chapter 11 seismic technology and law: partners or ... · chapter 11 seismic technology and law:...

Chapter 11

Seismic Technology and Law: Partnersor Adversaries?1

By Owen L. AndersonUniversity of Oklahoma College of Law

Norman, Oklahoma

Dr. John D. Pigott2

University of Oklahoma School of Geology and GeophysicsNorman, Oklahoma

SynopsisPart 1 by Dr. John Pigott

§ 11.01. Introduction: Posing the Problem ..............................287§ 11.02. How 3D Seismic Works, How It Differs from 2D

and What It Tells Us ....................................................293[1] — Seismic Fundamentals ..................................................... 294

[a] — Ray Path Characteristics (Snell’s Law) .................. 296[b] — Waveform Characteristics ...................................... 297[c] — Velocities of Rocks, Fluids and Gases ................... 299[d] — Statics and Dynamic Corrections ........................... 302[e] — Migration ................................................................ 303[f] — Noise: Coherent vs. Non-coherent .......................... 306

1 © Owen L. Anderson and Dr. John D. Pigott. This article updates previously publishedarticles: Owen L. Anderson, “Geophysical ‘Trespass’ Revisited,” 5 Tex. Wesleyan. L.Rev. 137 (1999) and Owen L. Anderson and Dr. John D. Pigott, “3D Seismic Technology:Its Uses, Limits, & Legal Ramifications,” 42 Rocky Mt. Min. L. Inst. 16-1 (1996). ProfessorPigott prepared Part 1 of the article and Professor Anderson prepared Part 2.2 Professor Anderson is the Eugene Kuntz Chair in Oil, Gas & Natural Resources atThe University of Oklahoma College of Law and a consultant in domestic and internationalnatural resources and energy law. He is licensed to practice law in North Dakota,Oklahoma, and Texas. Dr. Pigott is Associate Professor of Geophysics at The Universityof Oklahoma School of Geology and Geophysics and an energy consultant for governmentsand energy companies world-wide. The authors thank Dr. Christopher Kulander, M.S.,Wright State University, and Ph.D., Texas A&M University, in Geophysics and law student,The University of Oklahoma, for his research assistance.

CITE AS24 Energy & Min. L. Inst. ch. 11 (2004)

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[2] — Acquisition ....................................................................... 307[a] — Speculation v. Proprietary ...................................... 307[b] — Land Sources, Receivers and Geometries .............. 308[c] — Marine Sources, Receivers and Geometries ........... 310[d] — Exploration ............................................................. 311[e] — Development ........................................................... 311[f] — Costs ....................................................................... 312

[3] — Processing and Reprocessing ........................................... 313[a] — Cosmetic vs. Scientific Philosophy

of Noise Reduction ................................................. 313[b] — General Noise Suppression and

Image-Enhancing Techniques ................................ 314[c] — AVO and Attributes ................................................. 315[d] — Exploration ............................................................. 317[e] — Development ........................................................... 319[f] — Costs ........................................................................ 319

[4] — Interpretation .................................................................... 320[a] — Conventional Seismic Interpretation ...................... 320[b] — Seismic Stratigraphic Interpretation ...................... 321[c] — DHIs and Reservoir Characterization .................... 323[d] — Modeling and Iterative

Reprocessing-Reinterpretation ............................... 324[e] — 4D Seismic Method (Time-Lapse Imagery) .......... 325[f] — Costs ........................................................................ 325

[5] — Limits and Errors ............................................................. 326[a] — Acquisition .............................................................. 326[b] — Processing ............................................................... 328[c] — Interpretation .......................................................... 330[d] — Vertical Resolution ................................................. 330[e] — Horizontal Resolution............................................. 332[f] — Signal-to-Noise Ratio ............................................. 333

[6] — Conclusion: The 3D Seismic Advantage ........................ 334

Part 2 by Professor Owen L. Anderson§ 11.03. 3D Seismic Data as Evidence................................................. 336§ 11.04. Geophysical “Trespass” ......................................................... 346

[1] — The Right to Explore Is a Valuable Property Right ......... 348[2] — Causes of Action for Protecting the Right

to Explore ........................................................................ 349[3] — Who Owns the Right to Explore? .................................... 354

[a] — Severed Mineral Interests ....................................... 354[b] — Surface-Related Exploration .................................. 357

SYNOPSIS

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SEISMIC TECHNOLOGY AND LAW

[c] — Minerals Owned in Cotenancy ............................... 362[d] — Minerals Owned in Succession .............................. 374[e] — Mineral Ownership Divided By Depth .................. 375[f] — Mineral Ownership Divided By Substance ............ 376[g] — Minerals Under Lease or Other Agreement ........... 378[h] — The Exploration of Adjacent and Nearby

Tracts—(and Brief Sidebar on AerialSurveying) .............................................................. 382

[i] — The Basic Problem ................................ 382[ii] — Assumpsit ............................................. 385[iii] — Loss of Speculative Value ................... 385[iv] — Trade Secrets ....................................... 387[v] — The Related Problem

of Aerial Surveys .................................. 390[vi] — Misappropriation ................................. 393[vii] — Our “Modest Proposal” ...................... 394

[i] — Measure of Damages for ActionableGeophysical “Trespass” ......................................... 404

§ 11.05. Surface-Use Limitations on the Right to Explore .............. 409§ 11.06. Conclusion .............................................................................. 415§ 11.07. Appendix: Figures ................................................................ 418

Part 1§11.01. Introduction: Posing the Problem.

During the past three decades, reflection seismic3 technology hasrevolutionized the way people look at the earth, be it for academic studyof the Earth or for the profitable extraction of its energy resources. Thereare two methods: one is termed 2D seismic (for two-dimensional) and isthe classic approach, and the newer is termed 3D seismic (for three-dimensional). They are both powerful non-invasive (without drilling)methods for imaging the makeup of the earth much as one non-invasively(without surgery) images the human body using contemporary medicaltechnology. Indeed, the quality of the image may be stated that 2D seismic

3 While properly an adjective, we will occasionally use the term “seismic” as a noun.While seismic is not properly used as a noun, personnel in the oil and gas industrycommonly use the term as both a noun and an adjective.

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is to an x-ray two dimensional photo as 3D seismic is to a CAT-scan ofthe body’s volume. In particular, the recent advances in seismic technology(specifically the 3D method) have been so powerful that they have changedthe very way the petroleum industry conducts exploration and exploitation,and in the very way it thinks.

The yearly increase in 3D seismic data collection has acceleratedto the point that this wonderful new technology has significantlydropped the price per barrel to find oil. It has also resulted insurprising increases in the production of oil from existing fields.Perhaps the solution to the impending push to get more oil tomarket, faster, will come not from increased exploration success,but from new uses of 3D seismic data that maximize recoveryefficiencies from existing oil and gas fields.4

Not surprisingly, as the use of 3D seismic technology expands andbecomes routine within the industry, the value of seismic technology as alegal tool increasingly becomes of interest. But what exactly does thisnew technology offer? And what are some of its legal ramifications forresolving, as well as potentially causing, legal problems? That is, is theseismic method a protagonist or an antagonist of the law? For example,although the 3D seismic technique differs from 2D in providing muchgreater information with higher resolution, for proper subsurface imaging,3D seismic acquisition design commonly requires it to be shot at distanceswell beyond the actual surface dimensions of the subsurface target, raisingas never before potential trespass questions that extend beyond the targetedsubsurface region.

We shall address these questions essentially in two parts: a technicalsummary followed by a legal discussion. The technical discussion can beused in two ways: for the casual reader, a quick reading of each subsectionto gain a general understanding of the steps necessary to obtain accurateseismic information, or for the reader who desires to know more technical

4 Wei He, et al.,“4D Seismic Monitoring Grows as Production Tool,” Oil & Gas J.,May 20, 1996, at 41 [hereafter He].

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information, a careful study of the text followed by further study of thecited sources for detailed information.5 The legal discussion focuses onthree matters: (1) the potential relevance and use of 3D seismic data asevidence—a matter that is both exciting and, in some contexts,

5 For further information on the 3D seismic method, see: “Salaries Rise Along WithPrices,” American Association of Petroleum Geologists Explorer, 1996, vol 17, no. 5, p.10; J. L. Allen & C.P. Peddy, “Amplitutude Variation with Offset: Gulf Coast Case Studies,”Geophysical Development Series, v. 4, Society of Exploration Geophysicists, Tulsa, 126pp. (1993)[hereafter Allen & Peddy 1993]; M. Austin, J.D. Pigott, & J.M. Forgotson,“Seismic Stratigraphy of the Upper Pennsylvanian Swope Limestone of Kansas andOklahoma: An Integrated Approach to Thin Bed Reservoir Prediction,” GeophysicalSociety of Tulsa 1991 Spring Symposium, p. 73-84 (1991)[hereafter Austin et al. 1991];W. K. Aylor, “Business Performance and Value of Exploitation 3-D Seismic,” The LeadingEdge, vol. 14, no. 7, p. 797-801 (1995)[hereafter Aylor 1995]; M. E. Badley, PracticalSeismic Interpretation, Prentice-Hall, Englewood Cliffs, New Jersey, 266 pp.(1985)[hereafter Badley 1985]; M. A. Biot, “Theory of Propagation of Elastic Waves ina Fluid-Saturated Porous Solid, 1. Low Frequency Range, 2. Higher Frequency Range,”Accoustical Society of America Journal, v. 28, p. 168- 191 (1956)[hereafter Biot 1956];J. D. Boudvier, C.H. Kaars-Sijpesteijn, D.F. Kluesner, C.C. Onyejekwe, & R.C. van derPal, “Three-Dimensional Seismic Interpretation and Fault Sealing Investigations, NunRiver Field, Nigeria,” American Association of Petroleum Geologists Bulletin, 73, No.11, p. 1397-1414 (1992)[hereafter Boudvier et al. 1992]; J. Brac, P.Y. Dequirez, F. Herve,C. Jacques, P. Lai11y, V. Richard, & D.T. van Nhieu, “Inversion With A Priori Information:An Approach to Integrated Stratigraphic Interpretation,” in R.E. Sheriff, ed., ReservoirGeophysics, Investigations in #7, Society of Exploration Geophysicists, Tulsa, p. 251-284 (1992)[hereafter Brac et al. 1992]; A. R. Brown, “Interpretation of 3-DimensionalSeismic Data,” 3d ed., American Association of Petroleum Geologists Memoir 42, Tulsa,341 pp. (1991)[hereafter Brown 1991]; B. S. Byun, Velocity Analysis of MultichannelSeismic Data, Society of Exploration Geophysicists, Tulsa, 518 pp. (1990)[hereafter Byun1990]; J. P. Castagna & M.M. Backus, “Offset-Dependent Reflectivity–Theory andPractice of AVO Analysis,” Investigatons in Geophysics #8, Society of ExplorationGeophysicists, Tulsa, 348 pp. (1993)[hereafter Castagna & Backus 1993]; S. N. Domenico,“Effect of Brine-Gas Mixture Velocity in an Unconsolidated Sand Reservoir,” Geophysics,v. 41, p. 882-894 (1976)[hereafter Domenico 1976]; Stuart W. Fagin, Seismic Modelingof Geologic Structures, Applications to Exploration Problems, Geophysical DevelopmentSeries, v. 2, Society of Exploration Geophysicists, Tulsa, 269 pp. (1991)[hereafter Fagin1991]; M.R. Gadallah, Reservoir Seismology, Penn Well Books, 384 pp. (1994)[hereafterGadallah 1994]; G.H.F. Gardner, Migration of Seismic Data, Geophysical Reprint Series,#4, Society of Exploration Geophysicists, Tulsa, 462 pp. (1985)[hereafter Gardner 1985];R.J. Greaves & T.J. Fu1p, “Three-Dimensional Seismic Monitoring of an Enhanced OilRecovery Process,” Geophysics, v. 52, p. 1175-1187 (1987)[hereafter Greaves & Fu1p1987]; A.R. Gregory, “Aspects of Rock Physics From Laboratory and Log Data That Are

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troublesome; (2) a new look at the thorny issue of geophysical “trespass”—a matter that is more thorny with 3D seismic data due to the necessity ofimaging structure from adjacent lands; and (3) a quick reprise of surfaceowner issues—a matter that is of greater concern with the 3D seismicmethod due to access issues and more intense surface use.

Important to Seismic Interpretation,” in Charles E. Payton, ed. Seismic Stratigraphy –Applications to Hydrocarbon Exploration, American Association of Petroleum Geologists,Tulsa, p. 15-46 (1977)[hereafter Gregory 1977]; J.P. Lindsey, “The Fresnel Zone and ItsInterpretive Significance,” The Leading Edge, Oct. 1989, p. 33-39 (1989)[hereafterLindsey 1989]; M.K. Jenyon & A.A. Fitch, Seismic Reflection Interpretation,Geoexploration Monographs 1, No.8, Gebruder Bomtraeger, Berlin, 318 pp.(1985)[hereafter Jenyon & Fitch 1985); R. McQuillin, M. Bacon, & W. Barclay, AnIntroduction to Seismic Interpretation, Graham & Trotman, London, 287 pp.(1984)[hereafter McQuillin et al. 1984]; R. M. Mitchum, Jr., P.R. Vail, & S. Thompson,III, “Seismic Stratigraphy and Global Changes of Sea Level, part 2: The DepositionalSequence as a Basic Unit for Stratigraphic Analysis,” in Charles E. Payton, ed. SeismicStratigraphy – Applications to Hydrocarbon Exploration, American Association ofPetroleum Geologists, Tulsa, p. 53-62 (1977)[Mitchum et al. 1977]; R. M. Mitchum, Jr.& P. R. Vail, “Seismic Stratigraphy and Global Changes of Sea Level, part 7: SeismicStratigraphic Interpretation Procedure,” in Charles E. Payton, ed. Seismic Stratigraphy– Applications to Hydrocarbon Exploration, American Association of PetroleumGeologists, Tulsa, p. 135-143 (1977)[Mitchum & Vail 1977]; A.M. Nur & Z. Wang,“Seismic and Acoustic Velocities in Reservoir Rocks,” v. 1, Experimental Studies, Societyof Exploration Geophysicists, Tulsa, 405 pp. (1988)[hereafter Nur & Wang 1988]; J. D.Pigott, R.K. Shrestha, & R.A. Warwick, “Young’s Modulus From AVO Inversion,” Societyof Exploration Geophysicists 59th Annual Meeting, v. 2, p. 832-835 (1989)[hereafterPigott et al. 1989]; J. D. Pigott, R.K. Shrestha, & R.A. Warwick, “Direct Determinationof Carbonate Reservoir Porosity and Pressure From AVO Inversion,” Society ofExploration Geophysicists 60th Annual Meeting, v. 2, p. 1533-1536 (1990)[hereafterPigott et al. 1990]; J. D. Pigott, Y. Wang, R.K. Shrestha, J. Forgotson, & J. McDonald,“Reservoir Characterization Using 3D AVO Inversion: Case Study – U.S. Gulf Coast,”Society of Exploration Geophysicists International Meeting, Beijing, P.R.C., p. 238-248(1993)[hereafter Pigott et al. 1993]; J. D. Pigott, “A Seismic Classification Scheme forClastic Wedges (Deltas)” Chapter 2, in M.N. Oti & G. Postma, eds., Geology of Deltas,A.A. Balkema Publishers, Rotterdam, p. 17-29 (1995)[hereafter Pigott 1995]; J. D. Pigott,& K. Feglo, “Optimizing Red Sea Imaging Through F-K Processing: Northern SudanExample,” Society of Exploration Geophysicists 66th Annual Meeting (1996)[hereafterPigott & Feglo 1996]; J. D. Pigott, & S.V. Tadepalli, “Direct Determination of ClasticReservoir Porosity and Pressure From AVO Inversion,” Society of ExplorationGeophysicists 66th Annual Meeting [hereafter Pigott & Tadepalli 1996]; J. G. Richardson& R.M. Sneider, “Synergism in Reservoir Management,” R.E. Sheriff, ed. ReservoirGeophysics: Investigations in Exploration Geophysics v. 7, Society of ExplorationGeophysicists, Tulsa, p. 6-11 (1992)[hereafter Richardson & Sneider 1992]; R. E. Sheriff,

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First, as a short review of just how significant the new 3D seismictechnology is at present, and how it differs from the 2D methods of thepast, one must first examine the classic makeup of a petroleum team, thepeople who search for oil and gas. It is geophysicists who use 3D seismictechnologies, together with geologists and engineers, who are the criticalcomponents of the integrated petroleum team.6 Today it would be

“Limits on Resolution of Seismic Reflections and Geologic Detail Derivable from Them,”in Charles E. Payton, ed. Seismic Stratigraphy – Applications to Hydrocarbon Exploration,American Association of Petroleum Geologists, Tulsa, p. 3-14 (1977)[hereafter Sheriff1977]; R. E. Sheriff, Enclyclopedic Dictionary of Exploration Geophysics, 3d Edition,Society of Exploration Geophysicists, Tulsa, 376 pp. (1991)[hereafter Sheriff 1991]; R.E. Sheriff, Reservoir Geophysics: Investigations in Exploration Geophysics, #7, 400 pp.(1992)[hereafter Sheriff 1992]; R. T. Shuey, “A Simplification of the Zoeppritz Equations,”Geophysics, v. 50, p. 609-64 (1985)[hereafter Shuey 1985]; M. T. Taner & R.E. Sheriff,“Application of Amplitude, Frequency, and Other Attributes to Stratigraphic andHydrocarbon Determination,” in Charles E. Payton, ed. Seismic Stratigraphy –Applications to Hydrocarbon Exploration, American Association of Petroleum Geologists,Tulsa, p. 301-327 (1977)[hereafter Taner & Sheriff 1977]; W. M. Teleford, L.P. GeldArt, & R.E. Sheriff, Applied Geophysics, 2nd Edition, Cambridge University Press,Cambridge, 770 pp. (1990)[hereafter Teleford et al. 1990]; P. R. Vail, R.M. Mitchum,Jr., & S. Thompson, III, “Seismic Stratigraphy and Global Changes of Sea Level, Part 3:Relative Changes of Sea Level From Coastal Onlap,” in Charles E. Payton, ed. SeismicStratigraphy – Applications to Hydrocarbon Exploration, American Association ofPetroleum Geologists, Tulsa, p.63-97 (1977)[hereafter Vail et al. 1977a]; P. R. Vail, R.G.Todd, & J.B. Sangree, “Seismic Stratigraphy and Global Changes of Sea Level, Part 5:Chronostratigraphic Significance of Seismic Reflections,” in Charles E. Payton, ed.Seismic Stratigraphy–Applications to Hydrocarbon Exploration, American Associationof Petroleum Geologists, Tulsa, p. 99-l33 (1977)[hereafter Vail et al. 1977b]; R. A.Warwick, & J.D. Pigott, “Interpretation of Lateral Variations in Carbonate Porosity byDetailed Stacking Velocity Analysis: Mississippian Bioherm Example, Hardeman Basin,Texas,” Estimation and Practical Use of Seismic Velocities, EAEG/SEG ResearchWorkshop, Cambridge, England, 460-469 (1990)[hereafter Warwick & Pigott 1990];M.R.J. Wyllie, A.R. Gregory, & L.W. Gardner, “Elastic Wave Velocities in Heterogeneousand Porous Media” Geophysics, v. 21: p. 41-70 (1956)[hereafter Wyllie et al. 1956]; O.Yilmaz, Seismic Data Processing, Investigations in Geophysics, v. 2, Society ofExploration Geophysicists, Tulsa, 526 pp. (1987)[hereafter YILMAZ 1987]; K. Zoeppritz,Erdbebenwellen VI/IB, “On the Reflection and Propagation of Seismic Waves,” GottingerNachrichten, I, p. 66-84 (1919)[hereafter Zoeppritz 1919].6 2 Peebler, R. P., 1996, “Extended Integration—The Key to Future Productivity Leap,”Oil & Gas J. May 20, 1996 at 57 [hereafter Peebler 1996].

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unthinkable to exclude geophysicists. However, the integration ofgeophysics with these other disciplines is a relatively recent development.Historically, there has been a lack of appreciation for seismic techniquesdue to (1) the inherent interpretational ambiguity of the forerunner 2D(two-dimensional) seismic analyses; (2) the costly mistakes ininterpretations as a result of having to make interpolations; and (3) theearly lack of suitable computers to conduct the enormous amount ofnumber crunching required to clearly and accurately image the subsurfacein three dimensions. All of this changed in the 1970s, first with thetheoretical 3D seismic studies in the first part of the decade,7 and thenwith the parallel development of more substantial mainframe computersin the second half of the decade, which led to the 3D seismic method’spractical deployment.8 With improved global positioning technology inthe 1980s, the use of 3D seismic technology expanded from the onshoreto the offshore. By the 1990s, the 3D seismic method was replacing thetwo dimensional (2D) seismic method as the preferred geophysical tool.

Application of the 3D seismic method for imaging rocks, fluids, andtheir structures to their fullest geometrical extent has negated theextrapolation of data between 2D seismic lines and between wells. Figures1A and 1B (pp. 418-419) illustrate dramatically the difference ininformation content between these two seismic technologies. Figure 1Arepresents a structural contour map from the Gulf of Thailand interpretedfrom 2D seismic data, and Figure 1B shows the same area mapped from3D seismic data. Observe the revised interpretations of the faults, theirnumber and their orientation, and most importantly, observe how thesefaults can now be observed to compartmentalize the potential rockreservoirs. For example, observe that some wells, previously believed to

7 See Walton, G.G., 1972, “Three-Dimensional Seismic Method,” Geophysics, v. 37,p. 417-430 and French, W.S., 1974, “Two-Dimensional and Three-Dimensional Migrationof Model-Experiment Reflection Profiles,” Geophysics, v. 39, p. 265-277.8 See Bone, M.R., B.F. Giles, and E.R. Tegland, 1976, “3-D High Resolution DataCollection, Processing and Display,” paper presented at 46th SEG Meeting, Houston,Texas.

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be within the same unit, now can be shown to be separated by faultboundaries. An additional example of the power of visualizing thesubsurface through the interpretation of 3D seismic data is illustrated byFigures 2A and 2B (pp. 420-421). Figure 2A illustrates a 2D seismicdisplay from offshore Texas. Figure 2B is a 3D seismic horizontal sectionfrom the same area showing a buried meandering river channel, a geologicfeature that is significantly more challenging to find on Figure 2A withoutthe 3D method. These two examples illustrate only a few of the advantagesof imaging the subsurface in three dimensions. These and other 3D seismictechniques have exponentially added information to the seismicinterpreter’s practical portfolio of tools, allowing the geophysicist to nowbecome an integral part of the geological and engineering team for makingquantitative interpretations requisite for an effective and economicallyprudent field development strategy.

Presently, 3D seismic exploration and exploitation is a multimillion-dollar technology, no longer in the experimental stages of development.The method is used both offshore and onshore in a variety of regionsworldwide. Importantly, the 3D method promises to become the exclusiveseismic tool for future field development, allowing in some instances theability to image snapshots of the extent and movement of reservoir fluidsthrough time (4D seismic), whereas previously reservoir drainage wasonly modeled and inferred from well production test data.

§ 11.02. How 3D Seismic Works, How It Differs from 2Dand What It Tells Us.

In this technical discussion, we follow a logical progression,commencing with an explanation of certain fundamentals of reflectionseismic theory, the acquisition of the seismic signal, the computer-intensiveprocedures of processing, the procedures of interpretation, and finally thepotential limits and errors of the technique. Since it is necessary tounderstand the 2D Seismic method in order to fully comprehend thedifferences of 3D, the presentation will be directed toward an informednongeophysicist (with a cursory knowledge of petroleum geology) whodesires to understand both the 2D and 3D seismic methods with a minimumof technical language. Owing to the almost impossible task of summarizingan immense subject in a meaningful—yet abbreviated—fashion, the

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footnotes will refer the interested reader to more rigorous and detailedtreatment of the subject matter.9 The Appendix consists of severalillustrations included to assist the reader in visualizing our technicaldiscussion.

[1] — Seismic Fundamentals.A seismic line is made up of a collection of seismic traces (Figures

3A and 3B, p. 422) which are displayed in two-way time in the verticaldimension and in distance in the horizontal dimension. To understandand use the information represented by these traces, both individually(wavelet analysis) and in groups (stratigraphic analysis), we mustunderstand certain fundamentals of the seismic method.

There are three main components to the seismic method, whether 2Dor 3D: acquisition, processing, and interpretation. Consider the followingexample. If during a thunderstorm, a lightning discharge strikes the ground,this electrical discharge and the resulting blast of sound represents anacquisition phase. If an observer first sees the lightning and then a fewmoments later hears the thundering response, the thunder and itsreverberations can be mentally connected to the lightning, in effectprocessing the information. If the observer then interprets this thunder assuggesting an approaching storm, the final part of the seismic method hasbeen performed.

Now, let us examine this event a little closer. The observer sees thelightning before hearing the thunder due to the comparative differencesin velocities of the transmission of light and sound through air—almostinstantaneously for light, but only about 1100 feet per second for air. Bycounting the time in seconds between when one sees the flash and whenone first hears the thunder and multiplying by 1100, the observer roughly

9 For additional study of seismic in general, see the geophysical dictionary Sheriff1991, supra note 3; for general treatment of geophysics theory, see Telford et al. 1990,supra note 3; for practical application, see Gadallah 1994, supra note 3; for interpretation,see Badley 1985, supra note 3. For 3D seismic in particular, for processing, see Yilmaz1987, supra note 3; for interpretation, see Brown 1991, supra note 3; and for applicationcase histories, see Sheriff 1992, supra note 3.

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can measure the distance to the lightning strike in feet. This time-distanceequation, used for the arrival of the thunder (sound), is the basic formulaused to measure the distance that sound travels through rock for directseismic arrivals:

Equation 1: d = (v*t)Here, d represents distance (feet) which is equal to v, the velocity of

sound (feet per second), multiplied by t, the elapsed time (in seconds).In actual seismic operations, however, the sound travels downward

into the ground and reflects off of strata (reflectors) back to the surface,creating an echo. Thus, in seismic, one measures two-way travel time.Consider the subsequent reverberations of thunder one often hears after asingle lightning strike. These reverberations are due to the thunder’sechoing off of reflecting surfaces (reflectors). This reflection varies withthe available reflectors. For example, thunder echoes much longer andlouder in a rocky, mountainous canyon than it does at sea or along a sandyocean beach. If thunder echoes or reverberates off of a canyon wall at anequivalent distance as an observer is from the source of the lightning, theobserver would hear the echo of the thunder at twice the time as it originallywas heard. Then, the observer could also calculate the distance to thelightning from the echo (reflection) as follows:

Equation 2: d = (v * T)/2Here, T equals two-way time (in seconds). This formula is the

conventional two-way travel time equation for sound used in reflectionseismic to measure distance or depth to a particular reflector. In otherwords, for a defined sound pathway (making corrections for surfacetopography and velocity variations), by knowing the average velocity ofthe path of the sound and the time delay between the source and recordedsignal, one can determine the depth from the surface to a particular reflector(reflecting surface). This relationship is fundamental to depthdeterminations for both the 2D and 3D seismic methods. However, owingto its geometrically increased sampling area of subsurface velocities,10

the 3D seismic method can provide a more accurate subsurface depthdetermination than 2D.

10 See infra § 11.02[1][c].

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[a] — Ray Path Characteristics (Snell’s Law).When one creates an acoustic disturbance on the earth’s surface by

causing a large sound, that sound travels or propagates through surroundingmaterials, be it air, water, or rock, in a manner that can be understood andmeasured by looking at this propagation either as a direct ray or as awaveform. Let us first examine its ray characteristics as a 1D (one-dimensional) approximation.

Consider a flashlight shining a beam of light on the surface of a pond(Figure 4, p. 423). The reflection angle for the light is exactly equal to itsincoming (incidence) angle, and its transmission below the water surfaceis a function of this angle and of the differences between the velocities oflight traveling through the two media (air and water). This relationship isknown as Snell’s law, i.e., the angle of incidence equals the angle ofreflection and the angle of the changed direction of the transmitted ray, orangle of refraction, is related to the angle of incidence and to the differencesin the velocities of the two media. This relationship is defined as:

Equation 3: (V1) * (sin Θ2 ) = (V2 ) * (sin Θ1)Here, Θ1

is the angle of incidence, Θ2 is the angle of refraction, V1 isthe velocity of the upper medium, and V2

is the velocity of lower medium(Figure 4). This relationship describes why a partially submerged straightpencil appears bent in a glass of water.

Examination of Equation 3 also explains why, if one’s angle of viewis too tangential to the horizontal surface of the water of a pond, onecannot see the bottom no matter how shallow the pond. Rather, one canonly see to surface of the water. No transmission occurs if the reflectionangle is too great, that is if the angle of refraction is 90 degrees or greater.This reflection angle is termed the critical angle. With reference to seismic,this shows that there is a limit to the angle (called the offset angle) thatone can use and still obtain selected subsurface reflections. Beyond thisangle, the rays do not continue to penetrate the layers but instead arecritically refracted along the interface and emerge as headwaves.

Although sound does not purely propagate as a single ray as describedby this 1D example, but more correctly as a 2D series of waveforms withever widening ripples. such as those formed by a pebble tossed into apond, sound’s propagation can be still be treated as a ray approximationby visualizing ray directions perpendicular to a front of wave ripples

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(Figure 5, p. 424). For an analogous 3D model, consider a candle in adarkened room exhibiting an ever-widening sphere of light. Thus, in the3D sense, the equation is equally valid.

[b] — Waveform Characteristics.Seismic signals of sound can also be usefully described as an

oscillating waveform—a periodic propagation which varies its intensitythrough time and space, with a measurable frequency and amplitude. Thegeneral relationship which links these parameters for sound, as well asfor any waveform, may be described spatially as

Equation 4: v = f * lHere, v represents the velocity of sound as it travels through a particular

medium. This velocity equals f (the sound’s frequency in hertz—cyclesper second) multiplied by l (lambda, the sound’s wavelength—the spatialdistance between peaks or troughs in the waveform). If describing awaveform in time instead of space, in lieu of describing the distancebetween wave crests or troughs in meters or feet, one would measure theperiod, or the number of seconds per cycle (the reciprocal of frequency).

In a 1D sense, a seismic waveform (Figure 6, p. 425) can be comparedto a vibrating string which illustrates amplitude by the displacement ofthe string’s peaks and troughs from its central axis and illustrateswavelength as the distance between these peaks or troughs. The rate atwhich each wave train moves along the string segment is the frequency.In a 2D sense, one could visualize the surface of a pond rippled by thewind.

In a 3D sense, one could imagine a large python which had swalloweda number of billiard balls. The diameter of the python at the position ofeach billiard ball would be the peak amplitude, midway between eachball would be the trough amplitude, and the distance between the ballswould be the wavelength. The rate at which the balls would be passingthrough the python would be the frequency.

Sound also varies in its amplitude through time. Returning to ourexample of the thunder reverberating from canyon walls, we may observethat sound is better echoed from barren rocky walls than from walls coveredby soil and vegetation. The loudness of the echo is a function of thereflectivity of the interface between two juxtaposed media—in this case,

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the air and the canyon wall. In seismic terms, we describe this reflectivityat the interface between the first transmitting medium and a secondarymedium as being proportional to the differences in the density and velocityproducts (or acoustic impedances) of the two media. This amplituderelationship is defined as the Reflection Coefficient (RC), which strictlyapplies only under the assumption of normal (vertical) incidence. This isillustrated for two horizontally bedded layers (layer 1 on top and layer 2on bottom), as follows:

Equation 5: RC = [(?2 * V2) – (?1 * V1)] / [(?2* V2) + (?1 * V1)]Here, ?1 represents the density of the first layer, ?2

the density of thesecond layer, V1 the velocity of the first layer, and V2 the velocity of thesecond layer. As is schematically illustrated in Figure 7 (p. 426), if theproduct of the density and the velocity of the second layer (the acousticimpedance) is higher than the product of the density and velocity of thefirst layer (e.g., a shale over a sand in the shallow subsurface), then thereflection coefficient will be positive. If lower, the reflection coefficientwill be negative (e.g., a gas-filled sand beneath a tight shale). Thus, thesedifferences in acoustic impedance yield differing reflection coefficientsexpressed as relative differences in amplitude peaks and troughs of theseismic traces as they cross the boundary between each layer. Both 2Dand 3D seismic have this potentially useful information within theirwavelet amplitudes. This information is also useful in determining a rock’slithology (composition or type) and fluid content. Specifically, theamplitude information potentially can describe the nature of the fluid, theaverage lithology of the rock, the effective pressure, the average porosity(the volume of the pore spaces in the rock), the net feet of pay, and, insome cases, the gas/oil ratio (GOR).11 Owing to the importance ofamplitude information, special care must be taken during processing toensure that it is not corrupted.12

11 The gas/oil ratio is the amount of gas (usually in thousand cubic feet) per barrel ofoil present in a particular location within a reservoir.12 See infra § 11.02[5][b].

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[c] — Velocities of Rocks, Fluids and Gases.When a geophysicist speaks of the velocity of a particular rock, the

geophysicist is describing the velocity at which sound travels throughthat rock, not the rate at which the rock moves past a stationary point. Byknowing the different velocities at which sound travels through differentrocks, the geophysicist can predict, in part, what the reflection coefficients(Equation 5) and resultant seismic amplitudes for differing lithologiesshould be. The compressional (P-wave) velocities and densities for aselected variety of naturally occurring geological materials composed ofvarying mineralogical compositions, porosities, and fluid content areshown below:13

Material Velocity Range Density Range(ft per sec) (gram per cm3)

Sand 3,000-12,000 1.6 - 2.4

Sandstone 5,500-19,000 2.0 - 2.6

Clay 4,500-6,000 1.9 - 2.4

Shale 5,000-16,000 2.0 - 2.6

Limestone 11,000-20,000 2.0 - 2.7

Dolomite 15,000-23,000 2.1 - 2.8

Salt 14,000-16,000 1.9 - 2.2

Granite 16,000-20,000 2.6 - 2.7

Air 1,100 0.00129

Methane 1,000-2,000 ~0.0007

Water 4,600-5,100 1 - 1.03

Oil 4,000-4,500 0.8 - 0.9

13 See Gregory 1977 and Telford et al. 1990, supra note 3.

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To understand why the seismic compressional wave velocities varyso much, especially with respect to rocks, as a first approximation, theamount of time required for sound to travel through a unit distance ofporous rock (transit time) is the sum of the time it takes to travel throughthe solid matrix plus the time it takes to travel through the fluid-filled (orthe gas-filled) pores:

Equation 6: t = [ ? * tf ] + [ (1 - ?) * tm ]Here, t is transit time, ? is porosity (or volume of fluid or gas ), 1 - ? is

what is left (the rock volume or solidity), tf the transit time of the fluid,and tm is the transit time of the matrix. Since interval velocity is thereciprocal of transit time, equation 6 can be similarly expressed in aformula known as the time average equation:14

Equation 7: 1/v = (pore filled fluid velocity)/ (?) + (matrix velocity)/(1 - ?)

Examination of either equation reveals that, as one adds more slow-velocity, fluid-filled porosity to a rock of a specific thickness, its totaltransit time from its top to its base lengthens, and, as a consequence, itsinterval velocity slows. This one factor is especially important, as it allowsgeophysicists to potentially tell what kinds of fluids a rock contains beforeone drills (especially gas). With variations in fluid content, brine-gas ratios,seismic frequencies, and lithologies, complications to the predictions ofthese simple formulas arise which require additional corrections15 in orderto optimize the accuracy desired for field development.

Average or bulk rock density is the second important parameter whichaffects the acoustic impedance (the product of the density and the velocity)of rocks and, ultimately, the reflection coefficients of their boundingsurfaces (Equation 5). Average or bulk rock density is calculated by theformula:

Equation 8: ?b = [? * ?f ] + [(1 – ?) * ?m]Here, ?b represents bulk density, ?f fluid density, ?m is matrix density,

and ? represents porosity. Since gases have lower densities than liquids,

14 See Wyllie et al. 1956, supra note 3.15 See Biot 1956; Domenico 1976; and compilation by Nur & Wang 1988, supra note3.

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inspection of Equation 8 reveals that gas-filled porous rocks would havelower densities than their liquid-filled counterparts. And since examinationof Equation 7 demonstrates that gas-filled rocks are slower than liquid-filled rocks, rocks with gas-filled porosity may be distinguished from rockswith fluid-filled porosity owing to the potentially substantial contrasts inacoustic impedance. This marked contrast in amplitude at the boundinginterface, as illustrated in Figure 8 (p. 427), is termed a seismic “brightspot”—so named because of its bright or enhanced amplitude valueobserved on seismic relative to the less amplified responses of adjacentreflectors. For example, a typical sedimentary rock layer may have areflection coefficient of 5 percent compared to a bright spot of perhaps 20percent. As such, a bright spot’s occurrence is so dramatic and so frequentlyattributed to hydrocarbons that it is included under the category of DirectHydrocarbon Indicators (DHIs).16

For completeness, note that there are several types of seismicvelocities, each deserving of its own discussion. However, the mostsignificant for our review are these four: interval velocity (defined by theprevious example); stacking velocity (velocity required to stack or averagea number of time grouped traces of a common mid point ((CMP)) gatherinto a coherent time shifted singular trace); Dix velocity (an approximationto the interval velocity using stacking velocities and a binomially derivedequation); and average velocity (the velocity from the surface to thereflector which averages all the interval velocities).17

Velocity analysis for the 3D seismic method differs from 2D. In 2Dseismic practice, stacking velocity is determined only from the hyperbolicmoveout of reflectors in a CMP gather. In 3D seismic, stacking velocitiesare represented as a velocity ellipse which includes velocities in directionsother than the shooting direction.18 In this manner, velocity informationfor 3D seismic practice and ultimately the accuracy of the resulting depthcalculations are greatly improved.

16 See infra § 11.02[4][d].17 Although a desire for brevity does not allow further discussion, the interested readercan obtain a greater detail from Byun’s compilation of the classic papers on seismicvelocities. See Byun 1990, supra note 3.18 See Yilmaz 1987, supra note 3.

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To conclude, velocity is one major seismic parameter, the accuracyof which helps make the most accurate seismic image both in time and,ultimately, in depth. Both 2D and 3D require accurate velocity informationfor the resulting images, depth calculations, and in some detailed studies,for the direct detection of hydrocarbon-filled porosity.19

[d] — Statics and Dynamic Corrections.In order to obtain the most accurate velocities and thus the most

accurate calculated depths of reflecting subsurface strata, two types ofcorrections must be applied to the reflection times: static and dynamic. Astatic correction applies a fixed-time correction to the seismic trace whereasa dynamic correction applies a time-variant correction. Figure 9 (p. 428)illustrates a static correction. Assume that seismic operations image aseries of horizontally bedded strata from an overlying topographic surfacethat varies from a valley to a hill to a valley. The two-way time to andfrom the stratal reflectors will vary sympathetically with respect to theterrain, producing an image of a subsurface positive structure (anticline)which does not exist. In other words, the surface topography distorts thetrue structure of the subsurface reflectors and must be corrected. The goalis to correct the seismic data as though the data were acquired along a flatsurface. In this way, any observed subsurface structures would be real,not artificial. Statics problems can be solved by application of elevation,refraction, and residual statics techniques.20

The major dynamic correction is the application of normal moveoutor NMO. Consider Figure 9 once again. When a flat subsurface stratalreflector is imaged along a flat topographic surface, the reflector will appearas concave strata bent downward, because the time of each ray path willincrease with the increasing offset from a central or common mid point(CMP) along the seismic line. This must be corrected to reveal the trueflat shape of the reflector by applying a specific spatially-varying amountof time shift which moves out the traces to their proper position. By

19 See Warwick and Pigott 1990, supra note 3.20 For more detail see Gadallah 1994, supra note 3.

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applying this NMO correction, the traces can later be correctly averagedtogether both to lessen random noise and to provide a more coherent imageof the reflector. Moreover, NMO provides a stacking velocity which canbe used to compute the Dix velocity21 and, subsequently, the depth of thereflector.

Both the 2D and 3D seismic methods benefit from static and dynamiccorrections. However, just as for velocity analyses, the geometricaladvantages of 3D seismic over 2D seismic procedures greatly augmentthe accuracy of the static and dynamic corrections, and with equivalentfold,22 can potentially yield a clearer subsurface image.

[e] — Migration.To properly view a subsurface event in time and ultimately in space,

techniques which migrate the image to its proper position must be applied.As a 2D seismic example, consider once again the pencil in a glass ofwater. In order for an above-water observer to correctly know the positionof the pencil, the vertical depth of the pencil beneath the water’s surfacemust be determined using the water’s velocity. This information mustthen be geometrically translated horizontally as well. If done correctly,the pencil image may be correctly positioned. In seismic, these samemigration tasks must be performed. First time migration determines anevent’s proper horizontal position in two-way time. Then depth migrationconverts this information to its proper depth relationship. Although seismicmigration methods are many and varied and, in some cases, costly in bothmoney and computational time, all methods pale in comparison to thespeed and accuracy of a heron in the precise mental-eye coordinated effortof time-depth migration that it routinely and instinctively uses to catchfish beneath the surface of a pond.

Owing to the rather involved mathematics of seismic migration, thecomputer techniques used are not easily summarized or madeunderstandable in only a few sentences. Instead, we shall briefly list and

21 See supra § 11.02[1][c].22 See infra § 11.02[2][b].

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tersely describe those that are currently in use for both the 2D and 3Dseismic method.23 Principal seismic migration methods are FiniteDifference, F-K, Kirchoff, and Depth. Finite difference is the mostcomputational and thus most time-consuming method. It uses the waveequation and performs well under low signal-to-noise ratios,24 but poorlyin the presence of steeply dipping beds. F-K migration is another variantof applying the wave equation. Its advantages are rapid computing timeand ease of migrating steeply dipping beds. Unfortunately, the F-K methodperforms poorly when there are lateral variations in velocities, such asthose produced by changes in ancient depositional environments andchanging lithologies. The Kirchoff method of diffraction (bending of waveenergy around objects) is statistical in its approach, summing amplitudesalong the bent hyperbolic wave pathways in order to perform migration.Though advantageous in steeply dipping settings, the Kirchoff methodunfortunately performs badly when there is much noise. Taken as a toolboxof possibilities, migration techniques offer more than one method inattacking a particular problem, and when employed properly can providesignificant benefit in not just portraying a better image, but in placingdata in their proper position.25

Although the preceding techniques have their advantages anddisadvantages in migrating features in time, depth migration best solvesthe problems of lateral variations in bed velocities and provides the mostaccurately positioned section, both vertically and horizontally. Alltechniques of migration are most powerful when used prior to stackingthe seismic line—that is, in the pre-stack stage of processing; however,the cost in time and money in performing pre-stack migration is muchgreater than post-stack migration.

23 For deeper study, the reader is advised of the excellent reviews of migration byGardner 1985 and Yilmaz 1987, supra note 3.24 See infra § 11.02[5][f].25 For application example, see Ibrahim, Abdelazim, and John D. Pigott, 1998, Post-stack model-guided seismic imaging and interpretation of salt and subsalt structures,Egyptian Red Sea, in Africa/Middle East Second International Geophysical Conference& Exposition, Cairo, Egypt, 17-19 February, p. 56-57.

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In terms of power and clarity, migration immediately distinguishes3D seismic from 2D. Because the seismic waveform expands with depthand, hence, detects images beyond those directly beneath the line, a “side-swipe” occurs,26 which can be diminished by migration. However,migrated 2D seismic lines may not tie. Before migration, two perpendicular2D seismic lines could be matched reflector by reflector, wavelet bywavelet, at their point of intersection; however, following migration, ifthere is a structural component inherent in the area, the lines will no longertie—that is they will not intersect properly in time. Accordingly,interpreters are left with a dilemma. They can either live with intersectingunmigrated 2D seismic lines which do not position subsurface events inthe correct position, or they can choose to work with migrated 2D lineswhich, although positioning events in an improved location, do not allowthe lines to tie or to be correlated with the subsurface geology in as rigorousa fashion as possible. By comparison, the 3D seismic method of depthmigration performed in two directions allows a perfect tie for correlationand for the correct positioning of subsurface events.

For proper migration, a 2D seismic shot line must be sufficiently longhorizontally (offset) and have a sufficient record length vertically in two-way time to properly position dipping events. If the 2D seismic line lengthor record length is insufficient to allow the reflection geometry to recordevents, an affected seismic section (i.e., the record made by a geophone)will portray no information—that is, it would be eventless and swampedwith noise. Unfortunately, the need to shoot beyond a target’s mappeddimensions is not as well appreciated for the 2D seismic technique as itshould be. For the 3D seismic method, this acquisition requirement isappreciated. The high cost of the 3D seismic practice requires theavoidance of eventless 3D seismic sections—hence, 3D seismic acquisitionis shot well beyond the actual surface dimensions of the target.

Restating this matter technically: to correctly record a dipping segmentof a subsurface reflector which, following migration, will be moved updip,steepened, and shortened, the 3D survey must extend beyond the actual

26 See infra § 11.02[5][e].

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dimensions of the structure (Figure 10, p. 429). This required spatialdimension is known as the migration aperture (MA):

Equation 9: MA = (1/2) * T * V * sin (?).Here, T represents two-way time, V is the average velocity to the

event, and ? is the dip angle of the strata.27

The importance of the application of the migration aperture can beillustrated as follows: Consider the top of a structural dome seismicallyimaged as a reflector at 3 seconds of two-way time, at an average velocityof 15,000 feet per second, and with a flanking dip angle of 20 degrees.Using Equation 9, the migration aperture is 7,695 feet. Therefore, if thisstructural dome were 5 miles by 5 miles, the surface acquisition or seismicgrid needed to accurately image the dome would have to extend at least7,695 feet beyond each side of the dome; in other words, the grid wouldhave to be approximately 8 miles by 8 miles. The need for larger seismicgrids presents significant legal ramifications owing to the law ofgeophysical “trespass.”28

[f] — Noise: Coherent vs. Non-coherent.Just as proper television reception depends upon the signal strength

in relationship to the surrounding noise, the quality of seismic images ofthe subsurface are similarly dependent upon the inherent noise. Two basickinds of noise corrupt the signal recorded by the seismic process: coherentand non-coherent. Coherent noise is periodic in time and/or space andthus can often be attenuated by application of periodic techniques whichfocus upon its predictability. For example, for a land seismic survey, a 60hertz electrical signal transmitted by nearby electrical power lines andinadvertently recorded by the seismic program can be removed by theapplication of a 60 hertz signal of exactly the opposite phase convolvedwith the seismic record.

In contrast, non-coherent or random noise in time or space commonlyrequires the use of periodic filtering techniques. For example, if

27 See Gadallah 1994, supra note 3.28 See infra § 11.04[3][h].

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automobiles passed noisily down a highway and near one particulargeophone29 during the seismic recording process, the resulting suddenand random signals could obscure the desired responses of the truereflectors. One method that can remove this non-coherent noise is to cutout that particular seismic section (geophone record) directly (digitally)at that particular time by the application of a surgical mute. Another lessdrastic procedure removes random noise by simply stacking during thecourse of processing of the seismic. Stacking may be described as anaveraging technique wherein each individual record (or field trace) is addedin its proper hyperbolic time and space (normal move out) and then dividedby the total number of records in the CMP gather (the collection of sortedtraces which correspond to one common midpoint of reflection). Instacking, only those events that occur at the same time on adjacent movedout traces (e.g., a true signal from a horizon) are reinforced, and the randomblips of noise are canceled out. In other words, if an event is persistentthrough time (i.e., the signal), it will tend to be strengthened above therandom events (i.e., the noise), and reducing non-coherent noise increasesthe signal-to-noise ratio.30

[2] — Acquisition.As previously stated,31 there are three major parts to the seismic

imaging method: acquisition, processing, and interpretation. All three areinterdependent, and in their most efficient application, this interdependencyis purposely exploited to iteratively improve the performance of each part.First, we shall examine seismic acquisition.

[a] — Speculative vs. Proprietary.New seismic data are acquired in two manners: a Speculative or

“Spec.” survey and a Proprietary survey. In a Spec. survey, a geophysicaloperator gathers seismic data over an area speculating that the seismic

29 For a discussion of acquisition design, see infra § 11.02[2][b].30 See infra § 11.02[5][t].31 See supra § 11.02[1].

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data will be non-exclusively licensed to various oil and gas explorationand production companies, thereby generating a profit. These future clientshave little control over the acquisition and processing of Spec. data. If, onthe other hand, a company wishes to acquire the seismic data for its ownprivate or “exclusive” use and wishes to custom design the parameters foracquisition and processing, it can purchase a “Proprietary” or “Exclusive”survey. In general, Proprietary data are substantially more expensive thanSpec. data because the tailoring of a Proprietary survey to a particularparty’s needs (e.g., the precise location, a design optimized for a particulartarget, etc.) is more costly and because the geophysical operator does notsell Proprietary data multiple times. Generally, offshore data are lessexpensive per kilometer of acquisition than onshore data.

Owing to the increased cost of 3D seismic acquisition whether bySpec. or Proprietary survey, the 3D seismic method is less commonlyutilized for pure exploration than the 2D seismic technique, which is oftenshot in very long regional lines with sparse intersections of infilling lines.However, when 3D seismic exploration is used, a sparse grid can beacquired with additional data being infilled by computer interpolation.Of course, the accuracy of computer interpolation will suffer if there arerapid changes in lithology or structure between the sampled data. However,if one can afford the Proprietary survey, such changes can be addressedand minimized by acquisition design.

[b] — Land Sources, Receivers and Geometries.The 2D seismic data are collected by setting up an array geometry of

sources and receivers optimally designed for particular geologicalconditions (e.g., structural dip, target depth, etc.). Onshore, the receiverlines with their attendant geophone groups are fixed and the sound source,be it explosives or Vibroseis,32 systematically move along a path in somedirection (often parallel at a fixed offset distance) to the receiver lines.

32 Vibroseis involves the use of a large hydraulically vibrating truck that generatesseismic energy. See Norman J. Hyne, Dictionary of Petroleum Exploration, Drilling &Production (1991)[hereafter Hyne].

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The source locations are termed shot points. A simplified planar view andsubsequent depth view of the resultant ray path of an in-line 2D survey isshown in Figure 11 (p. 430). In-line, star, split-spread are a few of theland 2D seismic acquisition arrays that are named in reference to how theshot and the receiver position arrays vary.

As previously discussed,33 during processing the stacking proceduresuppresses random noise within the traces from the CMP geophone groupsas they are added and averaged together. The number of common mid-point traces used in the stacking process is termed the number of fold (ormultiplicity).34 The number of fold may be calculated as follows:

Equation 10: Fold = [(number of receivers)*(receiver spacing)]/[2*(shotpoint spacing)]

Here, the number of receivers refers to the number of active geophonegroups, the receiver spacing is the distance between these groups, and theshotpoint spacing designates the distance between the positions wherethe sound source is activated. The higher the fold, generally, the greaterthe signal with respect to surrounding random noise. The lower the fold,the greater the noise.

The 3D seismic method of acquisition differs from 2D in both quantityand quality. Owing to the immense amount of data required for accurate3D seismic imaging, its acquisition commonly involves many times moresource points and receiver points than one 2D seismic line. As a 3Dprogram is commonly designed to image a particular subsurface target,its imaging capabilities are usually more focused. Bin35 size affects boththe quantity and quality of a survey. Although their ultimate size andpositioning can be estimated from pre-survey modeling, these binparameters can also be determined following acquisition in the processingstage. While bin size can vary, it generally ranges from a few hundred to

33 See supra § 11.02[1][f].34 See Hyne, supra note 30.35 Bins are the rectangular cells displayed on the shotpoint map that are primarilydesigned to collect sufficient CMP reflections that, after stacking, will yield an accurateimage of a particular subsurface feature.

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a few thousand square feet in areal size. The smaller the bin size, the finerthe resolution but the fewer the traces per CMP for image clarity. Thelarger the bin size, the coarser the resolution but the greater the fold forthe stack. In the 3D seismic method, fold is simply the number of tracesstacked within each bin, and can vary from bin to bin.

On land, 3D seismic data are usually acquired by swath shooting.The surface geometry of swath shooting involves laying out the receivercables parallel to each other (termed the in-line direction) and laying outthe shot lines, whether for Vibroseis or for explosives, perpendicular tothe receiver lines (termed the cross-line direction). However, shootingarrays can vary from inline, to L shaped, to cross patterns, or othergeometries.

Owing to the desire to minimize cost and optimize acquisition, 3Dacquisition is more often deliberately target-designed for development.36

This involves more intense surface use, which, in turn, can increase surface-owner anxieties. Moreover, as described in the subsection on migrationtheory,37 for the 3D seismic technique to image a target at depth commonlynecessitates the use of land and the acquisition of data from locationslateral to the targeted feature. Hence, for land 3D surveys, extensivepermitting is conducted to avoid claims of surface and geophysicaltrespass.38

[c] — Marine Sources, Receivers and Geometries.

Offshore, at water depths of 10 to 400 feet, seismic data can be acquiredthrough ocean bottom operations in a manner similar to land acquisition,by using stationary hydrophones along the ocean bottom and moving thesound source in the water column above. However, because of much greaterwater depths and of the high cost associated with the use of ocean-bottom

36 In contrast, 2D seismic, used primarily for exploration, is meant to image almosteverything from the surface to the basement to find targets with hydrocarbon potential.37 See supra § 11.02[1][e].38 For further discussion, see infra § 11.04[3][h].

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geophones, marine acquisition is most commonly conducted entirelywithin the water column. The sound source and receivers with fixed offsetdistances are transported by a streamer cable tethered behind a ship. Marinesound sources for both 2D and 3D seismic range from varieties of airgunsto waterguns to explosives. Although 2D seismic receivers (hydrophones)are connected to a single streamer cable, 3D seismic receivers arecommonly arranged through the use of multiple streamer cables towed inan en echelon array behind a ship. In contrast to the land acquisitionterminology, in the marine setting the direction of shooting is termed in-line whereas directions perpendicular to the acquisition direction is termedcross-line. Owing to changes in the ship’s trajectory as well as to watercurrent differences, the geometries of marine acquisition are much moredynamic and complex than land surveys and must be corrected bysophisticated global positioning systems and attendant software.Accordingly, bin sizes may be positioned and sized in order toaccommodate these complexities. Notwithstanding this geometriccomplexity, and even though, as with land, 3D data must be commonlyacquired from beyond the geographic boundaries of the target, there arefewer permitting problems associated with marine acquisition, ascompared to land acquisition.

[d] — Exploration.Permitting and acquisition are among the first major steps in the

seismic exploration process. In an ideal proprietary seismic survey,geologists, seismic interpreters, and seismic processors integrate their skillswith geophysical acquisition personnel. In this manner, a collectivelyinformed opinion can be developed about the proper and most efficientmanner to acquire, process, and interpret seismic data for particular targetsand depths. However, when seismic data are acquired through a Spec.survey, target-oriented acquisition from an integrated geoscientificstandpoint is generally not possible.

[e] — Development.For seismic acquisition to be useful for reservoir development,

reservoir engineers, with their knowledge of and concern for reservoirproperties, should be added to the team of geologists and geophysicists at

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the outset.39 Such integration not only optimizes the targeted seismicacquisition, processing, and interpretation, but, through sufficientcommunication and planning, the likelihood of making costly mistakes,in terms of both time and money, is minimized.

[f] — Costs.The costs of purchasing Speculative data have a large range, and

depend on the vintage (when the data was acquired and processed), itslocation, and the perceived value of the product at the time of interest.For example, some older data are almost free for the taking (available forthe costs of copying the data onto tapes) owing to the relative antiquity ofthe seismic technology employed (>20 years). Some newer Speculativedata require pre-survey advance costs whose amount are contingent uponthe numbers of participants and can be millions of dollars (e.g. the westcoast of Africa). Thus it is not possible to state a simple average or rangeon Speculative data prices.

However, though proprietary acquisition costs also vary considerably,they are more easily quantified as a product of the type of survey, location,topography, climatic conditions, size, client needs, and other factors. Thecosts for 2D and 3D seismic acquisition can be subdivided into four basicenvironments: land, transition (swampy land to shallow marine), marineocean bottom, and marine streamer (open water). For 2D seismicacquisition, prevailing land charges range from $3,000 to $12,000 permile (including $700 per mile for line clearing, and $1,500 per mile fordamage payments with the upper limit owing to heliportable drilling ifrequired). For the transition zone, the charges range from $10,000 to$30,000 per mile. For marine ocean bottom, charges range from $6,000to $10,000 per mile, and for marine streamer, charges range from $1,000to $2,500 per mile. Internationally, 2D seismic costs range for Vibroseisof $5,000 to $7,000 per kilometer and $12,000 to $30,000 per mile fordynamite, dependent upon remoteness, terrain, climate, etc. In foreignregions, the costs for 2D range from $5,000 to $7,000 per kilometer forVibroseis and from $12,000 to $30,000 kilometer for dynamite.

39 See Richardson & Sneider 1992, supra note 3.

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As 3D seismic technology continues to advance, costs decline towhere, in some instances, they are equivalent to the costs per mile for 2Ddata, and finding contractors who will acquire only 2D is becomingincreasingly difficult. Still, 3D seismic acquisition costs are usuallyconsiderably higher owing to the amount of data acquired and the laborinvolved. On land, acquisition charges range from $10,000 to $65,000per square mile, with the lower end for Vibroseis and the upper end fordynamite (owing to the increased costs of drilling the shot holes for thedynamite charges). In foreign areas, onshore 3D seismic acquisition pricesrange from $10,000 to $15,000 per square kilometer for Vibroseis,increasing to $18,000 to $50,000 per square kilometer for dynamite. Forthe transition zone, charges range from $50,000 to $80,000 per squaremile. Marine ocean bottom charges range from $25,000 to $50,000 persquare mile, and marine streamer charges range from $12,000 to $30,000per square mile.40 Similar to 2D, 3D seismic acquisition streamer chargesare the lowest since offshore operations are less labor intensive becausethere are fewer permitting problems, no surface damages are paid, and nolands are cleared. Costs for offshore 3D seismic (domestic and internationalwaters) range averages around $6,000 per square kilometer with an averageshoot of 1500 square kilometers.

[3] — Processing and Reprocessing.Processing follows acquisition in the seismic scheme. If processing

is repeated after interpretation, it is termed reprocessing. Of all of theseismic links to making an accurate subsurface image, processing is themost computationally intensive and, with respect to the 3D technique, themost time-consuming.

[a] — Cosmetic vs. Scientific Philosophy of NoiseReduction.

The two philosophies of seismic processing are metaphoricallycomparable to a physician’s treatment of a patient. One is cosmetic, in

40 These cost ranges are from the 1996 figures of a major international geophysicalcontracting company and revised with the information received March 2003 from severaladditional geophysical contracting companies.

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which, owing to the required economy of time and money, a “Band-Aid”is applied to rapidly treat and disguise a symptom. The results can beanywhere from fair to poor. On the other hand, if some effort is exerted tounderstand the physical cause of the symptom, the underlying cause canbe “cured” in a manner that will not mask other symptoms and, importantly,will not cause new ones to appear.

We have earlier described the seismic signal waveform as beingcomparable in behavior to the ripples that are generated when a stone isdropped into a pond.41 The amplitudes of these ripple-generated wavesdecrease with distance from their origin owing to their ever-wideningcircles (termed spherical divergence), to the imperfect elasticity of thewater (termed absorption), and to consequent reflection-generatingdisturbances along the shoreline (termed transmission loss and modeconversion). To infer the original splash amplitude from the ripple heights,one must restore their amplitudes by mathematically correcting foramplitude losses (termed true amplitude gain recovery). And just as wecan potentially interpret the momentum of the tossed pebble from theproduced ripples, we can seismically interpret the subsurface reflectioncoefficients (Equation 5) and the rock composition from the recordedseismic amplitudes. However, if in processing the signal, we take a shortcutby simply turning up the volume of the signal (termed data-dependentgaining) without a scientific consideration of how amplitude was lost inthe first place, we obtain an incorrect picture of the subsurface. In seismicprocessing, this amplitude problem is specifically addressed by trueamplitude gain recovery. Without it, seismic data can become worthlessfor stratigraphic interpretation, and worse yet, can misdirect a well location.Data-dependent gaining is cosmetic (a “Band-Aid”). True amplitude gainrecovery is noncosmetic (a “cure”).

[b] — General Noise Suppression and Image-Enhancing Techniques.

We previously described42 the two major types of noise: coherentand random. There exists a big proverbial tool box of tricks for attenuating

41 See supra § 11.02[2][b].42 See supra § 11.02[1][f].

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noise, ranging from drastic methods, such as surgically excising the noiseby killing the trace or portions of the trace, to coarse methods such aspredictive deconvolution (removing unwanted echoes), to comparativelymore gentle methods of removing certain noise components, such as F-Kdomain filtering (transferring the seismic data into a frequency and wavenumber domain where certain noise events are more evident and moreeasily removed) and velocity filtering. Yet the most robust and mostroutinely invoked method is stacking the data.43 In stacking, random eventsare diminished, but spatially and temporally continuous events (such asreflectors) are augmented. The by-products of stacking are greatlyenhanced image, velocity information, and ultimately, depth information.Within certain constraints, the general rule is the greater the fold,44 thegreater the robustness of this averaging technique is at removing randomnoise. Commonly, 2D has greater fold (48, 96, and in some rare cases upto 1000 traces averaged to make one) than 3D (with binned data commonlyaveraging 10 to 40 traces to make one line). Consequently, 3D seismicimages are usually not as crisp after stacking as 2D.

[c] — AVO and Attributes.AVO (amplitude variation with offset) is a seismic technique wherein

offsets (the distance between the sound source and receiver (geophone))are varied so that the source-to-receiver distance for a common midpoint(CMP) of a subsurface target is varied. This acquisition technique increasesthe angle for the ray path from vertical, so rather than simply being reflectedback to the geophones from the seismic source as the same kind of energy,a portion of the compressional waveform is converted into a new waveformtype, shear waves. The end result is that, with varying offsets, subsurfacereflectors can exhibit different compressional wave amplitude images asa function of varying rock-fluid compositions.

Technically, this variation of amplitude versus offset can be explainedby reinspection of the major assumption of Equation 5,45 which is thatthe Reflection Coefficient is strictly valid only for purely normal incidence.

43 See supra § 11.02[1][f].44 See supra § 11.02[2][b].45 See supra § 11.02[1][c].

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With increasing offset, seismic P-waves46 are converted into S-waves47

at differing rock-fluid interfaces as a function of the angle of incidence,the velocities, the densities, and the Poisson’s ratios48 of the materials(Figure 12, p. 431). Though the descriptive mathematical relationship issomewhat involved,49 it is easily adapted for computer solution.Importantly, from a practical standpoint, this mode conversion techniqueof extracting Poisson’s ratios (which can also be conducted by the directrecording of shear waves)50 may be used to differentiate particular rockproperties and the implied compositions which otherwise would beequivocally disguised in their stacked image. For example, this techniquecan differentiate a gas sand from a coal which might otherwise yieldindistinguishable stacked reflection coefficients.

Routine AVO application to differentiate bright spots51 (e.g., as eitherhydrocarbons or coals) involves either the forward modeling of geologyto fit an observed amplitude response (that is, making a fictitious geologicmodel as a first guess as to what the seismic response looks like) ornumerical inversion of the amplitude data (going directly from the seismicdata to a geological solution). AVO can also be used in some instances todetermine rock porosity and subsurface reservoir pressures (differential

46 P-waves or compressional waves are the wave used in standard seismic operations.They are acoustic and travel through a medium with the particles of the medium movingin the same direction as the wave propagation. See Hyne, supra note 30.47 S-waves or shear waves are body waves in which the motions of the particles areperpendicular to the direction of wave propagation. S-waves can be used to obtaininformation about the physical properties of strata. See Hyne, supra note 30.48 Poisson’s ratio is the measure of a substance’s “squeezability.” See Hyne, supranote 30.49 See Shuey & Zoeppritz 1919, supra note 3.50 See Sheriff 1992, supra note 3.51 A bright spot (see supra § 11.02[1][c]), caused by an abnormally large ReflectionCoefficient (RC)(supra § 11.02[1][b], is an intense seismic reflection, reflecting perhaps25 percent of seismic energy, rather than a typical 5 percent reflection. See Hyne, supranote 30.

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pressures) in both carbonate52 and clastic rocks.53 Because of its addedpower for hydrocarbon discrimination, the AVO technique is commonlyused in many 2D exploration applications;54 however, because of theintense computations required, its application to 3D problems requiressignificant computer assistance.55

Attribute analysis56 is an additional processing tool which, if usedproperly, can reveal quite dramatic changes in rock properties throughcolorful displays on seismic sections. When the entire seismic waveformis processed so that it can be analyzed in its complex real and imaginarymathematical components, certain attributes such as real polarity,instantaneous phase, and instantaneous frequency – to name a few – assistthe explorationist in finding seismic anomalies (seismic events which areunusual). When these anomalies are constrained with well control, theobservation of Direct Hydrocarbon Indicators (DHIs) may then be possible(Figure 8). Attribute analysis can be conducted for either the 2D or 3Dseismic technique. For the 3D seismic method, it has become an additionalinterpretive tool for reservoir development.57

[d] — Exploration.The recipes or algorithms for processing seismic are complex and

vary considerably. Rather than detail all of the required steps, we shall

52 See Pigott et al. 1989 and Pigott et al. 1990, supra note 3. Carbonate rocks, potentialreservoir rocks formed from CO3, include limestones and dolomites. See Hyne, supranote 30.53 See Pigott & Tadepalli in Press, supra note 3. Clastic rocks, potential reservoir rockscomposed of particles of other rocks that were broken down by weathering and thentransported by erosion, include sandstones, shales, siltstones, and conglomerates. SeeHyne, supra note 30.54 See Allen & Peddy 1993, supra note 3 and Castagna & Backus 1993, supra note 3.55 See Pigott et al. 1993, supra note 3. For reviews of AVO techniques, almostexclusively for 2D seismic, see Castagna & Backus 1993 and Allen & Peddy 1993, supranote 3.56 See Taner & Sheriff 1977, supra note 3.57 See Sheriff 1992, supra note 3.

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mention some of the most important ones.58 A typical 2D explorationprocessing sequence might be as follows: demultiplexing59 and optionalresampling of the data; muting first arrivals;60 true amplitude gainrecovery; application of static corrections, either deterministic or stochasticdeconvolution in the shot domain;61 filtering;62 sorting to the CMP domain;surface consistent deconvolution, filtering; velocity analysis and normalmoveout correction (NMO);63 selective AVO analysis;64 stacking;65

filtering; iterative statics; migration;66 and optional attribute analysis.67

The 3D processing problem is more complicated and computationallymore intensive than 2D processing because of its geometry and the numberof traces involved. Nevertheless, 3D processing techniques are similar to2D techniques, with a few exceptions. Following the shot domainprocesses, the 3D seismic method allows one the luxury of selecting andadapting particular bin sizes, locations,68 and geometries—that is, selectinghow many traces will eventually be stacked into a common midpoint gather(CMP). In addition, it is velocity control from three dimensions which,with depth migration, allows better depth control and more accuratepositioning of specific target Images.

58 For more information, see Yilmaz 1987, supra note 3.59 Demultiplexing is a process that separates individual seismic channels from thefield tape and reassembles the data corresponding to each detector onto an edit tape. SeeHyne, supra note 30.60 An arrival is the first appearance of a seismic event on a seismic display. See Hyne,supra note 30.61 Deconvolution, which results in clearer reflections, in a sense removes echoes andrecompresses the seismic impulse to remove noise added by the passage of the seismicwave through subsurface rock. See Hyne, supra note 30.62 Filtering discriminates between signal and noise based upon frequency and velocity.See Hyne, supra note 30.63 See supra § 11.02[1][d].64 See supra § 11.02[3][c].65 See supra § 11.02[1][f].66 See supra § 11.02[1][e].67 See supra § 11.02[1][c].68 See supra § 11.02[2][b].

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[e] — Development.For development or exploitation seismic, 2D processing would follow

a similar algorithm flow chart as for exploration but would differ principallyby the increased care conducted in the true amplitude gain recovery.Development processing is better at solving noise problems encounteredduring the exploration phase, as noise becomes more obvious andunderstandable after the first original processing and after well control isintegrated with the seismic, e.g., applying pre-stack migration, etc. Becausemuch 3D seismic is employed for development, it can be processed withgreater geologic control than if it were used solely for exploration.

[f] — Costs.Costs for computer processing of proprietary seismic survey data vary

depending upon the noise present and the kind of problems targeted.Present costs (March 2003), obtained from a survey of major internationalgeophysical contracting companies, may be subdivided into threecategories for both 2D and 3D processing. For 2D, onshore processingcosts range from $200 to $700 per mile, transition zone costs range from$3,000 to $10,000 per mile, and marine costs range from $200 to $500per mile. The costs vary with the kinds of seismic noise encountered andthe time it takes to provide the best subsurface image after removing ormitigating the noise.

A part of the cost is not just money, it is the time required forprocessing, and time is linearly proportional to the size of a 2D seismicsurvey area and exponentially proportional to the size of a 3D seismicsurvey area. For example, while a typical 2D project may be processed inone week, an equivalent area for a 3D project may require up to 10 weeksof processing time. In terms of money, the costs for 3D onshore are about$2,000 per square mile domestically and $750 per square kilometerinternationally. These prices drop for offshore and for onshore and offshoreare $740 and $450 per square kilometer, respectively. Although theincreased speed offered by new computer technology (e.g., parallelprocessing) in part lessens the time required for conventional processing,the concomitant increase in time required by new theoretical developments(e.g., pre-stack depth migration) in part offsets the time gained withadvanced computer technology.

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[4] — Interpretation.There are two methods for seismic interpretation. The first is the simple

correlation technique of a particular seismic horizon without regard to itsgeological meaning, termed “wiggle picking.” Such techniques are rapidand most useful for structural interpretations, such as mapping anticlinesand picking faults. In contrast, interpretation which incorporates thegeological information within the wavelet (e.g., lithology) and makes useof the implications of wavelet packages (e.g., depositional environments)is termed “seismic stratigraphy.”

[a] — Conventional Seismic Interpretation.Conventional seismic interpretation is mechanically driven.

Knowledge of the seismic wavelet’s phase and polarity is not emphasized.Instead, knowledge of what particular seismic reflector to interpret is allthat is required. One then simply traces that particular reflector on a seriesof seismic lines which intersect orthogonally in planar view, culminatingwith a product that correlates on every line. By correlating specific horizonson a seismic line, one may subsequently generate time data which, afterconversion to depth, help generate structural maps (maps which show thegeologic structure of a feature) and isochron or isopach maps (maps whichshow time or thickness of particular intervals, respectively). These mapsare useful in allowing the mapping of particular outlines and in determiningthe volumes of particular reservoir hydrocarbon accumulations.69 Themapped horizons may or may not be time significant, i.e., stratigraphicallycorrelatable. With integration of the seismic stratigraphic interpretationprocedure, conventional interpretation methods become more powerful.

The 3D interpretation method differs from 2D principally in twofundamental ways. First, the 3D seismic method has the ability to generate2D lines from a data volume in an almost unlimited number of directions,and is not restricted to only the in-line direction of shooting. Second, 3Dseismic surveys can generate time and horizon slices which cut the data

69 References which detail the methods and furnish numerous examples of casehistories involving conventional seismic interpretation techniques are McQuillin et al.1984, Jenyon & Fitch 1985, and Badley 1985, supra note 3.

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volume parallel to bedding surfaces, one of its chief interpretationadvantages. This extra degree of freedom, available for illustrating thesubsurface image, dramatically improves the ability of the interpreter tomap faults70 and other geometric structures71 which otherwise could onlybe interpolated from a 2D series of lines (recall Figures lA and IB). Nolonger must geologic data be inferred indirectly between 2D seismic lines– or even less accurately, interpreted from trend maps constructedexclusively from well control data.

[b] — Seismic Stratigraphic Interpretation.In comparison to the conventional non-stratigraphic method of

conventional seismic interpretation, seismic stratigraphy purposelyaddresses and incorporates the lithologic information, both of the rock-fluid type and of the rock geometries which are expressed, respectively,as the individual wavelet and as groups of wavelets.72 With respect togroups of wavelets, this stratigraphic technique of interpretation was firstdeveloped by Peter Vail and his colleagues at Exxon,73 and is now widelyused throughout the industry. It differs from “wiggle picking” in that onlyhorizons which have a time significance (i.e., chronostratigraphicalsignificance) are mapped. In so doing, one maps a geologically relevantsurface, not one that may cross time surfaces. In brief, the explorationmethod involves ten basic steps: First, one chooses a representative seismicline which, under ideal conditions, is regional, has geological well control,and has a known seismic wavelet interpretive phase and polarity. Second,one interprets the faults by their expressed sharp reflector discontinuities.Third, terminations of bed geometries are highlighted which are explicitlyexpressed as reflector terminations. Fourth, one interprets sequenceboundaries by connecting the terminations along synchronous reflectors.

70 See Boudvier et al. 1992, supra note 3.71 Dramatic and colorful examples of such interpretations are well illustrated in theclassic text by Brown 1991, supra note 3.72 See supra § 11.02[1][b].73 See, e.g., Mitchum et al. 1977; Mitchum & Vail 1977; Vail et al. 1977a; Vail et al.1977b, supra note 3.

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The lowermost sequence boundary indicates the top of the economicbasement, an important interpretation which allows the observation ofthe basement’s structural interdependency with the overlying strata. Fifth,a seismic facies analysis is conducted which, with the sixth step, integratingthe lithostratigraphy from the borehole control, allows one to proceed tothe seventh step: interpreting the paleoenvironments. Eighth, achronostratigraphic section is constructed. Ninth, a relative sea level chartis made. And tenth, one finally integrates and reiterates this informationinto a geohistory analysis which allows one to define play concepts,highlight leads, and, with the conventional seismic interpretation analysis,make maps and potentially outline exploration leads (suggest hydrocarbonlocations but lack one or more ingredients of the petroleum system, suchas a four-way structural closure) and drillable prospects (exhibit allingredients of a productive petroleum system). When applied in asystematic fashion, the seismic stratigraphic approach is a powerful toolfor extracting the geology from a seismic line, allowing, in some cases,the classification of ancient depositional environments even before theyare drilled.74

The 3D method of seismic stratigraphic interpretation varies littlefrom the 2D procedure, but differs greatly in its ability to image the datavolume with more directional degrees of freedom. Thus, the accuratemapping of stratigraphic relationships in three dimensions can be done,such as imaging sand distributions (recall Figure 2B) instead of simplyinterpolating them from a 2D set of lines. Such advantages, as correctlydetermining closure of a structure and its compartmentalization, areextraordinary cost- effective benefits of the 3D interpretive process. Undera 2D scenario, the interpolated geometry could be constrained only afterthe well or wells were drilled (recall Figure l). One additional advantageof 3D seismic interpretation is the ability to better resolve fault planes inthree dimensions and in so doing interpret the age of faults which in turn

74 See, e.g., the seismic delta classification of Pigott 1995, supra note 3.

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provide important information about the tectonic evolution and petroleumsystem of a basin.75

[c] — DHIs and Reservoir Characterization.If one properly constrains the information content of a seismic wavelet

with the rock-fluid information from a tying borehole, seismic data canbe used for the direct detection of hydrocarbons, termed DHIs. Thismethod, which focuses purely upon the detection and quantification ofhydrocarbons, can be a powerful tool for both exploration and exploitation,yielding the quantitative characterization of the reservoir. An example ofone conventional suite of DHI observations is illustrated in Figure 8. Theseinclude, for this particular situation, a bright spot (a large amplitudeincrease at the base of the gas/water contact), a flat spot (an anomalousflat horizon signifying the base of a gas/fluid or fluid/fluid contact), and afrequency shadow (a drop in frequency beneath a gas sand). Other DHIsinclude an AVO signature76 which can reveal rock-fluid elastic moduli,and under appropriate conditions, can either confirm or eliminate theexistence of hydrocarbons.

If these DHIs are correctly calibrated to rock data, they may be usedin development geophysics for characterizing such reservoir propertiesas porosity, pressure, fluid type, and fluid volume. Their subsequentinterpretation and mapping enable the direct determination of the fluidvolumes required for engineering calculations and field developmentstrategies. Application of DHIs and reservoir characterization fordevelopment provide a powerful tool for the direct three-dimensionalmapping of reservoir fluids and a determination of their volumes, especiallyif the data are constrained and calibrated with the substantial geologicalcontrol common to the 3D seismic method. Enhanced oil recovery (EOR)

75 For an example of fault interpretations using 3D seismic, see Cardozo, L, J.D. Pigott,and E. Ferro, 2002, Fault paleostrain reconstruction from 3D seismic as a tool for assessingreservoir quality: “La Concepcion Field, Maracaibo Basin, Venezuela,” Ingepet 5-8November, 9 pp.76 See supra § 11.02[3][b].

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techniques depend greatly upon these aspects of the 3D seismictechnique.77

[d] — Modeling and Iterative Reprocessing-Reinterpretation.

Determining the geology and fluids of rocks is a principal focus ofthe seismic stratigraphic process, whether through 2D or 3D seismictechniques. Nevertheless, because of the numerous varieties of subsurfacerocks, fluids, and conditions, obtaining a unique scientific answer can bedone only if the number of equations equals or exceeds the number ofvariables. Insight into determining the correct solution may be achievedin either of two ways: forward or inverse modeling. Forward modelingimplies the building of a known geological model and then computationallyfabricating a seismic signal that is theorized to a result. Forward seismicmodeling has become a fundamental tool for the interpretive geophysicistwho wishes to vigorously investigate seismic responses as a function ofsubtle to marked changes in geology.78 By comparison, inverse modelingtakes a seismic section and attempts to derive a geological image directlyfrom it. This process benefits from interactive reprocessing whichintegrates the bore-hole information with the seismic processingparameters.79 However, owing to the non-uniqueness, previously stated,both techniques are often used in concert with each other.

Metaphorically, both modeling techniques may be compared toattempts at repairing a squeaking automobile. Consider for examplesomeone hearing an annoying sound from a car and not knowing the sourceof the sound. The inversion method would directly recognize the natureof the sound and then correct the problem. Although this is an idealapproach, if the sound were not continuous or common to the listener, thedirect inversion method would be difficult to use. In contrast, a forwardmodeling method would attempt to reproduce the sound by exacerbatinga potential problem and then, when confirmed, fix the problem. Assuming

77 See, e.g., the case-history detailed by Greaves & Fulp 1987, supra note 3.78 See, e.g., case histories detailed by Fagin 1991, supra note 3.79 See Brac, supra note 3.

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the problem was solvable, if it reoccurred in the future the experiencedmechanic would then solve the problem by direct inversion.

[e] — 4D Seismic Method (Time-Lapse Imagery).The 4D seismic method refers to examining 3D data through an

additional dimension or more properly, parameter, i.e., calendar time. Thatis, by taking periodic seismic snapshots as a field is developed, underappropriate conditions one can directly image the pathways that the liquidsare moving by noting changes in certain properties of the snapshots, suchas changes in the relative amplitudes of the contact between differingfluid phases.80 The 4D seismic technique is particularly useful forenhanced oil recovery (EOR) development, as it allows the engineer toobserve the efficiency of the sweep of hydrocarbons through a field. Theengineer can then modify flooding programs as necessary to improve thesweeps and hence the recovery of hydrocarbons.

[f] — Costs.The amount of time required to interpret a seismic data set varies

with the magnitude of the data set, the nature of the problem, the detaildesired, and the available manpower. In general, an experiencedgeophysicist can completely interpret one to four structurallyuncomplicated 2D seismic lines in one work day, with each linerepresenting perhaps 10 linear miles. This rate of interpretation is variable.For example, if the geology is relatively uncomplicated, interpretationwould be read faster (but not more accurately) with the help of aworkstation (a computer in which all interpretation is conducted on aCRT image), or read slower, if the geology is structurally complex and ifonly paper copy is available for interpretation. Subsequent iterativeinterpretations, based upon continued refinement from well control andgeometrical ties, can be faster. Such linear interpretations do not includemapping which, again, depending upon the nature and complexity of theproblem, can require a substantial amount of time. It is not uncommon

80 See He et al. 1996, supra note 2.

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for an interpreter to take half a year interpreting several hundred miles ofseismic for one project.

A 3D seismic project takes considerably more effort, with aworkstation being the mode de rigor. Mapping, however, is almost anautomatic product of the interpretation. With the same considerations asfor 2D, but owing to the large volume of data to observe in threedimensions, it may take an experienced interpreter several weeks to initiallyinterpret a 10-square-mile grid of 3D seismic.

Consultant costs range from $500 to $2,000 per day, nonmanagerialcompany employee salaries range from $50,000 to $150,000 per year.81

Machine rentals (workstation and software) for state-of-the-artinterpretation by consultants average around $500 per day, whereas in-house interpretation requires seismic workstations which cost about$20,000 each (neglecting maintenance charges) with computer softwarelicenses which can cost in excess of $100,000. Consequently, consideringthe above estimates on the time required for interpretation, 3Dinterpretation costs are significantly greater than 2D.

[5] — Limits and Errors.There are limits to the accuracy of the seismic method. Some limits

are a function of the science itself and other limits are attributable to thehuman factor. We shall deal principally with the more quantifiable aspects,those of the science.

[a] — Acquisition.There are limits to how much signal can be extracted from the earth.

During the acquisition process, the signal-to-noise ratio is a function ofthe ability of the instruments to send an impulse into the earth and recordan uncorrupted earth response. Some of the most important natural factorswhich contribute to lowering the signal amplitude are caused by thenonstationarity or changing nature of the seismic signal in space and time.These include spherical divergence (the natural decay of the sound fromthe source as the wavefront rarefies with distance), absorption (earthmaterials absorb the sound and attenuate its continued propagation),

81 See AAPG 1996, supra note 3 with revision of March 2003.

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transmission loss (stratal surfaces which vary in acoustic impedance reflectportions of the energy and transmit the rest, resulting in continuingamplitude decay with depth), and mode conversion.82 All of these causesof nonstationarity can cause a seismic signal to decrease rapidly withdepth. Fortunately, conventional seismic instrumentation and high-outputtape83 have the ability (dynamic range) to record attenuations of a signalall the way down to almost 60 dB (more than 5 * 10 to the 56 power percent!) of its original amplitude. If attenuated below this level, the signalis swamped by noise and the events cannot be faithfully reproduced. Both2D and 3D seismic are equally affected by amplitude decay and thedynamic range of the recording instruments. Therefore, in situations where2D seismic technology may not return a signal (e.g., a homogeneous sandin the U.S. San Juan Basin), the 3D method will similarly not return acoherent signal.

We have previously described the importance of proper targetedacquisition design, for example the migration aperture for 3D seismic.84

If this parameter is ignored, then certain subsurface features cannot beimaged regardless of the subsequent efforts of the processor tries.

If the fold85 of a line is too low, random noise can greatly exceed thetrue signal. Since a 3D seismic line commonly has less than 50 percent ofthe fold of a comparable 2D seismic line, this can produce 3D imageswith less crisp definition than 2D images. Attempts at simply increasingfold by increasing bin size unfortunately leads to CMP smear, that is, thecommon mid point (CMP) varies so much horizontally that the stackedimage is poorly defined.86 Another type of CMP smear results fromsubsurface structural complications. Fortunately, this CMP smear can bepartially mitigated by expensive pre-stack depth migration.

A particularly significant error in acquisition, which is less commonnow than in the past, is positioning error. If the survey was not properly

82 Mode conversion is described supra § 11.02[3][c].83 See Sheriff 1991, supra note 3.84 See supra § 11.02[1][e].85 See supra § 11.02[2][b].86 See Pigott et al. 1993, supra note 3.

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located, the planned exploration well will be inaccurately located.However, with modem global positioning technology, such errors occurinfrequently today.

[b] — Processing.If seismic data have been improperly acquired, seismic processing

can, to some degree, remove some of the noise. Yet, just as there is a limitto the improvement that can be made in the fidelity of an old symphonicrecording using modem digital re-recording, there is a limit to how mucha poorly acquired and recorded seismic line may be similarly improvedthrough processing. The errors of acquisition can perpetuate.

Errors may also be directly caused by processing. The errors invokedby the indiscriminate application of cosmetic processing procedures maynot only distort the data but, in some cases, may create data artifacts.Although in theory problem-designed processing should not lead to sucherrors, the reality is that processing is often an iterative experimentalprocedure which results in a product that is difficult to wholly evaluateuntil after the geological data are available for constraint. Nevertheless,accurate processing results can be obtained by following conventionalnon-cosmetic procedures and by careful consideration of availablegeologic information.

We have previously described the importance of true gain recoveryand of the problems which can occur if the data are instead gained in adata-dependent fashion.87 Equally devastating can be an improper use ofdeconvolution.88 For example, in seismic, a cursory autocorrelationanalysis (an analysis which reveals periodic noise trains) of seismic datamay reveal that a particular noise (a ringing or reverberation) occurs atroughly 50 millisecond (ms) intervals (that is, horizontal bands on the

87 See supra § 11.02[3][a].88 Deconvolution, which results in clearer reflections and suppression of multiples (anecho from the same events that does not represent a real rock interface), recompresses theseismic impulse and removes changes in the seismic energy made by the passage of theseismic wave through subsurface rocks. One could liken this to suppression of unwantedechoes of the seismic energy. See Hyne, supra note 30.

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seismic line of echoes which occur at approximately 50 ms intervals). A“Band-Aid” approach might apply predictive deconvolution with aprediction length of 50 ms (a standard processing technique of removingunwanted echoes whereby their reoccurrence at particular times isattenuated) which undoubtedly would remove this feature. However, itwould also detrimentally remove any geology having intervals of 50 msthickness in time (for example, sand-shale beds of 10,000 feet per secondvelocities and 250 ft thicknesses). Such an accidental removal of thebedded geology could be extremely damaging both to the resulting imageand to the subsequent interpretation. In this circumstance, a thoughtfulstudy of the problem followed by a measured “cure” would produce betterresults.

The following are a few additional technical examples of commonprocessing problems. If the data are miss-stacked (i.e., the wrong velocitiesare chosen by an operator that is not familiar with the geology), or if abandpass filter with a particularly sharp taper on its sides (termed theGibbs effect) is incorrectly applied, pseudo-reflectors may be created (i.e.,reflectors which do not exist in reality). Just as real reflectors may beremoved by the inappropriate use of predictive deconvolution, real datacan be removed by incorrect application of velocity filters (e.g., by notallowing realistic velocity inversions to be stacked). Additional errorswhich can be obtained in processing are those outside of operator control—such as errors introduced during acquisition (mis-application of aliasingfilters, incorrect positioning, etc.) or recording (too coarse digitalresampling, polarity changes, etc.) without the operator’s knowledge.Although processing errors can occur which will lead to interpretationerrors, the degrees of processing and interpretational freedom areimmediately and severely reduced once geological information from theborehole is incorporated. For this reason, the development 3D seismicmethod, with its common incorporation of extensive well information,suffers much less from interpretational ambiguity than the 2D seismictechnique used in exploration.

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[c] — Interpretation.If the geophysical foundations of acquisition and recording are sturdy,

the resulting interpretation has the greatest potential of being sturdy aswell. However, if errors are unknowingly introduced during acquisitionor processing, they can continue to propagate during interpretation. Inaddition, errors can be introduced from the geological well data as a resultof nonoperator errors, such as problems encountered with recordingpetrophysical (or electrical) logs in a damaged hole, or operator errors,such as incorrectly mapping electronically digitized lithologic informationin three-dimensional space.

Although perhaps surprising to the uninitiated, experiencedinterpreters will not differ greatly in their final interpretations. If the database is assumed to be accurate, the freedom available for interpretation isreduced. Of course, if the structures are complex or if there is an ambiguityin the nature of the finer details of the stratigraphy, the variability of theresulting interpretations will be increased. But even here, if sufficientgeological control is available, the freedom available for creativeinterpretation is significantly reduced. In the case of a conventionaldevelopment 3D seismic project, there usually exists sufficient well controlto efficiently constrain the seismic interpretation and minimize the errorsof interpretation. The ability to obtain the most accurate interpretation islimited only by the availability and soundness of the geological calibration.

[d] — Vertical Resolution.Owing to the nature of the seismic signal transmitted into the earth

and to the earth’s attenuating abilities, there is a limit to the resolvingpower of what can be imaged, both vertically and horizontally. Becausethe recorded wavelet is frequency restricted, the amount of verticalinformation that can be interpreted (e.g., such as discriminating the upperfrom the lower bed surface of a particular unit) is limited. This is termedtuning thickness, conventionally described by the following expression:89

Equation 11: Tuning thickness = l/4Here, l (lambda) is wavelength (see Equation. 2). If a sedimentary

layer is thinner than the tuning thickness, it cannot be resolved. How this

89 See Badley 1985, supra note 3.

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might work in the real world is illustrated in Figures 13A-D (p. 432), aforward seismic model of a sandstone wedge encased in shale. Figures13A and 13B show the geology in depth and in two-way time, respectively.Figures 13C and 13D display the seismic response generated with a 25hertz and 50 hertz frequency wavelet, respectively. Assume that one isattempting to image a 60 ft channel sand, filled with oil and buried in asuitably contrasting shale body at 2 seconds of two-way time on a seismicline, that the average velocity is 10,000 feet per second, and that thedominant frequency of the seismic line at this target is 25 hertz (cyclesper second). Using Equation 2, the wavelength is 400 feet. Equation 11shows that one quarter of this wavelength (lambda) is 100 feet. Therefore,the top and bottom of this 60 ft channel sand cannot be successfully imagedas it is thinner than the tuning thickness. Interestingly, if, owing to differentacquisition and/or processing, the dominant frequency of our seismic signalwas increased to 50 hertz, then by repeating the calculations a tuningthickness of 50 feet can be achieved which would allow the discriminationof the top and the bottom of the channel sand.

Even for the 25 hertz example, however, the sand can still be detected,but its upper and lower boundaries would not be imaged. This ability,termed the detection limit, can be computed thus:90

Equation 12: Detection Limit = l /30Here, l is once again wavelength. If a sedimentary layer is less than

this thickness, it cannot be detected. In the preceding case examples, thedetection limits would be 3.33 ft. for the 25 hertz wavelet and 1.67 ft. forthe 50 hertz wavelet. These are important considerations when decidingwhether a bed can be discriminated as to its upper and lower boundaries(i.e., resolved) or whether it can only produce a response (i.e., detectable).It must be emphasized that both are theoretical limits that vary in the realworld as a function of the signal-to-noise ratio91 Moreover, it is possible,under certain circumstances, to exceed these limits.92 However, neither2D nor 3D seismic methods differ with respect to these general verticalresolution limits.

90 Id.91 See infra § 11.02[5][f].92 See Austin et al. 1991, supra note 3.

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[e] — Horizontal Resolution.Although 2D and 3D seismic methods do not differ regarding vertical

resolution limits, they do differ in horizontal resolution limits. It is usefulto metaphorically compare the seismic signal expanding as a waveformwith distance to the expansion of the beam of a flashlight. With distancethe flashlight illuminates a greater area. Likewise, the seismic signal coversa greater area with increasing distance from the sound source. This canbe both useful and destructive to the resulting seismic image. It is usefulin the sense that one can image a significantly greater area than that directlybelow a seismic section.

It is destructive in that one may inadvertently detect events that areoutside of the line of the section and incorrectly assume that they arewithin the line of the section. This horizontal aspect of seismic reflectionis known as the Fresnel zone radius,93 which is illustrated in Figure 14 (p.433) and can be computed thus:

Equation 13: RF = (V/4) * sqrt (T/f)Here, RF indicates the radius of the Fresnel zone, V is average rock

velocity, T is two- way time in seconds, and f is the dominant frequency.Recalling the example of the previous subsection, one computes a Fresnelzone radius for the 25 hertz example to be 707 feet. This suggests that a2D seismic line would image a circle of 1,414 feet in diameter about aCMP, potentially placing any event within this circle directly beneath theseismic line at this location. If imaged out of the vertical plane of theseismic line, this is termed “sideswipe.” Now, if the 2D seismic line ismigrated, this Fresnel zone is collapsed only in the direction of migration;94

sideswipe perpendicular to the line in the horizontal sense remains. Withrespect to 3D seismic, we have previously described the importance ofmigration aperture95 which affects the ability, through acquisition design,to correctly image a subsurface feature of a particular dimension. Assumingthis has been done properly, the Fresnel zone is collapsed the size of a bin

93 See Sheriff 1977, supra note 3.94 See Lindsey 1989, supra note 3.95 See supra § 11.02[1][e].

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following two pass pre-stack depth migration and is commonly an orderof magnitude smaller (100' * 100') than the uncollapsed 2D Fresnel zone(-1,400 diameter). The smaller the 3D bin (an arbitrary spatial dimensionwhich the processor chooses to average all CMP traces to yield one trace),the higher is the horizontal resolution. However, there is a tradeoff. Asbin size decreases and the power of averaging the traces in order to mitigaterandom noise decreases, noise begins to increase at the cost of the signal,what is termed a decrease in the signal to noise ratio (see next section).

[f] — Signal-to-Noise Ratio.The signal-to-noise ratio (S/N) is commonly calculated asEquation 14: S/N = S/(S + N)Here, S is the amplitude of the signal and N is the amplitude of the

noise. The lower the S/N, the less well resolvable is the resulting seismicimage. One of the main objectives of seismic processing is to boost thesignal without boosting the noise component.

Increasing fold96 helps lessen random noise. Correct application ofnon-cosmetic processing techniques can successfully mitigate both randomand coherent noise.97 Of course, there exists a limit to just how muchsignal is ultimately obtainable – a function, in part, of how much signal isreturned from a buried reflector to the dynamic range limitations of therecording technology itself.98 Though there are ways that one may increasethe signal to noise ratio (increasing fold for a 2D line or increasing foldthrough increasing the bin size of a 3D volume), unfortunately there alsoare ways that the processor can inadvertently boost the noise by creatingartifacts that the seismic interpreter will incorrectly interpret as a signal.Fortunately, if the seismic data can be constrained with sufficient wellcontrol, the noise and potential processing artifacts can be discoveredand potentially removed. Without this geological control, whether the lineis 2D or 3D, the error can remain in its disguised form to the detriment ofthe resulting interpretations.

96 See supra § 11.02[2][b].97 See supra Pigott and Feglo.98 See supra § 11.02[5][a].

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[6] — Conclusion: The 3D Seismic Advantage.The addition of one more dimension to our ability to image the earth

adds considerable power to the interpretation (Figure 15, p. 434).Nevertheless, using only 2D seismic data, it is still possible to conduct acomparably accurate 3D seismic interpretation. However the quantity ofwork involved, the time required, and ultimately the money invested makesuch a task prohibitive. Just as one may, in principle, describe a threedimensional object from photographs from every conceivable angle andperhaps accurately describe it, the image from examining a body in threedimensions, by rotating it in hand so to speak, is infinitely more desirable,and for the human mind, more informative than hundreds of twodimensional photographs.

Increasing developments in theory, technology, and applications havecontinued to drive the use of 3D seismic technology. Improvingtechnologies, both for direct applications (such as workstations whichcan now process and interpret 3D data whereas before large mainframecomputers were required) and for indirect augmentive and integrativeapplications (such as reservoir simulators, etc.), are propelling 3D seismicinto becoming the geophysical standard by which to explore and developthe world’s hydrocarbons. However, the economic advantage of greaterdrilling success is what largely continues to increase its use within thepetroleum industry. Prior to 1975, almost all seismic was 2D. Within 15years more than half of all seismic activity in the Gulf of Mexico and inthe North Sea was 3D.99 3D seismic technology continues to grow in itsimportance internationally.

When combined with repeated imaging through time (4D seismic),the economic savings can be substantial. As one quantitative examplewhich underscores the reason more companies are devoting more of theirbudgets to 3D seismic, British Petroleum and Shell have furnishedestimates of the improvements in recovery of 3D over 2D seismic methods.For their North Sea Foenhaven Field, they report an increase in recovery

99 See Brown, supra note 3.

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of 40-50 percent of oil in place when the 3D seismic technique is usedinstead of 2D. When 4D is applied, their estimate increases to 65-70percent.100

The application of new seismic technology to exploiting earthresources is not limited to the exploration of oil and gas. The applicationalso includes coal,101 and coal bed methane (exploiting the methane-richgas which is commonly absorbed onto the surface of coal beds).102 Theadvantages of using a noninvasive technique (drilling not necessary) tomap the distribution of coal seams either for recovery of the coal or forcoal bed methane is economic both in terms of time and money.103

Nevertheless, a word of humility is appropriate. No one geophysicaltool can uniquely and perfectly find all hydrocarbons. If one did exist, wewould not require the additional tools used by the geologists and theengineers. The 3D seismic technique is a powerful tool, and, indeed forthe petroleum industry, with lowering costs for its development anddeployment, it is becoming a principal tool for exploitation. However, itsaccuracy and precision has limits and it is not always the most cost-effective choice for every business opportunity.104 Only by the appropriateintegration of properly acquired, processed, and interpreted 3D seismic

100 See He, supra note 2.101 A general reference to the application of seismic to coal is that of Ziolkowski, A,1998, A Seismic Coal Exploration: Surface Methods/Part A (Handbook of GeophysicalExploration, Vol. 16), Pergamon Press, New York.102 Recent papers on the application of seismic to coal bed methane exploration arethose of Miller, R.D. and Clough, J.G., 2002, “Delineation of coal beds for coalbedmethane using high resolution seismic reflection at Ft. Yukon, Alaska,” in AmericanAssociation of Petroleum Geologists Technical Program Abstracts, and that of Marroquin,I.D, and B.S. Hart, 2003, “Seismic Attribute-Based Characterization of Coalbed MethaneReservoirs: An Example from the Fruitland Formation, San Juan Basin,” in AmericanAssociation of Petroleum Geologists Conference Technical Program Abstracts.103 Negating the environmental impact of exploration prior to obtaining the knowledgeof the geometry of coal beds in the subsurface is addressed in the seismic papers byHenson, Jr., H. and Sexton, J.L., 1991, Pre-mine study of shallow coal seams using highresolution seismic reflection methods: Geophysics, vol. 56, no. 9, p. 1494-1503 and E. B.Zhou, 2002, Seismic surveying for coal mine planning: Proceedings of CMMI Congress2002 in Cairns, 27-28 May, pp. 107-111.104 See Aylor, supra note 3.

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data, with geological information for constraint, can this instrument beproperly utilized to its extraordinary advantage. In this manner, seismictechnology, of which 3D is the newest and most significant component,offers much for the quantification of rock fluid properties, the geometricaldelineations of reservoirs, and the direct imaging and mapping ofhydrocarbons in the subsurface. It has truly redefined subsurfaceexploration of the earth’s resources.

Part 2§ 11.03. 3D Seismic Data as Evidence.

The most important legal ramification of the 3D seismic method islikely to be its use as expert opinion evidence in court and in administrativehearings. Historically, 2D seismic, if admitted as evidence at all, wasviewed suspiciously as being too susceptible of error andmisinterpretation.105 Accordingly, 2D seismic has seldom served as pivotalfactual evidence in a legal proceeding. Whether 3D seismic will be viewedas more credible evidence remains to be seen; however, modern seismicinformation, especially 3D seismic information, should be admissible ascredible opinion evidence in a variety of contexts—especially as anaugmentative aid in fact finding where other evidence, such as well control,

105 An illustrative case is Railroad Comm’n v. Delhi-Taylor Oil Corp., 302 S.W.2d 273,7 O&GR 1300 (Tex. Civ. Ct. App. - Austin 1957, writ dism’d w.o.j.). The owner of asmall tract, subdivided from a larger tract, sought a Rule-37 exception location. Opponentsargued that the tract was part of a known reservoir at the time of its subdivision andtherefore was not entitled to an exception to prevent confiscation. The opponents supportedtheir contention by introducing seismic evidence to show the likelihood of commonstructure beneath the tract. The court of appeals, noting that “[t]he seismograph depictinga structure, is, of itself, of little, if any significance to us,” held that permitting the exceptionwas proper. Id. at 276. The court further commented:

Even should we concede that such seismograph is strong evidence of aproductive area its effect here is minimized by the fact that the .8 acre tractis on the very edge of the structure. An error of a few hundred feet wouldmean the difference between a producer and a dry hole. The evidencesuggests no such precision in seismic operations.

Id.

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is also available.106 As with any geological method, fact finders will needto exercise objectivity in weighing 3D seismic evidence.107

Few reported cases deal specifically with the admissibility orcredibility of 2D seismic evidence. 2D seismic evidence has beeninfrequently offered as evidence in legal proceedings. Where it has beenoffered and then accepted or rejected, the evidence itself seldom forms acentral ground for appeal. Nevertheless, in a few reported cases, seismicevidence, or the lack of seismic evidence, is specifically mentioned.

These cases suggest that seismic evidence has been used in threegeneral categories of disputes: first are cases that address whether a lesseehas fulfilled its duty to act in good faith as a reasonable and prudentoperator—most commonly concerning whether the lessee has fulfilled itsduty to explore and develop a lease. A lessee might show compliancewith these duties by offering testimony regarding any seismic operationsthat it has conducted on the leasehold or in the immediate vicinity of theleasehold.108 And, lessors may offer the absence of seismic operations asevidence that the lessee has breached its duty.109 The majority of the

106 See, e.g., Vogel v. Corporation Comm’n, 399 P.2d 474, 476, 22 O&GR 285 (Okla.1965), cert. denied, 382 U.S. 815, 23 O&GR 566 (1965) and Tenneco Oil Co. v. StateIndus. Comm’n, 131 N.W.2d 722, 725, 22 O&GR 56 (N.D. 1964)(both cases holdingthat 2D seismic evidence supported by well control evidence was sufficient to supportagency orders).107 For example, 3D seismic data have played a key role in finding oil in MississippianLodgepole mounds near Dickinson, North Dakota. Nevertheless, even with 3D seismicdata, several dry holes have also been drilled. This mixed success indicates a problemthat needs to be solved regarding the gathering, processing, or interpretation of the 3Dseismic data in this particular play. But then again, favorable well control data do notguarantee that a producing offset well can be drilled. Better success has been achievedthrough integrating several exploration tools, including 2D seismic, 3D seismic, and soiltesting for the occurrence of iodine geochemical anomalies. Steven A. Tedesco & JohnA. Andrew, “Integration of Seismic Data, Iodine Geochemistry Yields LodgepoleExploration Model,” Oil & Gas J., Sept. 18, 1995, at 56.108 See, e.g., West v. Sun Oil Co., 490 P.2d 1073, 40 O&GR 414 (Okla. 1971).109 In Sinclair Oil & Gas Co. v. Masterson, 271 F.2d 310, 315, 11 O&GR 632 (5th Cir.1959), cert. denied, 362 U.S. 952, 12 O&GR 586 (1960), the trial court had allowed thelessee time to conduct seismic surveys, but when the seismic surveys were not done in atimely manner, the trial court cited this failure as one ground for cancellation of non-productive portions of the lease.

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cases that mention seismic have been decided in favor of the lessee.110

For example, a court will generally regard seismic operations as evidencethat a lessee is engaged in the reasonable exploration of a lease.Additionally, some courts have found that seismic evidence indicatingunfavorable structure is sufficient proof that further development drillingis not warranted. Nevertheless, in Amoco Production Co. v. Underwood,111

the court noted that the lessee had wrongfully pooled acreage that waslikely to be unproductive based upon the lessee’s own seismic evidencethat indicated that the acreage was located on a low part of the structure.

The second type of cases involving seismic evidence concerns thepresence and value of minerals thought to be under certain property.Typically, in these cases, the parties are arguing over the presence andvalue of any minerals that may be in place beneath a particular tract ofland. The suit itself might be a claim for lost profits resulting from aparty’s failure to live up to its promise to drill a well or to participate inthe drilling of a well.112 It is not enough to show the likelihood of theminerals existing in paying quantities; rather, courts require clearindications of the kind, amount, and value of the minerals present. 2Dseismic evidence is used in a few cases to help establish the presence offavorable structure. At least one eminent domain case cites the lack ofsuch evidence as a factor in refusing to assign a high valuation to mineralrights.113

110 See, e.g., Blythe v. Sohio Petroleum Co., 271 F.2d 861, 11 O&GR 609 (10th Cir.1959); Noel v. Amoco Prod. Co., 826 F. Supp. 1000, 125 O&GR 38(W.D. La. 1993);Clayton v. Atlantic Refining Co., 150 F. Supp. 9, 7 O&GR 1426 (D.N.M. 1957); Johnsonv. Hamill, 392 N.W.2d 55, 91 O&GR 77 (N.D. 1986); West v. Sun Oil Co., 490 P.2d1073, 40 O&GR 414 (Okla. 1971); Union Oil Co. v. Jackson, 489 P.2d 1073, 39 O&GR645 (Okla. 1971); Shell Oil Co. v. Howell, 258 P.2d 661, 2 O&GR 1306 (Okla. 1953);Shell Oil Co. v. Lee, 258 P.2d 666, 2 O&GR 1314 (Okla. 1953).111 Amoco Prod. Co. v. Underwood, 558 S.W.2d 509, 512, 58 O&GR 578 (Tex. Civ.Ct. App. - Eastland 1977, writ ref ’d n.r.e.).112 See, e.g., County Management, Inc. v. Butler, 650 S.W.2d 888, 79 O&GR 317(Tex. Ct. App. - Austin 1983, writ dism’d).113 State Highway Comm’n v. Antonioli, 401 P.2d 563, 566 (Mont. 1965).

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The final category of cases that refer to seismic evidence involvesappeals from decisions of oil and gas conservation agencies, such as casesconcerning well spacing and exception locations.114 In these cases, thecourt may refer to a party’s testimony in the administrative proceedingthat was based upon seismic data or commented upon the lack of suchdata115 to support its own objective or to refute the objective of anadversary.

If 3D seismic data are properly gathered, properly processed, andproperly interpreted, much can be learned about the subsurface. Resultingimages, measurements, and calculations are substantially improved over2D seismic. As with 2D seismic data, geologic structures can be identified.However, with 3D seismic data under appropriate conditions, subsurfacestructures can be imaged in much greater detail with far greater accuracy.That is, one can image a structure, measure its depth and thickness, and,as never before, calculate its volume directly from the seismic data. Underappropriate conditions, the specific type of rock can be identified and itsvariability across the structure can be determined and mapped. Porosityand its variations may also be determined throughout the rock. Fromporosity, permeability may be inferred. Moreover, the contents of thepores (e.g., oil vs. gas vs. water) can be identified. Finally, if seismicdata are gathered through time (i.e., 4D seismic data), the drainage pattern

114 See, e.g., Hester v. Sinclair Oil & Gas Co., 351 P.2d 751, 12 O&GR 237 (Okla.1960). Cf. Railroad Comm’n v. Delhi-Taylor Oil Corp., 302 S.W.2d 273, 7 O&GR 1300(Tex. Civ. Ct. App. - Austin 1957, writ ref ’d n.r.e.)(holding that seismic evidence wasnot credibly probative of the presence of structure beneath a small tract which the seismicevidence, itself, indicated overlaid the edge of the structure) and Vogel v. CorporationComm’n, 399 P.2d 474, 476, 22 O&GR 285 (Okla. 1964), cert. denied, 382 U.S. 815, 23O&GR 566 (1965)(holding that seismic evidence supported by well control evidencewas sufficient to support the Commission’s order). For cases in accord with Vogel, seeTenneco Oil Co. v. State Indus. Comm’n, 131 N.W.2d 722, 22 O&GR 56 (N.D. 1964)and El Paso Natural Gas Co. v. Corporation Comm’n, 640 P.2d 1336, 72 O&GR 93(Okla. 1981).115 See, e.g., State Oil & Gas Bd. v. Crane, 271 So. 2d 84, 86-87, 43 O&GR 527 (Miss.1972)(rejecting an argument that the applicant for a gas well permit has to produceseismic evidence indicating the probable presence of a gas bearing deep structure).

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of a reservoir116 can be traced and lenses of by-passed hydrocarbonscan be identified, resulting in greater hydrocarbon recovery.117

Although errors can occur in gathering, processing, and interpreting3D seismic data, reliability is constantly improving.118 Moreover, because3D seismic is most commonly a development tool, the validity of the datacan be tested by concurrently and iteratively evaluating the data with other

116 Amplitude information, discussed supra § 11.02[1][b], is what is so useful inproduction for directly mapping and ultimately, for effectively and efficiently exploitinga reservoir’s hydrocarbons.

Differential pressure (lithostatic minus reservoir fluid) increases ashydrocarbons are drained from a reservoir, reducing seismic amplitudes ina gas sand. . . . If, however, a GOR increase occurs during production, aswith the formation of a secondary gas cap, seismic amplitudes are predictedto increase, or “brighten” over time, because the acoustic effects of the fluidchange dominate over the pressure depletion affects. Similarly, seismicamplitudes can dramatically decrease, or “dim-out,” if in addition to pressuredepletion, the O/W contact migrates in a reservoir. Here, the amplitudedecrease is caused by pressure depletion and is further enhanced by thedrop in impedance caused by the replacement of low velocity oil and/or gasby relatively high velocity water.

Roger N. Anderson et al., “4D Seismic Helps Track Drainage, PressureCompartmentalization,” Oil & Gas J., Mar. 27, 1995, at 55, 57-58.117 Anderson also states, id. at 58:

[B]ypassed hydrocarbons can be identified by “near-zero” changes in highseismic amplitude regions over time, if there has been little increase indifferential pressure. Also, areas of sustained high seismic amplitudes canbe the highest permeability, drainage pathways, through which hydrocarbonsare moving to get to wellbores. Thus, the detection of the oil, water, and gasvolumes remaining in a reservoir might be derived from observing changesin seismic amplitudes over time, after carefully calibrating these observationsto changes measured within wells.

118 For example, the ability of both 2D and 3D seismic to accurately image the subsurfaceis affected by noise. Increasing noise obscures the signal and increasingly decreases 3Dseismic’s potential to image a reservoir, to measure its dimensions, and to calculate itshydrocarbon-filled volume. See supra § 11.02[1][f]. As another example, the 3D seismicmethod can be very helpful in identifying the upper and lower limits of a reservoir;however, of the two resolution parameters (see supra § 11.02[5][e]), the most subjectiveis the detection limit and the more objective is tuning thickness.

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information—especially well control data. Thus, 3D seismic information,together with well-control data can prove facts about the subsurface inmuch greater detail and much more reliably than in the past.

With 3D and 4D (series of 3D surveys taken over time) seismicinformation, wells can be optimally located and spaced, production ratescan be more appropriately determined,119 and enhanced recovery planscan be more refined.120 The bottom line is that with the enhanced andmore accurate imagery afforded by 3D seismic, production can be moreeffectively and efficiently maximized. Stated in conservation terms, bothunderground and economic waste can be more effectively prevented.

While especially useful in achieving greater exploration andproduction efficiency, 3D seismic could be simultaneously useful in theprotection of correlative rights. For example, in an exception locationproceeding, the location and direction of a crucial fault line could bepinpointed by 3D seismic with greater accuracy than if the fault weremapped by interpolating 2D data. Thus, the necessity for and the optimallocation of an exception location could be more reliably determined. In agas balancing dispute, 4D seismic could prove valuable in determiningwhether any recoverable gas remains in a reservoir.

Because it has the ability to directly map direct hydrocarbon indicators(DHIs), the 3D seismic method can be used to map the geographical limitsof oil or gas in place. Accordingly, the 3D seismic method could potentiallybe very helpful in determining a fair allocation of production in unitizationproceedings. One of the biggest barriers to unitization is the determinationof a cost and production allocation formula. For example, in Gilmore v.Oil & Gas Conservation Commission,121 eighty-one working interest

119 For a case dealing with a dispute over production allowables, see Marathon Oil Co.v. Corporation Comm’n, 910 P.2d 966, 135 O&GR 549 (Okla. 1994).120 “Gas/oil ratio (GOR), oil/water contact (O/W), and gas/water (G/W) changes, aswell as the increase in differential pressure caused by depletion, are all shown to affectseismic amplitudes through changes in acoustic impedance across the reservoirboundaries.” Anderson, supra note 141, at 57.121 Gilmore v. Oil & Gas Conservation Comm’n, 642 P.2d 773, 75 O&GR 172 (Wyo.1982).

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owners in a field held several meetings in an effort to agree on a plan ofunitization. They considered 71 formulas and voted on about 60 formulas,each time failing to achieve the 80 percent threshold approval needed topetition for compulsory unitization. The owners then used computers toanalyze the past voting patterns to develop a compromise formula dividingproduction based upon eleven factors. This formula received a 75.89percent approval, which allowed the Wyoming Oil and Gas ConservationCommission to compel unitization with a 75 percent approval vote incertain circumstances. In other cases, the threshold approval is easy toachieve because a single operator may own most of the interest in thereservoir, and that single operator can easily find one or two small-interestowners to join in a unitization plan. In either of these situations, the formulathat is finally imposed by the conservation order may not represent a fairallocation of production. Rather, the formula is more likely to representthe biased interests of those who voted to approve the formula at theexpense of those who opposed it. While a conservation commission ischarged with the duty to protect the correlative rights of all parties, itwould most likely approve the unitization because it is more interested inpreventing waste. If conservation commissions become more insistent onthe submission of available 3D seismic data and interpretations inunitization proceedings, correlative rights would be better protected.Unitization would still be more easily achieved and thus waste would stillbe prevented because reluctant interest owners would have a harder timequarreling with well-control data that are coupled with 3D seismic, whichdirectly images rather than interpolates the reservoir data between wells,and because the conservation agency, knowing that it will be given detailedinformation, would be more willing to “encourage” unitization throughthe issuance of curtailment and shut-in orders.122 Parties who haveprudently incurred 3D seismic expenses could be credited for such expenseas a contribution to the unit.

122 For an example of an order to “encourage” unitization, see Majority of WorkingInterest Owners in Buck Draw Field Area v. Wyoming Oil & Gas Conservation Comm’n,721 P.2d 1070, 94 O&GR 636 (Wyo. 1986).

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On the other hand, the use of 3D seismic technology could undulycomplicate the pooling of spacing units. Consider, for example, an ancientmeandering subsurface riverbed saturated with gas (recall Figure 2B).Certain small tracts within a large 640-acre spacing unit may not overliethe riverbed, and those small tracts that do overlie the riverbed may do sodisproportionately to their size. Fundamentally, non-productive acreagewithin the boundaries of a spacing unit is not entitled to share in unitproduction.123 Because 3D seismic evidence could be used to overcomethe presumptions of radial drainage124 and compensatory drainage125 thatserve to justify current spacing-unit practices, a conservation agency wouldbe theoretically barred from allocating spacing-unit production on a simplesurface-acreage basis—especially where the spacing units are large.126

This would be costly in both time and money, and could prove to be an“inefficient” drawback to the 3D seismic method. Unfortunately, giventhe doctrine of correlative rights (that an owner of a common reservoirhas the right to a fair opportunity to recover a fair share of the hydrocarbonsin a reservoir), courts may be inclined to order conservation agencies touse available 3D seismic data to “refine” spacing and pooling practices.127

123 See, e.g., Brooks v. LPCX Corp., 587 P.2d 1358, 64 O&GR 52 (Okla. 1978).124 As a general development model, petroleum engineers presume that reservoirs arehomogeneous. Consequently, they further assume that wells will drain a reservoir in auniform radial pattern. In reality, because reservoirs are heterogeneous, wells do notdrain in a radial pattern.125 As a general correlative rights model, petroleum engineers presume that, becausewells drain in a radial pattern, drainage between and among spacing units will be offsetting.In other words, drainage from spacing unit X to a well on unit Y will be compensated oroffset by drainage to unit X from unit Y and Unit Z, and so forth. In reality, this is notreally true because reservoirs are heterogeneous.126 For example, in a 640-acre spacing unit, a 40-acre tract would receive 1/16 of theproduction on a surface-acreage-allocation basis. The 3D seismic evidence, however,might reveal that the 40-acre tract should be entitled to far more or far less production.127 Besides the factual difficulties, there are theoretical difficulties as well. For example,is an owner entitled to a share of production based upon the amount of hydrocarbonsoriginally in place beneath her tract, or is she entitled to a share based upon the amountof hydrocarbons she would be able to produce by drilling a well under the rule of capture?Note that the answer might be influenced by the applicable ownership theory. In so-

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Query whether a common lessee, having reason to believe that somespacing-unit acreage is unproductive, has a duty to seek correctiveadministrative relief to allocate production fairly among those interestowners whose acreage is productive?128 These potential problems couldbe largely ameliorated if the availability of 3D seismic evidence couldbe very useful in resolving disputes over development. For example, afarmor might introduce 3D seismic evidence in an effort to prove damagespayable for the farmee’s breach of an obligation-to-drill farmoutagreement. On the other hand, the farmee might introduce 3D seismicevidence to reduce damages. Moreover, 3D seismic evidence could alsobe useful in resolving a variety of implied covenant disputes—i.e., whetherthe lessee has violated the covenants to explore, the covenant to drilladditional development wells, the covenant to protect against drainage,or the covenant to properly operate and administer a lease. For example,a lessee might use 3D seismic evidence to show that additional wells arenot needed to fully develop a particular lease, or that there is no need todrill an offset well to prevent drainage. By the same token, however, thelack of any 3D seismic operations could become a factor in finding that

called ownership-in-place jurisdictions, one might argue that she is entitled to the shareof hydrocarbons originally in place beneath the property (thereby confining the rule ofcapture to a non-liability rule). While one could make this same argument in a so-callednon-ownership jurisdiction, one might also argue that she is entitled to the full share ofhydrocarbons that she would be able to economically capture (thereby making the ruleof capture a property rule, not merely a non-liability rule). This share might depend uponwhether her tract was located high or low on the reservoir structure. In the former case,she would recover more than the hydrocarbons originally in place beneath her tract. Inthe latter case, she would recover less than the hydrocarbons originally in place beneathher tract.128 Cf. Amoco Prod. Co. v. Alexander, 622 S.W.2d 563, 72 O&GR 125 (Tex.1981)(holding that lessee has a duty to seek administrative relief to prevent field-widedrainage toward up-dip tracts) and Amoco Prod. Co. v. First Baptist Church of Pyote,579 S.W.2d 280, 67 O&GR 568 (Tex. Civ. Ct. App. 1979, writ ref ’d n.r.e.), 611 S.W.2d610, 67 O&GR 590 (Tex. 1980)(holding that a lessee owes individual duties of goodfaith and fair dealing to each lessee). If the principle of these cases is applied to theabove situation, perhaps a lessee could be charged with a duty to come forward andpresent evidence that not all of a spacing unit is productive on behalf of those lessorswho have productive acreage.

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an implied covenant has been violated. Although not yet widely used as awildcat exploration tool, seismic surveys could become an importantmeans of satisfying the implied covenant to further explore, and conversely,the lack of seismic surveys could become a basis for showing that theobligation to explore has not been fulfilled.129

When available, 3D seismic evidence should assist juries in thevaluation of minerals in eminent domain cases, or in determining damagesfor breach of a contract to purchase mineral rights. 3D seismic evidenceshould prove useful in resolving some of the ownership disputes that canarise where mineral rights have been horizontally severed. For example,if Able owns the mineral rights to the base of the Madison formation, 3Dseismic might be used to more precisely determine its depth andlocation.130

This brief discussion of possible uses for 3D seismic evidence doesnot include every possible use.131 In general, 3D seismic evidence willprove to be useful in resolving a variety of legal disputes.

129 By focusing on the notion that the lessee’s duty to conduct prudent operations islimited to those operations that are likely to be profitable, courts in Texas and Oklahomahave focused on the duty (or lack of duty) to drill exploration wells, not on a duty to useexploration methods short of drilling. See, e.g., Sun Explor. & Prod. Co. v. Jackson, 783S.W.2d 202, 107 O&GR 383 (Tex. 1989) and Mitchell v. Amerada Hess Corp., 638 P.2d441, 72 O&GR 104 (Okla. 1981). In contrast, Colorado courts have recognized that thelessee’s duty to explore does not turn on profitability. Rather the lessee’s duty turns onwhether the lessee has acted unreasonably in failing to further explore the leaseholdbased upon relevant circumstances. Gillette v. Pepper Tank Co., 694 P.2d 369 (Colo. Ct.App. 1984).130 Disputes over depths to a particular reservoir at various locations can be reliablyresolved through depth calculations (see supra § 11.02[1][a], Equations 1 and 2) basedupon either 2D or 3D seismic data. However, because velocity information can be obtainedin a radial pattern with 3D seismic, it is much more accurate in obtaining velocity averagesfor measuring depth (see supra § 11.02[1][c]). Accordingly, subsurface structures areboth better defined and better located using 3D seismic. Moreover, 3D seismic maycontribute information regarding the depth of a planar surface, which when multipliedby a vertical dimension of thickness, yields a volumetric calculation.131 For example, the Minerals Management Service will accept newly acquired 3Dseismic data and information as grounds for acting on a request to re-determine royaltiespayable on deep-water OCS wells. 30 C.F.R. § 203.53(d)(1)(i)(1995).

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§ 11.04. Geophysical “Trespass.”Not surprisingly, as use of 3D seismic technology expands and

becomes routine within the petroleum industry, the potential legalramifications of 3D seismic increasingly becomes of interest. One of themore troublesome issues, geophysical trespass, is actually a very old issuethat manifested itself with conventional 2D seismic operations; however,the trespass issue is more complicated with 3D seismic operations.

The basic legal concern for a geophysical operator is to obtainpermission from the owner of the exploration right to avoid what iscommonly called “geophysical trespass.” Proper permitting minimizesthe possibility that a geophysical operator will be sued for trespass orother tort.132 Although this basic concern is the same for all seismic

132 Legal commentators have written extensively on geophysical trespass and theunauthorized disclosure of geophysical information. For treatise commentary, see RichardW. Hemingway, The Law of Oil and Gas §§ 4.1, 4.2 (3d ed. 1991)[hereafter Hemingway];Eugene Kuntz, Oil and Gas § 12.7 (1987); Howard R. Williams & Charles J. Meyers, Oiland Gas Law § 230 (1995)[hereafter Williams & Meyers]; W. L. Summers (John S.Lowe), The Law of Oil and Gas §§ 660 - 662 (1962)[hereafter Summers]. For articles,see Harry L. Blomquist III, “Geophysical Trespass? The Guessing Game Created ByThe Awkward Combination of Outmoded Laws and Soaring Technology,” 48 Baylor L.Rev. 21 (1996)[hereafter Blomquist]; Earl A. Brown, Jr., “Geophysical Trespass,” 3 RockyMtn. Min. L. Inst. 57 (1957)[hereafter Brown]; Joseph R. Dancy & David Humphreys,“Legal Considerations Involved in the Geophysical Exploration for Oil and Gas,” 57Okla. B. J. 1802 (1986); Walace Hawkins, “The Geophysical Trespasser and NegligentGeophysical Explorer,” 29 Tex. L. Rev. 310 (1951)[hereafter Hawkins]; Joseph L. Hull,Jr., “Oil and Gas Lessee v. Seismograph Licensee,” 21 Okla. B. Ass’n J. 1503 (1950);Kendor P. Jones, “Restrictions on Access and Surface/Subsurface Trespass InvolvingExploration and Production Technologies,” 40 Rocky Mtn Min. L. Inst. 20-1 (1994);Kendor P. Jones & Robert C. Faber, “Subsurface Trespass and Seismic Options,” StateBar of Texas 11th Ann. Adv. Oil, Gas, & Min. L. Course, Paper J (1993)[hereafter Jones& Faber]; Scott D. Marrs, “Geophysical Trespass and Advanced Geophysical ExplorationTechniques,” 58 Tex. B. J. 128 (Feb. 1995); Richard G. Martin, “Geophysical Explorationon Severed Mineral Interests in Oklahoma,” 36 Okla. B. Ass’n J. 1889 (1965); Allan D.Nielsen & Christopher B. Manderville, “Seismic Access Issues,” 40 Alberta L. Rev. 1(2002); Robert J. Rice, “Wrongful Geophysical Exploration,” 44 Mont. L. Rev. 53 (1983);Henry M . Shine, Jr., “Measure of Damages in Suits Relating to Geophysical Operations,”29 Notre Dame L. Rev. 49 (1953)[hereafter Shine]; and Jack M. Wilhelm, “Legal ProblemsRelated to Geophysical Operations,” 42nd Mineral Law Inst., Louisiana State UniversityLaw Center, March 30-31, 1995. For student commentary, see Mark D. Christiansen,Note, “Oil and Gas: Improper Geophysical Exploration—Filling in the Remedial Gap,”

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operations, the concern is quantitatively larger for a 3D seismic operatorthan for a conventional seismic operator. The reasons for this greaterconcern include the facts that large land areas may be involved; 3D surveysrequire more intense surface use; targeted acreage of a 3D survey mayinclude tracts that are not actually used and occupied by the geophysicaloperator; and some tracts used and occupied by the 3D operator may notbe targeted acreage. Moreover, because 3D seismic is often regarded ashighly reliable, favorable information can be very valuable to those whohave it, and unfavorable information can greatly lower the speculativevalue of “wildcat” acreage. Thus, a geophysical trespasser and its principalscan be liable for potentially large direct and consequential damages.

From the perspective of the mineral owner, the concern is whether the3D seismic operations will be conducted without permission and withoutpayment for the privilege. Moreover, unfavorable 3D seismic data canserve to “condemn” the property for leasing and development. Accordingly,should 3D seismic become a widely used wildcat exploration tool, unleasedmineral owners can be expected to seek greater compensation for 3Dseismic operations because of their concern that unfavorable seismic datawill eliminate further interest in the property, thereby damaging a tract’sspeculative mineral value. However, regarding fee acreage, most oil andgas companies would not commonly commission proprietary 3D seismicsurveys unless the subject acreage is wholly or partly under lease.

Surface owners are also concerned parties. From their perspective,the stated concern is generally whether seismic operations will cause

32 Okla. L. Rev. 903 (1979)[hereafter Christiansen]; James W. Griffin, Comment,“Protectable Property Rights, Trade Secrets, and Geophysical Data After City ofNorthglenn v. Grynberg,” 71 Denv. U. L. Rev. 527 (1994); James R. Rogers, Comment,“Liability for the Invasion of a Landowner’s Rights by Geophysical Exploration,” 18Cal. W. L. Rev. 460 (1982); Scott S. Slater, Note, “The Surreptitious Geophysical Survey:An Interference with Prospective Advantage,” 15 Pac. L. J. 381 (1984); Thomas M.Warner, Jr., Note, “Oil and Gas: Recovery for Wrongful Geophysical Exploration—Catching Up With Technology,” 23 Washburn L. J. 107 (1983). An article addressingtrespass issues concerning hydraulic fracturing, Norman J. Hyne and Laura H. Burney,“Hydraulic Fracturing: Stimulating Your Well or Trespassing Theirs?,” 44 Rocky Mt.Min. L. Inst. 19-1 (1998).

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actionable damage to the surface. Often, the real concern is to receivecompensation for the use of the surface—whether or not there is anydamage or legal entitlement to compensation.

There are other perspectives as well. For example, an environmentalistmight be concerned about the impact of 3D seismic on the environment—especially fish and wildlife. On balance, however, wider use of 3D seismicshould be an environmental plus because fewer dry or unnecessary wellswill be drilled.

Geophysical operations conducted without permission from the“owner” of either occupied or targeted land raises several fundamentalissues, including: Will the law recognize and protect the right to exploreas a valuable property right? If so, what possible causes of action areavailable to protect this right? Who owns the right to explore? What if thetargeted property is owned in cotenancy or in succession? What if themineral ownership has been horizontally divided? What if the mineralownership is divided by substance? What if the property is subject to anoil and gas lease or other agreement? Can the surface of one tract be usedto secure subsurface information from another tract? These questions arebriefly addressed in the following subsections.

[1] — The Right to Explore Is aValuable Property Right.Fundamentally, the right to conduct geophysical operations is a

valuable property right, and the law will safeguard this right againsttrespass and related torts.133 Although technically one cannot trespassupon an incorporeal interest, courts have nevertheless protected oil andgas interests from trespass regardless of the oil and gas “ownership theory”recognized in a particular state.134 The right to conduct geophysical

133 See, e.g., Franklin v. Arkansas Fuel Co., 51 So. 2d 600, 601 (La. 1951); Wilson v.Texas Co. 237 S.W.2d 649, 650 (Tex. Civ. App. - Ft. Worth 1951, writ ref ’d n.r.e.). Seealso, La. Rev. Stat. Ann. § 30: 217.134 See Ohio Oil Co. v. Sharp, 135 F.2d 303, 310 (10th Cir. 1943)(concurring JusticePhillips, after recognizing that Oklahoma follows the nonownership theory of oil andgas and yet still recognizes the tort of geophysical “trespass,” commented that “it isdifficult for me to see how there can be a trespass upon an incorporeal hereditament”).

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operations is traditionally secured by obtaining permission from the“owner” of the right to explore. Obviously, a geophysical surveyor whoknowingly conducts seismic operations on land without permission of anowner of the right to explore commits a bad-faith trespass.135

Permission may take several forms, including a “prospecting”permit,136 a prospecting permit coupled with an option to acquire an oiland gas lease, or an oil and gas lease. In the case of a prospecting permit,used most commonly by a geophysical operator doing a “speculativesurvey”137 for licensing to oil and gas companies, the operator is given afixed period of time to engage in geophysical operations. The owner ofthe right to explore might be paid nothing, paid a flat or per-acre sum ofmoney, paid according to the operations on the subject property (e.g., pershot hole or per mile of seismic line), paid by the acreage explored, orpaid on some other basis. In the case of a prospecting permit coupledwith a lease option—generally used by a geophysical operator undercontract to an oil and gas company who is not ready to acquire leases—the form of payment is likely to include an up-front payment for a one- tothree-year lease option, and an additional bonus if a lease is taken. In thecase of an oil and gas lease, the lessee will generally have the implied orexpressed right to explore through the use of geophysical or other methods.In return, the lessor will be paid a bonus and probably annual rentals forthe primary term of the lease.

[2] — Causes of Action for Protecting the Rightto Explore.

Depending on the specific facts and circumstances, the owner of theright to explore may choose to pursue several causes of action against a

135 See, e.g., Sick v. Bendix-United Geophysical Corp., 341 So. 2d 1308 (La. App.1stCir. 1977).136 See, e.g., Encina Partnership v. COREnergy, 50 S.W.3d 66 (Tex. App. - CorpusChristi 2001).137 A speculative survey is done by a geophysical operator for the purpose of licensingthe data to multiple oil and gas companies for their assessment. Profits are earned byselling multiple licenses of the data to multiple companies. In contrast a “proprietarysurvey” is one done by a geophysical operator for a specific client who pays for theexclusive rights to the data.

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party who conducts geophysical operations without permission. Theseinclude trespass, assumpsit, loss of speculative value, interference withthe right to contract regarding exploration, invasion of privacy,138 unlawfulacquisition of a trade secret, and misappropriation. Thus, an “owner” whohas suffered unlawful geophysical operations will have a choice of tort139

remedies in the court of the jurisdiction where the wrongful surveyoccurred.140 The choice of remedy will turn on the nature andcircumstances of the plaintiff’s injury and on the cause of action that, onbalance, offers the best chance for recovery and the most lucrative damageaward.141

138 See generally, Restatement (Second) of Torts § 652A. Although invasion of privacyhas been suggested as a possible means of recovery for wrongful acquisition ofgeophysical information, this possible cause of action will not be discussed because thelaw of privacy has not evolved to embrace a right to privacy concerning one’s mineralrights.139 Case law generally classifies an action relating to an authorized geophysical surveyas grounding in tort. See, e.g., Iberville Land Co. v. Amerada Petroleum Co., 141 F.2d384, 387 (5th Cir. 1944)(concerning Louisiana law and stating that an action for wrongfulgeophysical survey was grounded in tort, not quasi contract); General Geophysical v.Brown, 38 So. 2d 703, 705 (Miss. 1949)(holding that a wrongful geophysical surveyconstitutes trespass); and Ohio Oil Co. v. Sharp, 135 F.2d 303, 307 - 308 (10th Cir.1943)(suggesting that, under Oklahoma law, wrongful geophysical surveys are groundedin trespass).140 See, e.g., Shell Petroleum Corp. v. Moore, 46 F.2d 959, 962 (5th Cir. 1931)(holdingthat, because an action for a wrongful geophysical survey is not grounded in conversion,the action must be brought in the jurisdiction where the land is located). Cf., WesternGeophysical Co. v. Adriatic, Inc., 1996 U.S. Dist. LEXIS 11862 (E. Dist. La. August 9,1996)(holding that a claim relating to damages to the lessees of oyster beds in statewaters caused by vessels engaged in geophysical surveying fell within the federal court’smaritime jurisdiction).141 See, e.g., Layne Louisiana Co. v. Superior Oil Co., 26 So. 2d 20, 24 (La.1946)(holding that the owner of the right to explore was entitled to recover compensatorydamages from a geophysical trespasser). Cf., Shell Petroleum Corp. v Scully, 71 F.2d772, 774 (5th Cir. La. 1934)(stating that a geophysical trespasser is liable for more thannominal damages) and Thomas v. Texas Co., 12 S.W.2d 597, 598 (Tex. Civ. App. -Beaumont 1928, no writ)(awarding only nominal damages due largely to the plaintiff’slack of proof of actual damages). Cf., Burns v. Western Geophysical Co., No. 89-6259(slip op.)(10th Cir. Dec. 12, 1990)(remanding a case involving the wrongful acquisitionof geophysical information to determine whether an award of punitive damages waswarranted).

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If suit is brought for trespass by reason of an unlawful entry, theplaintiff will ordinarily recover for any injury to the land and to anyimprovements on the land, including timber and water.142 Often, the ownerof the right to explore will elect to waive the trespass and bring suit inassumpsit for the value of the exploration right that was wrongfullyexercised.143 An action for recovery of the value of the exploration rightis theoretically possible even if an action in trespass is barred, such aswhere no physical entry occurred.144

In an action to recover damages for the value of the exploration right(or similar damages), an issue can arise regarding the type of “contract”the parties would have negotiated: a bare exploration permit,145 a permitto explore coupled with a lease option,146 or an oil and gas lease.147 Thisdispute also involves the amount of acreage such a permit or lease wouldlikely cover—the mineral owner’s full acreage in the area, only the actual

142 See, e.g., System Fuels, Inc. v. Barnes, 363 So. 2d 747 (Miss. 1978); Bynum v.Mandrel Indus., Inc., 241 So. 2d 629, 632; Magnolia Petroleum Co. v. McCollum, 51So. 2d 217, 218 (Miss. 1951); and General Geophysical v. Brown, 38 So. 2d 703, 705(Miss. 1949).143 Gulf Coast Real Estate Auction Co. v. Chevron Indus., Inc., 665 F.2d 574, 575, 73O&GR 98 (5th Cir. 1982) and Phillips Petroleum Co. v. Cowden, 241 F.2d 586, 592, 7O&GR 1291 (5th Cir. 1957)(construing Texas law). The damages available in an actionfor assumpsit or for the value of the exploration right may be criticized as inadequate forfailing to punish the wrongful explorer in that recovery is generally based upon thecompensation the explorer would have paid if it had negotiated a lawful right to explore.Thus, the trespasser pays damages as if a rightful entry had been made.144 Consider Gulf Coast Real Estate Auction Co. v. Chevron Indus., Inc., 665 F.2d 574,575, 73 O&GR 98 (5th Cir. 1982), where the only physical entry was the landing of anairplane which was used in flight to gather information about the property at issue.145 In Shell Petroleum v. Scully, 71 F.2d 772, 774 (5th Cir. La. 1934), the courtemphasized that in calculating damages the court must limit the damage award only tothat which was wrongfully taken (i.e., the right to explore itself). See also, Holcombe v.Superior Oil Co., 35 So. 2d 457, 459 (La. 1948) and Layne Louisiana Co. v. Superior OilCo., 26 So. 2d 20, 24 (La. 1946).146 Franklin v. Arkansas Fuel Oil Co., 51 So. 2d 600, 601 (La. 1951).147 Cf., Gulf Coast Real Estate Auction Co. v. Chevron Indus., Inc., 665 F.2d 574, 575,73 O&GR 98 (5th Cir. 1982), and Phillips Petroleum Co. v. Cowden, 241 F.2d 586, 593,7 O&GR 1291 (5th Cir. 1957).

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acreage explored, or some amount in between.148 Today, one wouldordinarily expect a mineral owner to seek damages measured by the oiland gas lease bonus typically paid for acreage typically leased because alease is probably the most common arrangement negotiated with a mineralowner for the exercise of the exploration right.149

The lack of any actual physical damage to the property at issue, thedefendant’s willing disclosure to the plaintiff of any information acquired,and the defendant’s nondisclosure of the information to third parties mayserve to limit the recovery of other damages.150 On the other hand, thefailure to complete a survey or the failure to secure useful or valuableinformation in the course of a wrongful survey will not serve to eliminatedamages.151 If a “trespassing” geophysical operator disseminatesunfavorable information, the rightful owner may recover for the loss ofspeculative value or for interference with the right to contract regardingexploration.152 Here, recovery is usually based upon any resulting

148 See, e.g., Phillips Petroleum Co. v. Cowden, 241 F.2d 586, 593, 7 O&GR 1291 (5thCir. 1957), after remand, 256 F.2d 408, 409, 9 O&GR 110 (5th Cir. 1958)(affirming anaward of damages for the market value of the exploration right over the entire 2,682-acre tract at issue, rather than the portion of the tract actually occupied by the defendant).149 See, e.g., Burns v. Western Geophysical Co., No. 89-6259 (slip op.)(10th Cir. Dec.12, 1990)(upholding the award of a full lease bonus). In IP Timberlands Operating Co.,Ltd., v. Denmiss, 657 So. 2d 282, 296 (La. App. 1st Cir. 1995), the court permitted alandowner to recover lost lease bonus revenues against a surface lessee who had grantedseismic permits to geophysical operators for all acreage explored that was notsubsequently leased for oil and gas operations.150 See Shell Petroleum Corp. v. Scully, 71 F.2d 772, 774 (5th Cir. 1934).151 See, e.g., Phillips Petroleum Co. v. Cowden, 241 F.2d 586, 593, 7 O&GR 1291 (5thCir. 1957), and Franklin v. Arkansas Fuel Oil Co., 51 So. 2d 600, 601 (La. 1951). Cf.Lableu v. Vacuum Oil Co., 132 So. 233, on rehearing, 132 So. 776 (La. 1931)(reducingdamages to $100 on the grounds that the wrongful entry was not done for the purpose ofgathering information concerning the property at issue, that no useful informationregarding such property had been obtained, and that plaintiff suffered no loss because hehad refused all offers to lease the property).152 Burns v. Western Geophysical Co., No. 89-6259 (slip op.)(10th Cir. Dec. 12,1990)(upholding a damage award for the value of the exploration right based upon thebonus a lessee would have paid for a lease, plus a damage award for loss of speculativevalue for wrongful disclosure of the seismic data to third parties, and rejecting Western’s

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depreciation in the value of the oil and gas interest.153 And, in the case ofan intentional wrongful exploration, a court could award damages formental anguish154 and even exemplary damages.155 However, courts haverejected liability on the ground of conversion, which would, in the propercase, allow damages based upon the value of the information to thedefendant.156 My views regarding the proper measures of damages areoffered in Section 11.04, below.

argument that the total damage award constituted a duplicate recovery because Westernhad not challenged the jury instructions requiring a separate calculation of damages forthe right to explore and for wrongful disclosure). In a non-geophysical context, see Solbergv. Sunburst Oil Co., 246 P. 168 (Mont. 1926). For further discussion of the tort ofinterference with the right to contract see, J’Aire Corp. v. Gregory, 24 Cal.3d 799 (Cal.1979).153 See, e.g., Angelloz v. Humble Oil & Refining Co., 199 So. 656, 658 (La. 1940). Seealso, Layne Louisiana Co. v. Superior Oil Co., 26 So. 2d 20, 24 (La. 1946) and Thomasv. Texas Co., 12 S.W.2d 597, 598 (Tex. Civ. App. - Beaumont 1928, no writ)(suggestingin dicta that further recovery for any established decline of the property’s royalty interestvalue may also be appropriate).154 See, e.g., Ard v. Samedan Oil Corp., 483 So. 2d 925, 928, 88 O&GR 302 (La.1986)(recognizing mental anguish but reducing the award); Dykes v. Peabody ShorelineGeophysical and Transportation Ins. Co., 482 So. 2d 662 (La. App. 1st Cir. 1985)(affirmingan award for mental anguish for some parties and reducing the award for other parties);Lloyd v. Hunt Exploration, Inc., 430 So. 2d 298 (La. App. 3d Cir. 1983)(rejecting awardfor mental anguish as abuse of discretion where there was no testimony supporting suchan award); and Teledyne Exploration Co. v. Klotz, 694 S.W.2d 109, 111 (Tex. App. -Corpus Christi 1985, writ ref ’d n.r.e.)(affirming an award of $50,000 for past and futuremental anguish).155 See, e.g., Seismic Petroleum Serv., Inc. v. Ryan, 450 So. 2d 437 (Miss. 1984). Seealso, Kennedy v. General Geophysical Co., 213 S.W.2d 707, 709 (Tex. Civ. App. -Galveston 1948, writ ref ’d n.r.e.)(stating that punitive damages may only be recoveredwhere actual damages were sustained); Burns v. Western Geophysical Co., No. 89-6259(slip op.)(10th Cir. Dec. 12, 1990)(allowing the trial court to consider the award of punitivedamages, even though the geophysical trespasser, in keeping with apparent custom andpractice, had obtained permission from the surface owner, but not the mineral owner);Geophysical Serv., Inc. v. Thigpen, 102 So. 2d 423, 424 (Miss. 1958)(remanding a juryaward for a new trial for the admission of defendant’s good faith so as to avoid an awardfor punitive damages). But see, Angelloz v. Humble Oil & Refining, 199 So. 656, 658(La. 1940)(rejecting an award of punitive damages for geophysical trespass).156 See, e.g., Phillips Petroleum Co. v. Cowden, 241 F.2d 586, 593, 7 O&GR 1291 (5thCir. 1957) and Shell Petroleum Corp. v. Moore, 46 F.2d 959, 962 (5th Cir. 1931).Ordinarily, the mineral owner cannot recover the value of the geophysical information in

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[3] — Who Owns the Right to Explore?Who owns the right to explore? This basic question is a somewhat

misleading. Obviously, because the right to explore is a valuable propertyright that the law will protect, the sole fee simple owner of both the surfaceand mineral estate in Blackacre is the only party authorized to conductgeophysical operations directly on and relating to Blackacre.157 But whatif a life tenant holds the property? What if the surface estate and mineralestate are severed? What if the minerals are owned by cotenants? What ifone mineral owner owns the oil and gas rights and another mineral ownerowns the other mineral rights? What if there has been a “horizontal”severance of the mineral rights by depth or by strata? What if subsurfaceinformation is acquired for a purpose other than mineral exploration? Whatif the mineral exploration is done to determine whether a particular surfaceuse is suitable out of concern that such use would be incompatible withmineral development? What if the property is subject to an oil and gaslease? What if there are several oil and gas lessees who have acquiredseparate leasehold rights, but have entered into a joint operating agreementrespecting the property at issue? What if the property is subject to avoluntary pooling or unitization agreement? What if the property has beenforce-pooled or force-unitized? This section will address some of thesequestions.

[a] — Severed Mineral Interests.Where ownership of the surface and mineral interests have been

severed, the right to conduct geophysical mineral operations rests withthe mineral owner.158 This principle is now well established, although

the hands of the trespasser (such as in an action for mesne profits), perhaps because thetrespasser’s profits derived from the acquisition and possible sale of the information arenot generated during the short time period of the trespass itself. Nevertheless, the benefitsreceived by the trespasser may be relevant in determining damages due in an assumpsitaction. But see, Franklin v. Arkansas Fuel Oil Co., 51 So. 2d 600 (La. 1951)(awardingdamages based upon the value of geophysical information to the trespasser).157 See, e.g., Wilson v. Texas Co., 237 S.W.2d 649, 650 (Tex. Civ. App. - Fort Worth1951, writ ref ’d n.r.e.).158 Id. at 650; Phillips Petroleum Co. v. Cowden, 241 F.2d 586, 590, 7 O&GR 1291 (5thCir. 1957); Holcombe v. Superior Oil Co., 35 So. 2d 457, 459 (La. 1948); and Burns v.Western Geophysical Co., No. 89-6259 (slip op.)(10th Cir. Dec. 12, 1990). In a Louisiana

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historically, in Oklahoma, for example, some oil and gas operatorsconducted geophysical operations with only the surface owner’spermission.159 No case law supports this historical practice – at least wherethe geophysical operations were conducted in furtherance of oil and gasexploration or development. Accordingly, no prudent operator wouldengage in geophysical mineral operations based upon permission fromsomeone who owned only a surface interest.160

The basis for recognizing that the right of exploration rests with themineral owner is discussed in Layne Louisiana Co. v. Superior Oil Co.:161

It is a well-known and accepted fact . . . that the right togeophysically explore land for oil, gas or other minerals is avaluable right. Large sums of money are annually paid landownersfor the mere right to go upon their land and make geophysical andseismograph tests. The information obtained as the result of suchtests is highly valuable to the person or corporation by whom theyare made. If the information thus obtained be favorable, it can beused and is used in dealing with the landowner for his valuablemineral rights. If the information be unfavorable, the fact quicklybecomes publicly known and thus impairs the power of thelandowner to deal advantageously with his valuable mineral rights.The average landowner is without means or funds to securegeophysical or seismograph information. Where that information,which is exclusively his by virtue of his ownership of the land, isunlawfully obtained by others, the landowner is clearly entitled

case, a surface lessee was found liable to the underlying landowner for issuing seismicpermits to geophysical operators. IP Timberlands Operating Co., Ltd., v. Denmiss, 657So. 2d 282, 295 (La. App. 1st Cir. 1995).159 Burns v. Western Geophysical Co., No. 89-6259 (slip op.)(10th Cir. Dec. 12, 1990).160 An important exception to this well-established principle is that a geophysicaloperator may explore federally-owned severed minerals with permission of only theoverlying surface owner. See generally, “Onshore Oil and Gas Geophysical ExplorationSurface Management Requirements,” BLM Manual H-3150-1, Release 3-289, page 1(June 7, 1994).161 Layne Louisiana Co. v. Superior Oil Co., 26 So. 2d 20 (La. 1946).

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to recover compensatory damages for the disregard of his propertyrights.162

However, the mineral owner’s exclusive right to conduct geophysicaloperations is subject to several caveats.

First, the initial severance instrument must be examined to determinewhether the exploration right has been expressly addressed by the termsof the instrument. For example, perhaps the severance instrument mayreserve in the surface owner the right to consent to exploration, to controlthe manner of exploration, or to be compensated for the use of the surface.

Second, while the initial mineral severance ordinarily grants theexclusive exploration right to the mineral owner, an oil and gas lease,depending on its express terms, may or may not grant the exclusiveexploration right to the lessee. This is true whether the lease is taken fromthe fee owner or from a severed mineral owner.163

Third, the surface owner should be regarded as having implicitlyretained the right to engage in subsurface exploration and testing necessaryto the lawful use and development of the surface.164 There is, however,no direct case authority to support this assertion.

Fourth, the mineral owner’s right of surface use is not unlimited. At aminimum, such use must be reasonable, necessary and nonexcessive and,in some states, the surface owner may be entitled to statutory surfacedamages.165

162 Id. at 22. The Louisiana Mineral Code currently provides that where the surface isburdened by a mineral servitude, the right of exploration rests with the owner of themineral servitude. La. Rev. Stat. Ann. § 31:21. But see, Jeanes v. G.F.S. Co., 647 So. 2d533, 535 (La. App. 3d Cir. 1994), cert. denied, 650 So. 2d 255 (La. 1995)(stating, underLa. Rev. Stat. Ann. § 30:217 that a geophysical operator must have permission from thelandowner, not just the owner of a mineral servitude). The holding in the Jeanes case,however, has been made moot by a statutory amendment. See La. Rev. Stat. Ann. §30:217.163 For further discussion, see infra § 11.04[3][g].164 For further discussion, see infra § 11.04[3][b].165 For further discussion, see infra § 11.04[3][i].

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Fifth, geophysical trespass may include an unlawful entry onto thesurface. In this case, the surface owner would be entitled to recover forthe surface trespass.166

[b] — Surface-Related Exploration.Cases that recognize that the exploration right rests with the mineral

owner (rather than with the surface owner) all deal with geophysicaloperations conducted for the purpose of locating favorable geologicstructures for possible further oil and gas exploration and development.Query whether geophysical activity, core sampling, or other acquisitionof subsurface information can be conducted by a surface owner whenconducted for a purpose that is directly related to surface managementand development?

By analogy, consider the case of Grynberg v. City of Northglenn.167

Grynberg held an unrecorded coal lease from the State of Colorado, themineral owner. Grynberg sued the City of Northglenn for damagesresulting from the City’s drilling of a test hole on the leased acreage withoutGrynberg’s permission and publishing the test results in a public filingsubmitted to the State Engineer. The test hole and public filing revealedthat the coal beneath the property was not commercially recoverable.Hence, Grynberg brought suit to recover the resulting lost market valueof his coal lease—alleging trespass, assumpsit, wrongful appropriationof geologic information, interference with prospective business advantage,negligence, and inverse condemnation.

Although the City had no actual notice of the unrecorded Grynberglease, its own search of record title did reveal that the State of Coloradoowned the mineral estate and that Coors held a prior coal lease that wasstill within its primary term. Upon inquiry of Coors, the City was informedthat Coors had abandoned the lease after Coors determined that any coalbeneath the property was not economically recoverable. Prior to drilling

166 Cf., Holcombe v. Superior Oil Co., 35 So. 2d 457, 459 (La. 1948), Layne LouisianaCo. v. Superior Oil Co., 26 So. 2d 20, 24 (La. 1946), and Thomas v. Texas Co., 12S.W.2d 597, 598 (Tex. Civ. App. - Beaumont 1928, no writ).167 Grynberg v. City of Northglenn, 739 P.2d 230, 234, 95 O&GR 28 (Colo. 1987).

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the test hole, the City never sought or obtained permission from the Stateof Colorado (as owner of the severed mineral interest), but it did obtainpermission from the surface owner. The court held that only the mineralowner (in this case, either the State or Grynberg)168 could authorizegeological testing, noting that “[t]he recognition of the exclusivity of theright of the mineral owner to consent to such exploration is based uponthe central importance of information concerning mineral deposits to thevalue of the mineral estate.”169 The court further held that, because theCity had not sought permission from the State, the record owner of thecoal, the City was not entitled to the protection of the recordation act forGrynberg’s failure to record his coal lease.

If the court is correct that only the State or Grynberg could haveauthorized geological testing, then the court’s holding that the City wasnot entitled to the protection of the recordation act is undoubtedly correct.Recordation acts protect bona fide purchasers, not trespassers who havefailed to deal with the apparent record owner.170 Thus, consistent withthe court’s analysis, one could argue that the State (as mineral owner) orGrynberg (as the State’s lessee), but not the surface owner, had the rightto control mineral exploration on the ground that such exploration is aninvasion of the mineral estate. I submit, however, that a mineral ownershould not be free to bar any and all subsurface activity by a surfaceowner.

168 Regarding the matter as irrelevant, the court does not discuss the possibility that theState of Colorado, as severed mineral owner, could have authorized the exploration. Thecourt, after noting that the City did not seek the State’s permission, stated that the answerto this question depends upon the terms of Grynberg’s lease (i.e., whether the lease gaveGrynberg the “exclusive” right to explore). Such permission would have to have beenobtained from the State Board of Land Commissioners, as custodian of state-ownedminerals, not from the State Engineer, a regulatory official.169 739 P.2d at 235.170 See, e.g., Sick v. Bendix-United Geophysical Corp., 341 So. 2d 1308 (La. App.1stCir. 1977)(holding that the owner of an unrecorded interest in oil and gas had a cause ofaction against a geophysical surveyor who entered property without permission of therecord owner).

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Surely a surface owner has the right to drill a well on the property insearch of water without having to secure the permission of the mineralowner. A water well may be drilled quite deep, and well cuttings mightreveal the absence of coal deposits, just as in Grynberg. Moreover, a surfaceowner, who is contemplating extensive surface development, may have alegitimate need to drill test holes to be assured of continuing subjacentsupport.

Of course, a court could recognize a surface owner’s right to drill ageologic test hole for a legitimate surface-related purpose but still prohibitthe surface owner from generally publicizing the results in a manner thatcauses unnecessary harm to the speculative value of severed mineral rights.Even here, however, not all disclosure should be prohibited. For example,the surface owner should be permitted to disclose the results of a test to aprospective purchaser of the surface who may be concerned about thepossibility of future mineral development on the property.

In Grynberg, the City drilled the test hole in the course of purchasingthe surface to ascertain the presence or absence of recoverable coalreserves. This testing was apparently necessary to secure state and localgovernment approval for the construction of a wastewater reservoir onthe property.171 The results of the test became public upon submission tothe State Engineer, as required by law. Although the Colorado statutescould have been drafted to require the State Engineer to keep the testresults confidential, as a practical matter, any subsequent change in zoning,followed by construction of the reservoir, would have signaled the lack ofcommercial coal deposits to anyone familiar with the underlying statutes.Thus, under the circumstances, the construction of a reservoir wouldundoubtedly damage the speculative value of Grynberg’s coal lease.

171 Colorado statutes require the State Engineer and local governments to identify andlocate valuable mineral deposits in heavily populated counties. Local zoning authoritiesare prohibited from zoning in a manner that would prevent the possible extraction ofcommercially valuable mineral deposits. Colo. Rev. Stat. §§ 34-1-301 through 305.Although these statutes directly affect the ability of a surface owner to develop thesurface estate, the court held that these statutes do not alter the exclusive right of themineral owner to authorize mineral exploration.

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Nevertheless, I would view any such damage, resulting from intensesurface development in a Grynberg situation, as analogous to the resultingdamage that occurs when wildcat oil and gas property is surrounded bydry holes drilled on adjacent land. Surely, there is no cause of action forthe resulting loss of speculative value to the wildcat acreage. Or considerthe situation where the owner of oil and gas rights drills a well that indicatesan absence of coal or of fresh water. Such a well would damage thespeculative value of the both coal rights and surface rights, but neitherowner should have a cause of action for damage for loss of speculativevalue.

The drilling of the test well in Grynberg was actually mandated byColorado law for the protection of mineral owners because governmentalland-use authorities could not permit surface development that wouldunduly hinder the recovery of commercial coal deposits.172 If drilling totest for the possibility of recoverable coal reserves is a necessaryprerequisite to intense surface development, shouldn’t the surface ownerbe authorized to drill? Or stated another way, could the mineral ownerprohibit the surface owner from drilling such a hole? I submit that theanswers to these questions should be, respectively, yes and no. The courtin Grynberg recognized that, in resolving tensions between surface andmineral owners, the “broad principle . . . is that each owner must have dueregard for the rights of the other in making use of the estate in question.”173

If this broad principle is truly a two-way street, how could the mineralowner prevent drilling done as a precaution against intense surfacedevelopment that might actually hinder mining? If the mineral owner canprevent anyone from testing for the presence of a commercial deposit ofcoal, the mineral owner can then inhibit (and the Colorado statutes wouldthen effectively bar)174 surface development on acreage that contains nocoal. Such power would give the mineral owner too much leverage innegotiating with the surface owner about permission to drill a test hole.

172 739 P.2d at 234, discussing Colo. Rev. Stat. §§ 34-1-301 through 305.173 739 P.2d at 234.174 Colo. Rev. Stat. §§ 34-1-301 through 305.

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Perhaps, if the mineral owner denied permission, the land-use authoritieswould allow surface development on the presumption that no commercialcoal deposits are present beneath the property. The risk, however, is thatthis solution could result in the waste of coal deposits or the waste of asurface investment, depending upon whether mining was later allowed.

To sum up, the Grynberg decision essentially holds that if the purposeof exploration is to gather data on subsurface geology, the mineral owneror its lessee has the right to control such activity, regardless of the specificreason for gathering the data. This seems to broaden the mineral owner’sright of surface use beyond what the common law has traditionally allowed.At common law, the mineral owner’s use of the surface must relate to theenjoyment of the mineral estate. For example, a mineral owner wouldexceed the scope of common law surface-use rights by entering the surfaceto drill holes for the purpose of determining whether the property is suitablefor use as a wastewater reservoir because this is unrelated to mineralexploration and development. While, in this instance, a court might decidethat the right is correlative, thereby requiring permission from the boththe surface and mineral owners, such a rule would be inefficient and wouldraise the cost of conducting such tests due to the strategic behavior of theparties in negotiating the necessary permission. Thus, on balance, theholding in Grynberg is not desirable public policy. The holding isparticularly troublesome in states where surface and mineral estates arecommonly severed, where intense surface development and mining areincompatible, and where surface owners, prior to constructing majorsurface improvements, wish to detect and avoid geologically unstableareas, such as fault lines or old, abandoned mine shafts.

After remand, plaintiff Grynberg dropped all tort claims and proceededon a theory of inverse condemnation. After trial, the jury awarded Grynbergnearly $650,000, plus attorney fees. The Colorado Court of Appealsaffirmed Grynberg v. Northglenn,175 but the Colorado Supreme Courtreversed, holding that no “taking” of the severed mineral estate had

175 Grynberg v. Northglenn, 829 P.2d 473, 477 (Colo. App. 1991).

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occurred, either as a result of the City’s acquisition of the surface estatefrom the surface owner or as a result of the drilling of the test hole inquestion, even though the value of Grynberg’s coal lease may have beendepreciated.176 The supreme court also addressed whether a “trade secret”had been “taken” from Grynberg. Although the court stated that it wasnot deciding whether geophysical information in general may be a tradesecret, it concluded that “Grynberg’s access to the information [concerningthe coal deposits] was not sufficiently exclusive to qualify as a trade secret. . .” because of other publicly available information concerning the amountof coal beneath the property.177

[c] — Minerals Owned in Cotenancy.Under the well-established majority view, a cotenant may exploit the

minerals without the consent of other cotenants, subject to a duty to accountfor net profits.178 Accordingly, where mineral rights are held in cotenancy,a party, desirous of conducting geophysical operations, can obtain thenecessary permission from any one of the cotenant mineral owners,regardless of how small such cotenant’s fractional interest may be.179 Onthe other hand, a geophysical surveyor who conducts operations on co-tenancy lands without the permission of any co-tenant is liable to all ofthem for trespass.180 Moreover, even an operator who has permission of

176 City of Northglenn v. Grynberg, 846 P.2d 175, 185 (Colo. 1993).177 846 P.2d at 184, n. 17.178 See, e.g., Prairie Oil & Gas Co. v. Allen, 2 F.2d 566, 569 (8th Cir. 1924) and Burnhamv. Hardy Oil Co., 147 S.W. 330, 335 (Tex. 1912). The notion of accounting betweencotenants stems from the English Statute of Anne in 1705. Regarding the duty of onecotenant to account to other cotenants, see 2 American Law of Property § 6.14 (A.James Casner, ed., 1952). Generally, the duty to account is based upon actual receipts ofthe cotenant, not on the fair market value of the rights conferred.179 Enron Oil & Gas Co. v. Worth, 947 P.2d 610 (Okla. App. 1997)(owner of undividedunleased mineral interest can authorize a third party to conduct seismic exploration activitieswithout the consent of the surface owner or other mineral owner cotenants).180 Ladner v. Quality Exploration Co., 505 So. 2d 288 (Miss. 1987)(holding that, iffeasible, all co-tenants should be joined as necessary and indispensable parties to aseismic trespass case). But see, Young v. Garrett, 149 F.2d 223 (8th Cir. 1945)(construing

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some or all cotenants may be liable for any permanent damage to the landwhere the damage results from unnecessary, negligent, or excessive useof the land.181

Under the minority view, followed in Illinois, Louisiana, Michigan,Virginia, and West Virginia, subject to statutory modifications in three ofthese states182 and to a possible prevention-of-drainage exception,183 theexploitation of minerals by fewer than all cotenants is viewed as waste184

and can be enjoined by a nonconsenting cotenant185 or lessee.186 Ingeneral:

Once it is ascertained that a person has established property rightswhich he seeks to protect by injunction, he will not ordinarily bedeprived of that remedy on the ground that the injunction operatesto the inconvenience of the person against whom the remedy isinvoked, or that the rights are of little value to the holder thereof.187

Arkansas law and holding that an action in trespass may be maintained by less than allco-tenants for their proportionate share of any trespass damages done to the freehold).181 Cooperative Refinery Ass’n v. Young, 393 P.2d 537 (Okla. 1964).182 Oil and Gas Rights Act, Smith Hurd Ill. Comp. Stat. Ann. ch. 765 §§ 520/0.01 - 520/0.10; La. Rev. Stat. Ann. §§ 31:174 - 31:177; and Mich. Comp. Laws Ann. §§ 319.101through .110.183 See, e.g., Law v. Heck, 145 S.E. 601, 602 (W. Va. 1928).184 The notion of an action for waste between cotenants originates with the EnglishStatute of Westminster II in 1285, which has been adopted by various state courts orcopied by state legislatures. The term “waste” is seldom defined, which has led to a lackof uniformity in the United States.185 Chosar Corp. v. Owens, 370 S.E.2d 305 (Va. 1988)(dealing with coal); Dotson v.Branham, 90 S.E.2d 783 (Va. 1956)(dealing with coal); Law v. Heck, 145 S.E. 601 (W.Va. 1928)(holding that the owner of a 1/768 interest may enjoin drilling and productionby the other cotenants unless the premises are suffering drainage). See also, Murray v.Haverty, 70 Ill. 318 (1873); Zeigler v. Brenneman, 86 N.E. 597 (Ill. 1908); Cecil v. Clark,39 S.E. 292 (W. Va. 1913) and South Penn Oil Co. v. Haught, 78 S.E. 759 (W. Va. 1901).Cf., Davis v. Byrd, 185 S.W.2d 866 (Mo. App. 1945)(criticizing the minority view as badpolicy).186 Trees v. Eclipse Oil Co., 34 S.E. 933, 934 (W. Va. 1899).187 Hark v. Mountain Fork Lumber Co., 34 S.E.2d 348, 354 (W. Va. 1945)(dealing witha trespass).

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Cotenants who commit waste are treated like trespassers and are jointlyand severally liable.188 A nonconsenting cotenant,189 however, may electto waive the tort and recover the value of such cotenant’s share of thesubstances removed, subject to a deduction of costs if the developingparty acted in good faith.190 A lease issued by less than all cotenants isvalid between the parties but is not binding on other cotenants,191 whocan enjoin the lessee from developing the premises.192 Moreover,nonconsenting cotenants cannot be compelled to lease their interest.193

In some circumstances, the harshness of the minority rule may be temperedby the availability of partition in equity.194

Although case law concerning exploration in minority-viewjurisdictions is scarce, case law in West Virginia may support the right ofone cotenant to engage in mineral exploration. In Smith v. United FuelGas Co.,195 the court offers the following dicta:

Each cotenant had the right to enter on the land himself or bylessee and explore for gas and market the gas if found. But whenthat right was exercised and the common property was taken, theother cotenants or tenants in common are entitled to an accountingas for a waste committed.196

188 Stewart v. Tannant, 44 S.E. 223 (W. Va. 1903).189 Cotenants can be held to have manifested their consent without formalities. Vicarsv. First Virginia Bank-Mountain Empire, 458 S.E.2d 293, 296 (Va. 1995).190 McNeeley v. South Penn Oil Co., 52 S.E. 480 (W. Va. 1905)(discussing accountingbetween cotenants); South Penn Oil Co. v. Haught, 78 S.E. 759 (W. Va. 1913)(discussingaccounting between cotenants); and Williamson v. Jones, 27 S.E. 411 (W. Va.1897)(discussing this matter in the context of a life tenant-remainder situation, but alsodiscussing cotenancy).191 Freeman v. Egnor, 79 S.E. 824 (W. Va. 1913).192 United Fuel Gas Co. v. Koontz, 169 S.E. 328, 330 (W. Va. 1933)(citing Law v.Heck, 145 S.E. 601 (W. Va. 1928)).193 Id.194 See, Alderson v. Horse Creek Coal Land Co., 94 S.E. 716 (W. Va. 1917) and Zeiglerv. Brenneman, 86 N.E. 597 (Ill. 1908).195 Smith v. United Fuel Gas Co., 166 S.E. 533 (W. Va. 1932).196 Id. at 534.

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In this case, the plaintiffs sought an accounting, not an injunction.Thus, the statement about each cotenant having a right to explore is dictaand its contextual meaning is unclear. If this dicta is intended to recognizean exploration right in less than all cotenants, then the basis must be, asbetween development and exploration, that exploration does not involvethe permanent extraction and actual depletion of minerals. In other words,no “waste” occurs. Although seismic surveying could result in the“depletion” of the speculative value of the property for oil and gasdevelopment, I nevertheless submit that the minority view should protectexploring co-tenants from claims for loss of speculative value by non-exploring cotenants. Such exploration may be necessary to convince fellowco-tenants of the wisdom of mineral development, and a co-tenant whoinvests in exploration is necessarily doing so—particularly under theminority view—for the potential benefit of all co-tenants.

Louisiana’s minority view is not based upon the Statutes ofWestminster II, the Statute of Anne, or the doctrine of waste. Rather, it isgrounded in the view that cotenants (owners in “indivision” in Louisiana)are the owners of part, as well as the whole, and can only jointly possessand control the property. Thus, subject to some exceptions,197 case law inLouisiana holds that a nonconsenting cotenant can bar oil and gasoperations by another cotenant.198 Louisiana case law has been modifiedby statute, which allows the concurrent holders of an undivided 80 percentof the mineral rights (either through full ownership, mineral servitude, orboth) who consent to exploration or development to proceed even thoughthe owners of the balance of interest oppose such operations.199

Nevertheless, I am advised that the practice in Louisiana is to obtain theconsent of all owners or lessees.200 The reason for this is because the co-owner of a mineral servitude or a co-owner’s lessee or permittee, seeking

197 See, e.g., United Gas Public Service Co. v. Arkansas-Louisiana Pipe Line Co., 147So. 66 (La. 1933)(cotenant who is draining the cotenancy property from nearby propertiescannot bar oil and gas operations by other cotenants).198 Gulf Refining Co. v. Carroll, 82 So. 277 (La. 1919).199 La. Rev. Stat. Ann. §§ 31:164, 166, 175. Id. §§ 31: 166 and 175.200 Telephone interview with a Louisiana oil and gas lawyer, May 1996.

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to explore or develop, must show that a good faith effort was made tocontact co-owners and to offer to contract with them on substantially thesame basis as with other co-owners.201 A co-owner, acting in good faithand holding less than an 80 percent interest, may act without the necessarypermissions when necessary to prevent waste, destruction, or extinctionof the mineral servitude.202

Thus, except for Louisiana (and perhaps the other minority-view statesthat have no specific case law dealing with exploration), a cotenant of asmall fractional interest can authorize mineral exploration without liabilityfor waste. This is so even though the exploring party may gain valuableand favorable information that would be very useful to the nonconsentingcotenants in negotiating development rights or gain information that greatlyreduces the land’s speculative value. In monetary terms, the party seekingto explore can acquire the right to gather valuable geophysical informationby negotiating an exploration right with a cotenant willing to take theleast compensation for granting the right.

While this same scenario can occur regarding the acquisition of drillingand development rights, operators who intend to drill have a big incentiveto acquire the full working interest prior to drilling. This is so because theoperator must account to other cotenants for the net profits of development,as required by case law.203 For example, under the majority view, acotenant owning a 10 percent interest in the mineral rights would assume100 percent of the risk of drilling a dry hole or unprofitable well, butwould only be entitled to 10 percent of any net profits. Thus, most operatorsare desirous of acquiring the full working interest prior to drilling a well.

In contrast, a geophysical operator who wishes only to acquire seismicdata has little, if any, incentive to acquire a prospecting permit from allcotenants because the geophysical operator would want to acquire data ascheaply as possible. This, however, does not hold true for oil and gasoperators. An oil and gas operator, who is interested in developing thearea if favorable geophysical information is acquired (in contrast with a

201 La. Rev. Stat. Ann. §§ 31: 164,166, and 175.202 Id. § 31:177.203 See, e.g., Prairie Oil & Gas Co. v. Allen, 2 F.2d 566, 569 (8th Cir. 1924).

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geophysical company who might be shooting an area on speculation),does have an incentive to acquire lease options or leases up front from allcotenants. Cotenants who are aware that seismic operations have occurredmay drive a very hard lease bargain. Moreover, they may insist onreviewing seismic information prior to executing a lease. A prospectivelessee who, in the course of lease negotiations, falsely denies havingseismic information could face a fraud claim.

No modern reported case addresses a situation where non-consentingcotenants have filed suit to bar exploration, to obtain an accounting fornet profits realized through sale or use of acquired geophysical data, torecover the reasonable value of the exploration right, or to recover theloss of speculative value. Given no direct case authority regarding a dutyto account for exploration net profits, given the reliability of 3D seismic,and given the fact that unfavorable data may eliminate affected propertyfrom further exploration and leasing activity, the oil and gas industry shouldanticipate that cotenant mineral owners may seek some relief.204 Howwill courts rule? Although I have no prediction,205 one commentator, HarryBlomquist, believes that courts might side with cotenant mineralowners.206 How should courts rule? I submit that courts should deny relief.Nevertheless, to guard against a contrary ruling, I agree with Mr.Blomquist’s suggestion that a prudent geophysical operator may wish toacquire an oil and gas lease from one cotenant, rather than rely solely ona bare seismic permit.207

204 This point is also discussed by Blomquist, supra note 130 at 35-40.205 As previously discussed, Louisiana has decided this question by statute. Accordingly,my comments are related to jurisdictions other than Louisiana.206 Blomquist, supra note 130 at 37 suggests that courts may have some problemsrecognizing the right of a geophysical operator to shoot seismic based upon a bareexploration permit from fewer than all cotenants. Blomquist bases this concern on thegeneral rule that a seismic permit is like an easement or a license which Blomquistcontends cannot be granted by fewer than all cotenants. Id. Moreover, Blomquist arguesthat courts may be reluctant to allow one cotenant to issue a permit that could result in aseismic survey that could destroy or seriously harm the value of the mineral estate. Id. at39.207 Blomquist, supra note 130 offers this advice so that the geophysical operator canassert all of the status and rights of a cotenant. Id. at 40.

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My reasoning is as follows: Because a cotenant can, in mostjurisdictions, lawfully develop and produce oil and gas without the consentof other cotenants,208 it necessarily follows that a cotenant can explorefor oil and gas without the consent of other cotenants. Moreover, becausea cotenant may develop the oil and gas through a lessee, I submit that alessee may engage in exploration for the same reasons that a cotenantmay do so.209 And since a cotenant is free to engage in exploration, acotenant should be able to permit a geophysical operator to do so. Inother words, because a cotenant or cotenant’s lessee may explore, it islogical that a geophysical company should be entitled to engage in seismicsurveying with permission from a cotenant or a cotenant’s lessee210

without having to secure the consent of other cotenants. When I initiallyreached this conclusion,211 there was no case authority directly on point;however, there was the following general principle: an individual cotenantcan give a license or permit to a third party “to use and enjoy the propertyin the same manner as the tenant himself, provided an ouster of hiscotenants is not involved.”212 Since then, the Oklahoma Court of Appealshas expressly held that one cotenant may permit a third party to explorethe property through seismic operations without the consent of other

208 See, e.g., Prairie Oil & Gas Co. v. Allen, 2 F.2d 566, 569 (8th Cir. 1924) and Burnhamv. Hardy Oil Co., 147 S.W. 330, 335 (Tex. 1912).209 My argument is consistent with established majority-view doctrine. And as discussedabove, the limited case law in minority view jurisdictions, which view mineraldevelopment by one cotenant as waste, nevertheless recognizes that a cotenant has theright to explore. See, Smith v. United Fuel Gas Co., 166 S.E. 533, 534 (W. Va. 1932)(statingthat a cotenant may explore without the joinder of other cotenants).210 Regarding an oil and gas lessee’s authority to issue a geophysical permit, note thatthe exploration should arguably be in furtherance of the object of the lease (i.e.,exploration, drilling, and development). Accordingly, a lessee may not have the authorityto permit a geophysical operator to conduct a survey for speculation if the lessee (or atleast a prospective purchaser of the lease) is not going to acquire the seismic data. For

further discussion, see infra § 11 .04[3][g].211 Owen L. Anderson and Dr. John D. Pigott, “3D Seismic Technology: Its Uses, Limits,& Legal Ramifications,” 42 Rocky Mt. Min. L. Inst. 16-1, 16-88 to 16-90 (1996).212 2 American Law of Property § 6.12 at 51 (A. James Casner, ed. 1952), citing EagleOil & Refining Co. v. James, 126 P.2d 880 (Cal. App. 1942). This seminal treatisedistinguishes licenses from easements. Although all cotenants must consent to an easement

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cotenants.213 The court held that a mineral owner may separately transferthe right to explore the mineral interest and the right to use the surface forseismic exploration apart from other incidents of the mineral estate.214

Regarding the right of less than all cotenants to explore for and, inmost jurisdictions, to exploit minerals, compare the “one-stock rule,” whichgoverned the exploitation of certain profits at common law. Under theone-stock rule, the right to exploit a profit must be exercised jointly andfor the benefit of all co-owners of the profit.215 Among co-owners, a one-stock rule assists in preventing waste that results from exploitation of acommon pool—such as occurs when there is unfettered oil and gasdevelopment under the rule of capture. The one-stock rule also avoidslitigation among co-owners concerning their obligation of accounting.The rule’s chief disadvantage, however, is that transaction costs are toohigh. The greater the number of co-owners, the harder is the task ofsuccessfully negotiating a joint operating agreement. For example, therule would invite strategic behavior by the owners of small interests whowould often “hold out” for payments that greatly exceed the actual valueof their interests.216 One means of countering this tendency would be toprovide for a more efficient action for partition by sale than is generallyavailable where fractional mineral interests are involved.217 In any event,

because the dominant easement would interfere with the ownership rights of all cotenants,there is no similar interference where a license is granted which authorizes a use of theproperty that would be a lawful use by an individual cotenant. Accordingly, I questionHarry Blomquist’s concern that courts may require a geophysical operator to securepermission from all cotenants to engage in geophysical operations.213 Enron Oil & Gas Co. v. Worth, 947 P.2d 610, 613-14 (Okla. App. 1997), citing Earp v.Mid-Continent Petroleum Corp., 27 P.2d 855, 858 (Okla. 1933) and Knox v. Freeman, 78P.2d 680, 682 (Okla. 1938).214 Id. at 613, citing Hinds v. Phillips Petroleum Co., 591 P.2d 697 (Okla. 1979).215 See, Mountjoy’s Case, 1 And. 307, 1 Godbolt 17, 4 Leonard, 147, Moore 174, 2Coke on Littleton 164b, 165a (C.P. 1583). See also, Stanton v. T. L. Herbert & Sons, 211S.W. 353, 355 (Tenn. 1919); Harlow v. Lake Superior Iron Co., 36 Mich. 105, 110 (1877).216 See, e.g., Law v. Heck, 145 S.E. 601, 602 (W. Va. 1928)(where the owner of anundivided 1/768 mineral interest held out for compensation greatly in excess of itsproportionate value).217 See generally, Hemingway § 3.3.

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even in jurisdictions that classify an oil and gas lease as a profit, the one-stock rule of Mountjoy’s Case has been rejected in the context of oil andgas operations.218

What about cotenants who seek an accounting for net profits, if any,or file an action for the reasonable value of the exploration right or forloss of speculative value? While it is true that a cotenant or a cotenant’soil and gas lessee must account for the net profits of mineral development,absent an ouster, neither they nor a geophysical permittee should be obligedto account to other cotenants for the net profits of seismic information.Moreover, the other cotenants should not have a cause of action to recoverthe reasonable value of the exploration right, the loss of speculative value,or the seismic information itself. Although the seismic data was acquiredthrough the exercise of a co-tenancy right, the data itself—in the absenceof a cooperative agreement—should be regarded as the surveying co-tenant’s separate intellectual property.

Consider the following analogous situations: first, while a cotenantwho has a special expertise in horizontal well drilling and productionwould have to account to cotenants for the net profits of production, ifany, that same cotenant should not be obliged to disclose special horizontal-drilling expertise to the other cotenants. The Fifth Circuit Court of Appealshas even ruled that a lessee of a cotenant does not have to discloseinformation about a gas well to other unleased cotenants.219

Second, a cotenant who tries in good faith to secure production bydrilling a well, would not be liable for lost land values when the well iscompleted as a dry hole. And if a cotenant drills both a dry hole and aprofitable producing well, most courts have held that the producingcotenant must account for net profits on a well-by-well basis.220

218 See, e.g., Hinds v. Phillips Petroleum Co., 591 P.2d 697, 62 O&GR 532 (Okla.1979) and Chandler v. Hart, 119 P. 516, 520-22 (Okla. 1911).219 Mitchell Energy Corp. v. Samson Resources Co., 80 F.3d 976, 985 (5th Cir. 1996).This same case held that an operating cotenant who fails to account to other cotenantsfor net profits is liable for an accounting, but not for conversion. Id. at 982-984.220 See, e.g., McMillan v. Powell, 362 S.W.2d 721, 722, 17 O&GR 399 (Ark. 1962);Davis v. Sherman, 86 P.2d 490, 493 (Kan. 1940); and Williamson v. Jones, 27 S.E. 411,423-424 (W. Va. 1897)(involving a life tenant-remainder situation, but also addressingcotenancy). But see, Connette v. Wright, 98 So. 674 (La. 1923).

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Accordingly, in calculating net profits on a well-by-well basis, theproducing cotenant may recoup the costs of drilling the producing well,but may not recoup the costs of a dry hole. Thus, the developing cotenantmust absorb the full cost of the dry hole. In this circumstance, it would bepunitive to also require the developing cotenant to compensate the non-consenting cotenants for lost land values that resulted from the drilling ofthe dry hole on the affected portion of the property. Even if accountingwere permitted on a property or tract basis, a rule that requiredcompensation for lost land values resulting from dry holes would greatlydiscourage exploration and would be tantamount to adopting a rule thatviewed any exploration activity as waste.221

Unfortunately, the details of the law relating to a cotenant’s generalduty of accounting are confusing. At common law, a cotenant in solepossession had no duty to account provided the cotenant in possessiondid not oust other cotenants wishing to share possession. The commonlaw, however, was changed by the Statute of Anne, Stat. 4 Anne, c.16Section 27 (1704), which as interpreted, required a cotenant to accountfor any rents and profits received from third persons in excess of her justproportion. As to a just proportion, after passage of the Statute of Anne,in England, a cotenant was allowed to mine a fair share of coal fromcotenancy property without having to account to other cotenants.222 TheStatute of Anne survives in most states by statute or common law. Asinterpreted in most states, a cotenant must account for any net profitsderived from mineral exploitation.223 The mere gathering of seismic

221 Under cotenancy law, the only basis for liability for loss of speculative value wouldappear to be waste. The Statute of Westminister, 13 Edw. I, c. 22 (1285), provided that acotenant was liable for waste. This statute has counterparts in most states. Nevertheless,in England, the courts continued to recognize that a cotenant in fee had the same rightsas a sole fee owner to use and enjoy land. And, as previously discussed, in most Americanstates, a cotenant can exploit minerals and need only account for net profits, if any.There is no authority for holding a cotenant liable for “net losses” except where thecotenant has maliciously or recklessly harmed the property itself, such as by destroyingan improvement on the land that lowers the property’s value. See generally, Roger A.Cunningham, William B. Stoebuck, and Dale A. Whitman, The Law of Property § 5.8 at222 (Law. ed. 1984).222 Job v. Patton, L.R. 20 Eq. 84 (1872).223 See, e.g., White v. Smyth, 214 S.W.2d 967, 974 (Tex. 1948).

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information by less than all cotenants should be allowed without anaccounting because no minerals and hence no net profits are beingextracted.

In a minority of states, however, there is a broader duty to account forrents, net profits, or reasonable rental value. In these states, while a cotenantmight have to account for rents received from a geophysical operator,that cotenant would not ordinarily receive (and thus would have no dutyto account for) profits from the sale of the seismic data by the geophysicaloperator. By analogy, a cotenant who cash rents farmland may be requiredto account for the rents received, but neither the renting cotenant nor thefarm tenant would have to account to the other cotenants for a share of thecrops. The only issue might be whether the cotenant received a reasonablerental value. This latter concern may prompt cautious geophysicaloperators to pay a reasonable price vis-à-vis the consenting cotenant’sfractional interest and be prepared to pay the same proportionate sums toother cotenants who complain.

On the other hand, as a matter of public policy, interested parties,such as other co-tenants, might argue for the right to purchase seismicdata by paying their proportionate share of the acquisition costs. To theextent this argument has any merit, a right to purchase should be withouta credit for any loss of speculative value resulting from an unfavorablesurvey. Once a geophysical survey has been conducted, it is arguablywasteful to conduct a similar survey. I submit, however, that courts shouldrefrain from judicially conferring any such right to purchase on fellowco-tenants or other parties. This fundamental question, together withimportant sub-issues, such as whether the right of purchase should belimited to unprocessed data or be extended to processed data, should beleft to legislatures, who through public hearings, can better sort out theeffect that a right of purchase would have on the seismic and oil and gasindustries. A better approach might be to require the submission of seismicdata to state conservation agencies that would eventually make the datapublicly available after an appropriate period of confidentiality.

Another confusing, and potentially troublesome aspect of cotenancylaw is the notion that one cotenant owes a fiduciary duty to other cotenants.In discussing the cotenant’s duties to account to each other, to not commitwaste, and to not be hostile to each other, some courts have a bad habit of

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characterizing the cotenancy as a fiduciary relationship.224 Perhaps themost common situation where courts characterize cotenancy as a fiduciaryrelationship occurs when one cotenant acquires an outstanding adversarialclaim to the cotenancy property that it asserts exclusively for itself ratherthan for the benefit of the entire cotenancy. Even here, however, a fiduciaryduty does not exist automatically by reason of cotenancy itself. Generally,to have a fiduciary relationship, the cotenants must have acquired theirinterest through a common inheritance, will or deed.225 On the other hand,concerning a cotenant’s own interest, the cotenant may freely transactwith strangers and may acquire the interests of another cotenant withoutoffering to share the acquisition with other cotenants.226 Although tenantsby the entirety have a fiduciary relationship,227 other concurrent interestowners generally are not fiduciaries to each other,228 absent someindependent relationship or agreement.229 Accordingly, a cotenant whoissues a prospecting permit for seismic operations relating to her undividedinterest should not be in violation of a fiduciary obligation to othercotenants.230

224 This frequently happens in oil and gas cases. Courts sometimes loosely use the termfiduciary to characterize the duties owed by an operator to non-operators, by an executiverights holder to a non-executive mineral interest owner, by a lessee to a lessor under thepooling clause, and even by producers to royalty owners. In such cases, it is doubtful thatthe court really means fiduciary in the trustee sense.225 See generally, 2 The American Law of Property § 6.16 at 67 - 69 (A. James Casner,ed. 1952).226 4 Thompson on Real Property § 1801 at 164 (1979).227 Id. at 160.228 See, e.g., Pure Oil Co. v. Byrnes, 57 N.E.2d 256, 361 (Ill. 1944).229 4 Thompson on Real Property § 1801 at 161-165 (1979).230 In Mitchell Energy Corp. v. Samson Resources Co., 80 F.3d 976, 985 (5th Cir. 1996),the Fifth Circuit Court of Appeals held that an oil and gas lessee of one cotenant does notowe a fiduciary duty to the other cotenants. See, e.g., Matter of Fender, 12 F.3d 480, 486(5th Cir. 1994)(holding that, under Texas law, cotenants do not stand in a fiduciaryrelationship absent a specific agreement). Cf., Smith v. Bolen, 261 S.W.2d 352 (Tex. Civ.App. - Fort Worth 1953), aff ’d in part, rev’d in part, 271 S.W.2d 93 (Tex. 1954) andHardman v. Brown, 88 S.E. 1016 (W. Va. 1916).

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231 See, e.g., Welborn v. Tidewater Assoc. Oil Co., 217 F.2d 509, 511, 4 O&GR 385(10th Cir. 1954)(construing Oklahoma law).232 Id. See also, Ohio Oil Co. v. Daughetee, 88 N.E. 818 (Ill. 1909); Williamson v.Jones, 27 S.E. 411 (W. Va. 1897).233 See, e.g., id., Priddy v. Griffith, 37 N.E. 999 (Ill. 1892); Graham v. Smith, 196 S.E.600 (Va.. 1938); and White v. Blackman, 168 S.W.2d 531 (Tex. Civ. App. 1942, writref ’d w.o.m.).234 Smith v. United Fuel Gas Co., 166 S.E. 533, 534 (W. Va. 1932)(suggesting that acotenant may explore without the consent of and without accounting to other cotenants).

[d] — Minerals Owned in Succession.Where the mineral ownership is divided between a life tenant and

remainderman, permission for mineral development from theremainderman is insufficient because the remainderman has no currentright of access to the property.231 On the other hand, a life tenant maynot develop the minerals, because the extraction and removal of mineralsfrom the property would constitute waste.232 In the proper circumstance,a life tenant may have to permit mineral exploitation to prevent wastecaused by the drainage of oil and gas by wells drilled on adjacent ornearby property. Also, if a life tenant can assert the open mine doctrine233

or if the instrument creating the life estate provides that the life tenantholds “without impeachment for waste,” then the life tenant may exploitthe minerals for its own account. In general, however, an interested mineraldeveloper must obtain permission from both the life tenant and theremainderman.

Arguably, however, geophysical activity does not constitute waste—at least in the traditional sense—because nothing is extracted. By analogyto cotenancy, even—under the minority view—where the actual extractionof minerals by one cotenant is viewed as waste, mere exploration maynot be viewed as waste.234 Thus, one could argue that the life tenantcould authorize geophysical operations without risk of an injunction or adamages suit by the remainderman. No case law directly addresses thisquestion, but the oil and gas industry should anticipate that aremainderman may seek an answer in the future, and the oil and gasindustry should not assume that the answer will be the same as in thecase of cotenants.

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235 One could argue that the life tenant should be permitted to explore to further thepublic policy of encouraging mineral exploration and ultimate development. If allowed,presumably the life tenant could exercise this right itself or through a permittee. Ifexercised through a permittee who paid for this privilege then the question would ariseas to whether the life tenant could retain the payment or would have to hold the paymentin trust for the remainderman. By analogy to oil and gas leases, most states treat leasebonuses as corpus to be held in trust for the remainderman with the interest earned onthe bonus being paid to the life tenant. See, e.g., Sewell v. Sewell, 1 N.E.2d 492 (Ill.1936). But see, Franklin v. Margay Oil Corp., 153 P.2d 486 (Okla. 1944)(awarding thelease bonus to the life tenant).236 Statutes in several states, however, authorize courts to appoint receivers or trusteesto execute leases of contingent future interests. See, e.g., Colo. Rev. Stat. § 38-43-101;Neb. Rev. Stat. § 57-222 et seq.; N.D. Cent. Code § 38-10-12; and Tex. Civ. Prac. &Rem. Code, § 64.092.237 See, e.g., Chartiers Block Coal Co. v. Mellon, 25 S. 597, 599 (Pa. 1893).

Most courts adhere to the common law of waste where successiveinterests are concerned. Because a life tenant may not unilaterally developminerals (except perhaps to prevent drainage), there is little reason topermit a life tenant to engage in oil and gas exploration.235 Accordingly,the oil and gas industry should not anticipate that a court will permit a lifetenant to unilaterally authorize seismic exploration.236 However, the lifetenant does control direct access (and may, in the proper case, have a dutyto permit access to prevent waste).

Regarding cotenant remaindermen, they should have the same rights,with respect to each other as cotenants in possession. Accordingly, as inthe case of oil and gas lessees, geophysical operators will ordinarily haveto deal with both the life tenant and one cotenant remainderman. In mostinstances, this should not be overly burdensome.

[e] — Mineral Ownership Divided By Depth.Occasionally, mineral rights are horizontally severed. For example,

one party may own the “shallow” development rights, and another interestowner may own the “deep” rights. Horizontal severance raises the questionof whether a party wishing to engage in geophysical operations must havepermission from both the shallow owner and the deep owner. Since thedeep-rights owner has the implicit right to drill through the shallowstrata,237 it necessarily follows that the deep-rights owner can “shoot”seismic through the shallow strata. Nevertheless, one commentator has

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suggested that a cautious geophysical operator “should consider blockingout any unpermitted shallow data not essential to its interpretation of thedeep structures.”238 Then, citing Phillips Petroleum Co. v. Cowden239 asanalogous authority, the commentator suggests that the shallow-rights ownerhas no right to gather and interpret data concerning the deep rights. I haveno quarrel with his advising cautious geophysical operators to block outdata obtained from “unpermitted” strata. However, I submit that a horizontalseverance situation is more analogous to Kennedy v. General GeophysicalCo.,240 wherein the court acknowledged that the incidental gathering ofinformation regarding lands adjacent to the targeted lands does not constitutea geophysical trespass of the adjacent lands.

Because I will argue that the gathering of information regarding adjacentand nearby lands should be lawful,241 I also conclude that both shallow-rights owners and deep-rights owners should be free to gather geophysicalinformation from all depths. In other words, the owner of a horizontallysevered interest should assume the risk that owners of other strata maygather geophysical information from all depths. A contrary rule is toodifficult to enforce, unnecessarily increases transactions costs, and causeswaste to the extent that gathered data from a “non-permitted” formationwould have to be purged from the geophysical operator’s database.242

Owners of horizontally severed interests who do not like my suggestedassumption-of-the-risk rule could specifically contract around it.

[f] — Mineral Ownership Divided By Substance.Where ownership of the mineral estate has been divided by substance

(e.g., Able owns the oil and gas rights, and Baxter owns the coal rights),243

238 Blomquist, supra note 130 at 42.239 Id. at 42, citing Phillips Petroleum Co. v. Cowden, 241 F.2d 586, 7 O&GR 1291(5th Cir. 1957).240 Kennedy v. General Geophysical Co ., 213 S.W.2d 707 (Tex. Civ. App. 1948, writref’d n.r.e.).241 See infra § 11.04[3][h][7].242 I further develop my views infra § 11.04[3][h][7].243 Throughout the West, oil and gas rights and coal rights are often under separateownership. In the Texas Panhandle, oil rights and gas rights are often under separate

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the objective of the exploring party (whether in search of oil and gas orcoal) should determine the party from whom permission must be secured.In general, the owner of each right has the concurrent right to explore andproduce their respectively owned substances and, if necessary, can passthrough244 and even utilize the other party’s substance.245 Recognize,however, that exploration activities (e.g., wildcat drilling for oil or gas)could incidentally reveal the presence or absence of other substances (e.g.,coal).246

In this and similar instances, I submit that the coal owner (or oil andgas owner) should assume the risk that other lawfully conducted activitiescould result in the loss of the speculative value of the property for coal (oroil and gas) development. Moreover, such a loss should not give rise to acause of action unless the acquiring party intentionally disclosed suchinformation to prospective coal developers where disclosure was notrequired by law.247 A more liberal recognition of a cause of action wouldbe inefficient and invite strategic behavior by both oil and gas owners andcoal owners in the negotiation of exploration permits. Again, owners whodo not like my view could specifically contract around it.

The Colorado Supreme Court issued a ruling consistent with my views.In Mallon Oil Company v. Bowen/Edwards Associates, Inc.,248 the court

ownership. See, e.g., Amarillo Oil Co. v. Energy-Agri Products, Inc., 794 S.W.2d 20, 21109 O&GR 524 (Tex. 1990).244 See, e.g., Chartiers Block Coal Co. v. Mellon, 25 S. 597, 599 (Pa. 1893).245 NCNB Texas Nat’l Bank, N.A. v. West, 631 So. 2d 212 (Ala. 1993).246 Likewise, the exploration and development of coal resources may often reveal thepresence of commercially recoverable coal-bed methane gas, thereby triggering a disputeover the ownership of the gas. See, e.g., Amoco Production Co. v. Southern Ute IndianTribe, 526 U.S. 865 (1999); NCNB Texas Nat’l Bank, N.A. v. West, 631 So. 2d 212 (Ala.1993); and United States Steel Corp. v. Hoge, 468 A.2d 1380, 79 O&GR 96 (Pa. 1983).In Sinclair Oil & Gas Co. v. Masterson, 271 F.2d 310, 315, 11 O&GR 632 (5th Cir.1959), cert. denied, 362 U.S. 952, 12 O&GR 586 (1960), the drilling of gas wells by thegas lessee revealed shows of oil which led to litigation over the oil lessee’s duty to explore.247 In many states, core samples from oil and gas wells must be submitted to a publiccore sample library. See, e.g., N.D. Cent. Code § 38-08-04(1). See also, Grynberg v. Cityof Northglenn, 739 P.2d 230, 95 O&GR 28 (Colo. 1987), discussed supra § 11.04[3][b].248 Mallon Oil Co. v. Bowen/Edwards Assoc., Inc., 965 P.2d 105 (Col. 1998), en banc.

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249 Id. at 110.250 Id. at 112.251 That issue was subsequently decided against the tribe in Amoco Prod. Co. v. SouthernUte Indian Tribe, 526 U.S. 865 (1999).252 See, e.g., Musser Davis Land Co. v. Union Pacific Resources, 201 F.3d 561, 562 (5thCir. 2000); Yates v. Gulf Oil Corp., 182 F.2d 286, 291 (5th Cir. 1950)(construing Texaslaw). For a detailed discussion of this topic see Annot. 29 A.L.R.3d 1426.253 29 S.W.2d 809 (Tex. Civ. App. 1930). See also, Mustang Production Co. v. Texaco,Inc., 549 F. Supp. 424, 74 O&GR 462 (D. Kan. 1982), aff ’d, 754 F.2d 892 (10th Cir.1985) and Roye Realty & Developing, Inc. v. Southern Seismic, 711 P.2d 946 (Okla.App. 1985). In Ready v. Texaco, Inc., 410 P.2d 983, 986-987, 24 O&GR 521 (Wyo. 1966),

held that a geologist, who was working for the coal owner, did not commita geophysical trespass against an oil and gas lessee by testing the coalreserves for the presence of coalbed methane gas because the testing ofcoal for coalbed methane gas was viewed as “incidental” to the Tribe’sright to explore for coal.249 Moreover, the court held that a party wholater employed the geologist and acquired the results of the testing whichshowed that the coal contained commercial quantities of coalbed methanegas did not have to disclose this information to the oil and gas lesseewhen purchasing the lessee’s interest.250 Interestingly, the court reachedits holdings without expressly addressing the issue of ownership of thecoalbed methane gas.251

[g] — Minerals Under Lease or OtherAgreement.

If the property is subject to an oil and gas lease, the lessee willordinarily have the implied right to engage in geophysical exploration.252

In most modern leases, this right will be expressly conferred. However,in the absence of an express lease provision granting the exclusive rightto explore to the lessee, the lessor may retain a concurrent right toexplore.253 For example, in Shell Petroleum Corp. v. Puckett, a lesseewas denied recovery for an alleged geophysical trespass because the leasegranting clause, which conferred access to the leasehold “for the soleand only purpose of mining and operating for oil and gas . . . ,” did notexpressly grant the “exclusive” right to explore.

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the Wyoming Supreme Court held that a lessee, under a federal oil and gas lease (andunder a State of Wyoming oil and gas lease), does not have the exclusive right to explore.

This matter is a bit muddled in Louisiana. In Lloyd v. Hunt Exploration, Inc., 430So. 2d 298 (La. App. 3d Cir. 1983), the court stated that the landowner retains the rightto protect the property against a seismic trespass even when the property is subject to anoil and gas lease. In Lloyd, the seismic operator had obtained permission from the oiland gas lessee; however, the lessee’s permission expressly required the seismic operatorto obtain from the surface owners “all additional approvals . . . which may be necessary.”Id. at 300. The court appears to have cited this provision solely to indicate the lessee’sunderstanding of Louisiana law because the court’s holding seems to be based on ageneral Louisiana statute that allows landowners to protect their mineral rights againsttrespass. La. Rev. Stat. Ann. § 30:12. Another Louisiana trespass statute expresslyprohibits geophysical surveying without permission of “owner of the party or partiesauthorized to execute geological surveys, leases, or permits . . . .” La. Rev. Stat. Ann. §30: 217. Under this statute, “owner” is defined as not including a mere surface owner orsurface lessee—language inserted by amendment to moot Jeanes v. G.F.S. Company,647 So. 2d 533, 535 (La. App. 3d Cir. 1994), cert. denied, 650 So. 2d 255 (La. 1995). Afederal district court, citing Lloyd, ruled that this statute prohibited an oil and gas lesseefrom conducting seismic operations without the specific consent of the “owner,” includingthe consent of a lessee’s own lessor. In reaching this conclusion, the court reasoned thatthe right to conduct seismic operations is not an implied right emanating from the generalright of a lessee to explore and develop the leased premises under the oil and gas lease.Moreover, the court ruled that seismic data collected without this requisite permissionbelongs to the “owner,” not the lessee. Thus, the lessee was barred from selling ordisseminating the seismic data to third parties. Musser-Davis Land Co. v. Union PacificResources, Civ. No. 98-0407 (W. D. La. 1998). Fortunately, this case was reversed on allpoints on appeal. Musser Davis Land Co. v. Union Pacific Resources, 201 F.3d 561 (5thCir. 2000). The court of appeals concluded that seismic exploration is a generally acceptedexploration practice that was encompassed in the right to explore as conferred by thegranting clause of the lease. The court expressly rejected the lessor’s argument that thefact that the lessee had sought specific permission demonstrated that lessee did not havepermission to conduct seismic activities under the lease. In response, the court notedthat it was standard industry practice to seek such permission as a means of notifyingthe lessor of impending seismic activities.

Because oil and gas lessees desire the exclusive right to explore,modern oil and gas leases commonly expressly provide that the lesseeacquires the exclusive exploration right. Where the exploration right is“exclusive” to the lessee, the lessor cannot lawfully authorize a third party

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254 See, e.g., Wilson v. Texas Co., 237 S.W.2d 649 (Tex. Civ. App. - Fort Worth, 1951,writ ref ’d n.r.e.). In Tinsley v. Seismic Explorations, 117 So. 2d 897, 12 O&GR 76 (La.1960), the court assumed, but did not decide, that the lessee had the exclusive right toexplore; however, the court denied any recovery against a seismic operator who hadentered the property with the lessors’ permission on the ground that the lessee failed toprove any actual compensable damages. For a discussion of surface-related exploration,see supra § 11.07[3][b].255 See, e.g., Moity v. Petty-Ray Geophysical, Inc., 369 So. 2d 225, 65 O&GR 503 (La.App. 1979) and Wilson v. Texas Co., 237 S.W.2d 649 (Tex. Civ. App. - Fort Worth, 1951,writ ref ’d n.r.e.)(denying landowner the right to recover for geophysical trespass wherethe property in question had been leased under granting clauses that conferred the“exclusive right to . . . explore”; however, the landowner did not seek recovery for surfacedamages and use).256 Cf., Wilson v. Texas Co., 237 S.W.2d 649 (Tex. Civ. App. - Fort Worth, 1951, writref ’d n.r.e.)(denying recovery) and Thomas v. Texas Co., 12 S.W.2d 597, 598 (Tex. Civ.App. - Beaumont 1928, no writ)(dicta suggesting that recovery is possible).257 See infra § 11.04[3][7].

to engage in exploration.254 Nevertheless, if a geophysical trespass occursand the lessee holds the “exclusive” exploration right, the surface ownercould still recover for any surface damage,255 and the oil and gas lessormay be able to recover for any resulting loss in value to the retained royaltyinterest and underlying mineral interest.256

The lessee’s right to explore, whether implicit, explicit, or exclusive,is limited by the scope of the lessee’s general operational rights. In thisregard, I raise two concerns:

First, a lessee’s right to use the surface of the leasehold is generallylimited to exploration and development of the leased property, notadjoining property. This concern will be discussed later.257

Second, a lessee is entitled to engage in operations that relate to themutual and underlying objectives of the lessor and lessee: i.e., to engagein all activities reasonably necessary to the lessee’s development of oiland gas on the leasehold. When pursuing the underlying lease objectives,the lessee (or its successors) would necessarily have the right to explore.However, the lessee may not have the sole authority to authorize ageophysical operator to do a “speculative survey” for licensing to thirdparties if the results are not shared with the lessee. Although no case law

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directly addresses this particular situation, a court may view such a surveyas beyond the scope of the lessee’s rights. Arguably, this type of shoothas no relation to the lease objectives. Accordingly, a prudent lessee shouldrequire the geophysical operator to either share the information or obtainthe consent of the lessor. Likewise, if the information is not shared withthe lessee, a prudent geophysical operator should acquire the consent ofthe lessor as well as the consent of the lessee.

A related concern could be raised about a lessee who conducts seismicexploration of a particular leasehold, then lets the lease expire, and latersells the seismic information to a third party. Here, however, because thelessee owns the seismic data,258 I submit that the lessee should bepermitted to sell the information. The lessee would argue that it hadacquired the seismic information in fulfillment of the lease objectivesand sold the information in an effort to recoup some of its sunk costs.

Cotenant lessees should ordinarily be treated the same as cotenantmineral owners regarding mineral exploration.259 However, if variouslessees (or other working interest owners) have entered into a miningpartnership, a joint venture, a joint operating agreement, a voluntarypooling or unitization agreement, the terms of such agreements shouldbe consulted to determine whether the parties may have addressedexploration.260 And in the case of compulsory pooling or unitization, theterms of all relevant conservation orders and underlying agreements should

258 Musser Davis Land Co. v. Union Pacific Resources, 201 F.3d 561, 570 (5th Cir.2000).259 See supra § 11.04[3][c]. In Louisiana, however, the practice is to secure consentfrom all cotenant lessees from a single mineral servitude.260 The typical operating agreement does not address geophysical exploration. See,e.g., American Association of Petroleum Landmen, Form 610-Model Form OperatingAgreement (1982).

A typical unit agreement unitizes all oil and gas rights (including the right to explore)and governs all unit operations regarding the unitized substances produced from theunitized formation within the unit area. See, e.g., American Petroleum Institute, ModelForm of Unit Agreement art. 1.1,.1.2, 1.3, 1.14, and 3.1. The unit operator has the exclusiveright to conduct unit operations. Id. at art. 4.1. Accordingly, the typical unit agreementwould not govern the exploration of non-unitized substances or formations.

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261 Whether a fiduciary duty is owed is beyond the scope of this article. For moreinformation regarding an operator’s duty to nonoperators, see, e.g., Howard L. Boigan,“Liabilities and Relationships of Co-Owners Under Agreements For Joint Developmentof Oil and Gas Properties,” 37 Oil & Gas Inst. 8-1 (1986) and Ernest E. Smith, “Dutiesand Obligations Owed by an Operator to Non-Operators, Investors, and Other InterestOwners,” 32 Rocky Mtn. Min. L. Inst. 12-1 (1986).262 Frankfort Oil Co. v. Snakard, 279 F.2d 436, 442 (10th Cir.).263 Id. at 443.

be consulted; however, many of these agreements and orders are likelyto be silent on the matter of exploration.

Finally, “operators” under these types of agreements or orders shouldbe alert to the issue of whether exploration information must be sharedwith nonoperators because of a possible fiduciary duty owed by theoperator to nonoperators.261 Only one reported case, Frankfort Oil Co.v. Snakard,262 deals with seismic surveying in this context. Although thecourt found that the operator owed a fiduciary duty to the non-operator,the operator did not have to share seismic data with the non-operatorbecause their written agreement did not require the sharing of suchinformation.263

[h] — The Exploration of Adjacent and NearbyTracts—(and Brief Sidebar on AerialSurveying).

[i] — The Basic Problem.For 3D seismic operations to accurately image a structure, such as

an anticline or dome, seismic data must be gathered from alongside thestructure. In these situations, if either the surface or mineral ownershipfor the acreage alongside the structure differs from the acreage above thestructure, special trespass concerns are encountered. Consider thefollowing hypothetical problem:

Assume that the targeted area for 3D seismic operations is ageologic dome located largely beneath Blackacre, and that thebest way to image this dome is to conduct the geophysicaloperations from nearby Whiteacre. Assume that Baker owns the

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264 See supra § 11.04[3][a].265 Id.266 It is well established that the surface estate is burdened by the mineral owner’sright of reasonable and necessary use of the surface. See, e.g., Hunt Oil Co. v. Kerbaugh,283 N.W.2d 131 (N.D. 1979)(dealing with seismic operations). However, a mineralowner’s right of surface use is limited to uses that directly relate to the exploration anddevelopment of minerals beneath the burdened tract. This right does not include the useof the surface in furtherance of exploration and development of minerals on other tracts,unless the severance instrument specifically confers such right. See e.g., Mountain FuelSupply Co. v. Smith, 471 F.2d 594 (10th Cir. 1973).267 Kennedy v. General Geophysical Co., 213 S.W.2d 707, 709 (Tex. Civ. App. -Galveston 1948, writ ref ’d n.r.e.).

surface estate and Baxter owns the mineral estate of Blackacre,and assume that Walsh owns the surface estate and Wilson ownsthe mineral estate of Whiteacre. From whom must permission toengage in geophysical operations be obtained?

Conventional wisdom suggests that permission should be obtainedfrom Baxter and Wilson. Baxter is the owner of the targeted minerals.Thus, to recover data on the dome beneath Blackacre, a prudentgeophysical operator would secure Baxter’s consent.264 Further, becausegeophysical equipment will be placed directly above Wilson’s mineralrights in Whiteacre, existing case law requires that permission be securedfrom Wilson.265 And, if obtaining information about Whiteacre is not anobjective of the survey (e.g., because the operator already knows, from a2D seismic survey, that the dome is not beneath Whiteacre), thenpermission must also be obtained from Walsh because Wilson’s right touse the surface of Whiteacre is most likely limited to exploring for anddeveloping minerals beneath Whiteacre (not Blackacre). With theexception of the clear need to obtain permission from Walsh, the surfaceowner, if Whiteacre is not an objective of the survey,266 this subsectionwill re-evaluate this conventional wisdom.

Advocates on either side of this permission issue would most likelycite the same case law in support of their positions. Based upon a Texascase, Kennedy v. General Geophysical Co.,267 one could argue that

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268 Ratliff v. Beard, 416 So. 2d 307, 73 O&GR 532 (La. App. 1982), writ denied, 422So. 2d 154 (La. 1982).269 Kennedy v. General Geophysical Co., 213 S.W.2d 707, 709 (Tex. Civ. App. -Galveston 1948, writ ref ’d n.r.e.).270 Id.271 Whether an operator would obtain useful information in such a case depends uponthe purpose for locating the shot points and receivers adjacent to a plaintiff’s property.For example, to obtain sufficient fold for making dynamic and static corrections in acorner or at the boundary of an area, gathering of seismic data must extend beyond thecorner or boundary. Nevertheless, little or no useful information is obtained as to thesubsurface beyond the corner or boundary. Moreover, migrated seismic only yields usefulinformation covering a smaller area than the area from which the raw seismic data areinitially gathered.272 Id. at 709-713.

geophysical trespass requires a physical surface entry by the geophysicaloperator within the boundaries of the land at issue. This same propositioncan be surmised from a Louisiana case involving aerial surveying.268

Further, the court in Kennedy stated that gathered data could be used toextrapolate the geology of adjacent acreage without liability.269 Moreover,the court held that a subsurface concussion, caused by geophysicalsurveying, is not actionable in the absence of a physical invasion or anactual injury to the adjacent land.270

In Kennedy, the geophysical operator did not enter upon the plaintiff’sadjacent acreage at issue, but the operator did place shot points andreceivers along a public road that was adjacent to this acreage. Althoughthe court held that the defendant was not liable, the court, in dictum,emphasized the facts that the operator had made no physical entry ontothe plaintiff’s acreage and had not disclosed any information about theplaintiff’s acreage to its principal (Skelly Oil Company). Moreover, thecourt noted that the plaintiff failed to prove that the surveyor obtainedany valuable or useful information about the acreage at issue271 and thatno receivers and shot points were placed so that a straight line connectinga shot point and receiver would cross the plaintiff’s acreage. Moreover,the land was not physically injured in any way by concussion.272

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273 A similar view can be surmised from dicta in Ohio Oil Co. v. Sharp, 135 F.2d 303,306 - 309 (10th Cir. 1943)(involving an allegation of geophysical trespass, but mineralowners were not parties to the suit).274 Phillips Petroleum Co. v. Cowden, 241 F.2d 586, 590, 7 O&GR 1291 (5th Cir.1957)(construing Texas law).275 Humble Oil & Refining Co. v. Kishi, 276 S.W. 190 (Tex. Comm’n App. 1925,judgm’t adopted). Kishi was distinguished in Byrom v. Pendley, 717 S.W.2d 602, 605, 93O&GR 419 (Tex. 1986).

Thus, the court’s dictum suggests that if valuable and useful informationhad been intentionally gathered from beneath the plaintiff’s acreage, theplaintiff might have prevailed.273 Although most commentatorsacknowledge that no physical trespass occurred, most argue that a causeof action should exist in this situation on a variety of theories. These includeassumpsit for the reasonable value of the exploration right, loss ofspeculative value, wrongful acquisition of a trade secret, ormisappropriation of the right to explore. No appellate court, however, hassquarely ruled that a tort has occurred in the context of facts similar to myhypothetical problem.

[ii] — Assumpsit.Regarding assumpsit, in Phillips Petroleum Co. v. Cowden,274 the Court

of Appeals for the Fifth Circuit held that a mineral owner who had suffereda direct geophysical trespass could waive the tort of trespass and sue inassumpsit for the reasonable value of the exploration right. While thiscase provides authority for recovery on an assumpsit theory, it providesno authority for a cause of action concerning the indirect acquisition ofseismic data through the use of nearby lands.

[iii] — Loss of Speculative Value.Regarding loss of speculative value, the landmark case is Humble Oil

& Refining Company v. Kishi.275 In this case, Humble, acting presumablyin good faith, erroneously contended that it had a valid and subsistinglease from Kishi. Humble entered upon Kishi’s property and drilled a dryhole. Because Kishi’s cotenant lessor consented to Humble’s entry, Humblewas not a trespasser. Nevertheless, Kishi was allowed to recover because

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276 On second motion for rehearing, the court agreed to remand the case to determinewhether an undivided 3/4 interest in land should be reasonably expected to receive alease bonus equal to 3/4 of the bonus that would be paid for a full interest lease. HumbleOil & Refining Co. v. Kishi, 291 S.W. 538 (Tex. Comm’n App. 1927).277 American Surety Co. v. Marsh, 293 P. 1041 (Okla. 1930).

Humble had wrongfully asserted that it had a valid lease from Kishi.Although Kishi did not prove loss of a specific bargain, the court awardedKishi the loss of speculative value measured by the difference betweenthe lease bonus value of Kishi’s interest immediately before andimmediately after the drilling of the dry hole.276

A similar conclusion was reached in American Surety Co. v. Marsh.277

As a result of defendant’s wrongful claim that it held a valid lease onplaintiff’s land and the drilling of a dry hole on adjacent land during thecourse of defendant’s wrongful claim, plaintiff lost a specific bargain toissue a new lease. The court granted damages for loss of speculative valuemeasured by the plaintiff’s loss of a specific bargain. In Marsh, there wasno physical trespass or other entry onto the plaintiff’s property; however,in both Marsh and Kishi, the defendant wrongfully claimed to hold avalid lease from the plaintiff.

Both Kishi and Marsh are factually distinguishable from my seismichypothetical problem. First, both cases involved the drilling of a dry hole,not geophysical operations. Second, in Kishi, Humble physically enteredthe disputed acreage, while in my hypothetical problem, there is nophysical entry onto Blackacre. Third, the defendants in both Kishi andMarsh wrongfully asserted that they had a valid lease to the acreage,while in my hypothetical problem, there is no wrongful assertion of aninvalid interest in Blackacre. Fourth, in Marsh, the plaintiff proved theloss of specific bargain. These distinctions, however, are not critical. Thereal distinction lies in the basic underlying issue in my seismic problem:whether a geophysical operator needs to secure permission from Baxterto conduct geophysical operations on Whiteacre that target Baxter’smineral rights in Blackacre.

Cases concerning recovery for loss-of-speculative value do not addressthis question. Courts have awarded damages for the loss of speculative

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278 See, Phillips Petroleum Co. v. Cowden, 241 F.2d 586, 593, 7 O&GR 1291 (5th Cir.1957)(construing Texas law and finding liability based upon a theory of assumpsit) andAngelloz v. Humble Oil & Refining Co., 199 So. 656, 658 (La. 1940).279 Christiansen supra note 130. Because the author speaks of a remedial gap whereseismic data are gathered without physical entry on the plaintiff’s land, the note implicitlyviews such conduct as wrongful.280 In Laird v. Amoco Prod. Co., 622 N.E.2d 912 (Ind. 1993), the defendants acquireda map of an oil prospect from a disgruntled employee of the plaintiff. The plaintiff hadidentified this prospect by means of a microwave radar survey and had taken steps toassure the confidentiality of the information. The court held that plaintiff was entitled toprotect this information as a trade secret. In Pre-Cam Exploration & Development Ltd.v. McTavish, [1966] S.C.R. 551, the Supreme Court of Canada held that a defendant,hired to do exploration work for purposes of acquiring additional mining claims withinan area, breached a fiduciary duty when defendant used the information to acquirefavorable claims nearby the plaintiff ’s area of interest. In Lac Minerals Ltd. v.International Corona Resources Ltd., 61 D.L.R. (4th) 14 (S.C. Can. 1989), the courtimposed a constructive trust on property acquired by a mining company as a result of its

value where there has been an actual physical trespass onto the plaintiff’sacreage by a geophysical operator.278 Accordingly, if it were wrongful tointentionally gather geophysical information from Blackacre without theBaxter’s permission by operations conducted on Whiteacre, an award forloss of speculative value or other appropriate relief would logically follow.Moreover, if Baxter had denied the geophysical operator permission tomake a direct entry, some courts might even entertain an award ofexemplary damages if this conduct is viewed as wrongful. The thresholdissue, however, is whether it is “wrongful” to intentionally gathergeophysical information from Blackacre without Baxter’s permission bymeans of seismic operations conducted on Whiteacre. The cases onspeculative value do not directly address this issue.

[iv] — Trade Secrets.An informative student note suggests that principles underlying trade-

secret law could be used to fill the “remedial gap” where seismic datafrom a plaintiff’s acreage are gathered by a geophysical operator fromadjacent or nearby lands without the plaintiff’s permission.279 While thewrongful acquisition or use of confidential seismic data and interpretationswould undoubtedly violate trade-secret law,280 no court has expressly

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viewing of confidential data belonging to a small mining company that was soliciting ajoint venture partner to assist it in acquiring this same property.281 The Supreme Court of Colorado refused to find that a trade secret had beenmisappropriated in the drilling of an unauthorized test hole that revealed unfavorableinformation about the presence of recoverable coal because other publicly availableinformation concerning the amount of coal beneath the property was already available sothat the plaintiff’s “access to the information [concerning the coal deposits] was notsufficiently exclusive to qualify as a trade secret . . . .” City of Northglenn v. Grynberg,846 P.2d 175, 184, n. 17 (Colo. 1993). The court prefaced this conclusion by stating that“we do not decide here whether geophysical information in general may or may not be a‘trade secret.’ ” Id.282 Christiansen, supra note 130 at 908.283 Restatement of Torts § 747 (1939).284 E. I. duPont de Nemours & Co. v. Christopher, 431 F.2d 1012, 1015 (5th Cir. 1970).285 See also, Restatement of Unfair Competition § 43, comment, illustration 3 at 494-95 (illustrating the basic facts in Christopher as an example of conduct that would beactionable).

held that the initial wrongful gathering, creation, processing orinterpretation of seismic data by geophysical operations constitutes theunlawful acquisition of a trade secret.281 In this latter context, becausethe plaintiff is more interested in protecting her exclusive right to gaininformation about the mineral content of the property (rather than inpreventing physical injury to the property), the argument is that trade-secret law provides a more appropriate remedy than trespass.282

Courts may determine whether a party has wrongfully appropriated atrade secret based upon whether the acquiring party has violated “generallyaccepted standards of commercial morality and reasonable conduct.”283

For example, in E. I. duPont de Nemours & Co. v. Christopher,284 theFifth Circuit Court of Appeals concluded that a trade secret had beenwrongfully acquired when defendant’s agent took aerial photographs of aplant construction site to gain information about a special process that theplant owner had developed as a trade secret. The fact that the photographshad been taken from an airplane flying within public airspace was deemedirrelevant. Rather, the court’s decision turned on the defendant’s deviousconduct in acquiring a trade secret that the plaintiff had no practical meansof concealing during the course of plant construction.285

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286 See, e.g., Blomquist, supra note 130 at 33; and Christiansen, supra note 130 at 910.287 See, e.g., Uniform Trade Secrets Act § 1(4)(1985)(defining a trade secret) andRestatement of Torts, § 757 (1939)(defining a trade secret). The Uniform Act displacesan adopting state’s common law regarding tort claims, but not contract claims. UniformTrade Secrets Act § 7 (1985). See also, Restatement of Unfair Competition § 39 (definingtrade secret as valuable and secret information that can be used in the operation of abusiness or other enterprise). See generally, Ame´de´e E. Turner, Law of Trade Secrets12 - 13 (1962).288 See infra § 11.04[h][7].

While Christopher has been cited by commentators as analogous tothe situation posed in my hypothetical problem,286 I submit thatChristopher is neither particularly helpful nor relevant to the question ofwhether mineral owners have the right to protect the geology of theirsubsurface from discovery by means of operations from nearby lands.One difference lies in the threshold issue of whether the geology of atract can qualify as a trade secret. In Christopher, the plaintiff haddeveloped a particular processing technique that it had carefullysafeguarded from discovery. In the mineral exploration context, the plaintiffmineral owner (Baxter, in my seismic problem) has neither discoverednor developed anything. Indeed, intellectual property is not involved. Inessence, to prevail, Baxter would have to successfully argue that Baxterhas the exclusive right to obtain information that Baxter wishes to keepsecret – information that is so secret that Baxter does not even know whatthe secret is! In other words, Baxter is trying to prevent unknowninformation from becoming known information. While trade-secret lawwill protect a valuable secret known by one who wishes to keep it a secret,I submit that trade-secret law does not contemplate protecting against theacquisition of information that is unknown.287 Although in some contexts“ignorance is bliss,” it should not be protected as intellectual property.Moreover, commentators who have advocated trade-secret law as a remedyfor geophysical “trespass” do so on the assumption that the gathering ofinformation about Blackacre by geophysical operations on Whiteacre isinherently “wrongful.” My disagreement with this fundamental assumptionwill be discussed below.288

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289 University Computing Co. v. Lykes-Youngstown Corp., 504 F.2d 518, 536 (5th Cir.1974).290 S. Chesterfield Oppenheim, et al., Unfair Trade Practices and Consumer Protection315 - 16 (4th ed. 1983).291 A magnetic survey, which measures the strength of the earth’s magnetic field anddetects variations in the magnetic susceptibility of rocks, is used in oil and gas explorationto locate structures and to determine the depth of basement rocks. A surface magneticsurvey provides more information than an airborne survey. See Norman J. Hyne,Dictionary of Petroleum Exploration, Drilling & Production 304 (PennWell 1991).

Although I conclude that geophysical trespass does not qualify as thewrongful acquisition of a trade secret, the various measures of damagesused in trade secret law are instructive of the type of relief a court mightconsider in the case of geophysical trespass. For wrongful acquisition ofa trade secret, damages, inter alia, may be measured by value of the secretto the plaintiff where the defendant has destroyed its value by publication(cf., where geophysical trespasser publishes the information); by the lossof a specific bargain where the defendant has not published the secret;and by the reasonable value of the benefits derived by the defendant inusing the secret where the plaintiff has suffered no specific injury.289

Equitable relief may include enjoining the use or disclosure of the secret;imposing a constructive trust; granting an accounting; and compellingthe defendant to surrender the information that comprises the secret.290

[v] — The Related Problem of AerialSurveys.

The facts in Christopher are closer to the problem of aerial mineralexploration, such as an aerial magnetic survey.291 While aerial mineralexploration is beyond the scope of this article, a brief discussion of thepropriety of such surveying is in order. While most commentators haveargued that a mineral owner should have an exclusive right to controlgeophysical operations, little commentary has been offered regardingaerial magnetic surveys. Based upon the reasoning of most geophysicalcases (that the right of exploration is a valuable property right that thelaw will protect) and upon the reasoning in Christopher (that aerialphotography can be wrongful if it violates generally accepted standards

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292 See also, United States v. Causby, 328 U.S. 256, 261 (1946)(holding that landownerhad suffered a “taking” when aircraft were permitted to fly at such a low altitude that theplaintiff’s chicken farming operations were disrupted).293 And if a geophysical operator cannot use Whiteacre to explore Blackacre withoutBaxter’s (Blackacre’s surface owner’s) permission, logic would seem to dictate that theoperator cannot use Blackacre airspace for the same purpose without Baxter’s permission.294 To whomever the soil belongs, he owns also to the sky and to the depths. See e.g.,Del Monte Mining & Milling Co. v. Last Chance Mining & Milling Co., 171 U.S. 55(1898).295 See also, United States v. Cusumano, 67 F.3d 1497, 1510 (10th Cir. 1995)(holdingthat law enforcement officers must obtain a warrant before scanning a home with athermal imagery used to detect for the possible presence of marijuana greenhouses).

of commercial morality and reasonable conduct), a mineral owner couldargue that a party who engages in aerial magnetic surveying withoutpermission is liable for wrongful exploration.292

Because case law requires a geophysical operator to obtain themineral owner’s permission to engage in direct geophysical operationsinvolving the use and occupancy of the surface overlying the targetedminerals, one could argue that aerial magnetic surveys should be subjectto the same limitation.293 Note that an aerial magnetic survey isdistinguishable from my hypothetical seismic problem in that an aerialsurvey would often, but not always, involve a physical invasion of theairspace overlying the acreage at issue. This distinction arguably bringsthe aerial survey within the venerable common law maxim: Cujus estsolum, ejus est usque ad coelum et ad infersos.294

While the general public may use the public airspace for travel,Christopher suggests that there is no public right to use public airspacefor the purpose of wrongfully acquiring trade-secret information that anowner wishes to keep secret.295 Thus, whether aerial surveying withoutpermission is actionable may turn on whether a person’s right to usenavigational airspace is limited to travel and whether the acquisition ofmineral information via an aerial survey is viewed as a “wrongful”invasion of the mineral owner’s property rights. A court that agrees withChristopher in the context of a true trade secret might distinguish betweenwhat constitutes wrongful conduct in the adventurous world of oil and

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gas wildcatting296 and what constitutes wrongful conduct amongcompeting chemical or manufacturing companies. A court could also makea distinction between exploration via a physical entry onto the surfaceoverlying a plaintiff’s minerals and exploration via a physical entry intothe navigational airspace overlying a plaintiff’s minerals.

Regarding aerial surveying, I submit that the proper approach isbalancing. Should public policy encourage aerial exploration as a meansof promoting more domestic oil development and the lessening of ourcountry’s reliance on foreign oil supplies? Can permission to conductbroad-based aerial surveys be efficiently acquired from all necessarymineral owners, or will transaction costs prove to be too high? As a practicalmatter, would a rule that bars aerial surveys without mineral ownerpermission be enforceable? Can aerial surveys be done safely withoutphysical injury to persons or property? Can mineral owners who wish toprevent aerial surveys do so through the use of safe “blocking” technologythat does not encroach on neighbors? If unauthorized aerial exploration iffound to be actionable, what is the theory of liability, what is the propermeasure of damages, and how could damages be reasonably and reliablydetermined?

On balance, I submit that aerial surveys should be lawful withouthaving to secure permission from affected mineral owners.297 I base myconclusion on the grounds that a rule barring aerial surveys withoutpermission from all affected mineral owners would further discouragedomestic oil and gas activity, would result in very high transaction costsincurred to obtain the necessary multiple permissions, and would be verydifficult to enforce. Moreover, a rule that aerial surveys are wrongful istoo speculative in that it would be based upon a court’s intuition of what

296 Indeed, part of the oil and gas exploration and development business involves thegathering of information about prospective oil and gas plays through the examination ofpublic land records, conservation agency records, and the observation of exploration anddrilling activity.297 But see, Gulf Coast Real Estate Auction Co. v. Chevron Indus., 665 F.2d 574, 577,73 O&GR 98 (5th Cir. 1982)(holding that plaintiff failed to prove the value of theexploration right, but implicitly recognizing a right of protection from unauthorized aerialsurveys).

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is wrongful. Would all aerial surveying be wrongful? If so, even satellitephotography and other forms of satellite imagery would be wrongful. Onthe other hand, if satellite imagery is permissible but aerial magnetic surveysare not, then what about other types of aerial surveys and uses ofairspace?298

[vi] — Misappropriation.In addition to trade-secret law, a few commentators have suggested

that the independent tort of misappropriation might have application tothe wrongful acquisition of geophysical information.299 This tort, whichis an expansion of conversion, has been defined as “the appropriation ofthe fruits of another’s investment of money, time and intellectual effort,”300

such as copying and reselling news stories initially gathered, written anddistributed by another party.301 Efforts to further expand this tort on ageneral “unjust enrichment” theory have largely failed.302 Nevertheless,recovery has been allowed in situations where the defendant’s conducthas destroyed or seriously diminished the plaintiff’s primary opportunity

I am aware of Texas litigation dealing with the propriety of aerial surveying. BGMAirborne Surveys, Inc. v. Coppock, No. 92-CI-13993 (131st Dist. Ct., Bexar County,Tex., filed Oct. 6, 1992). While the trial court dismissed the landowner’s claims on theoriesof trespass, wrongful acquisition of a trade secret, and misappropriation of the explorationright, the court was willing to allow the landowner to pursue relief on other theories. Thecase was settled out of court.

Although he fails to state his personal view on the merits of recognizing a cause ofaction for wrongful aerial surveying, Blomquist does conclude that the recognition ofsuch a cause of action is “inevitable.” Blomquist, supra note 130, at 33.298 For example, would a crop duster who flies over another’s land in making a turnwhile spraying a crop need to have permission to use that airspace to make the turn?Presumably not, but where should the line be drawn?299 See, e.g., Christiansen, supra note 130.300 Charles R. McManis, Unfair Trade Practices 9 (3d ed. 1993).301 A leading case is International News Service v. Associated Press, 248 U.S. 215(1918)(enjoining INS, on the ground of unfair competition, from copying news gatheredby the Associated Press and selling it to INS’ customers).302 Peter B. Kutner & Osborne M. Reynolds, Jr., Advanced Torts 348 (1989).

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303 Id.304 Id.305 See citations, supra note 130.306 But see, Jones & Faber, supra note 130.

to market a product or service.303 Recovery is less likely if the defendanthas improved the product or service or greatly enhanced its value.304

Regarding a seismic survey, a plaintiff mineral owner (such as Baxterin my hypothetical problem) has neither a “product” nor a “service” toprotect. Rather, the mineral owner has title to real property and the rightto exclude trespassers. Moreover, the geophysical defendant has notappropriated any data that the mineral owner has gathered. Rather, thegeophysical defendant has gathered the raw data, processed and interpretedthe data, and produced something of independent value. Finally, theplaintiff mineral owner and the defendant geophysical operator are notbusiness competitors. Accordingly, a plaintiff who seeks recovery againsta geophysical operator under the tort of misappropriation should face anuphill battle.

[vii] — Our “Modest Proposal.”Commentators on “geophysical trespass” reason that the right to

explore is a valuable right that should be protected.305 From this basicpremise, all commentators agree that the gathering of seismic data bydirect entry onto a target parcel (Blackacre) without permission of themineral owner (Baxter) should be regarded as actionable trespass.Moreover, nearly all commentators argue that the intentional gathering ofseismic data from a target parcel (Blackacre) solely through the use andoccupancy of a nearby parcel (Whiteacre) without permission from amineral owner of the target parcel (Baxter) also should be regarded asactionable trespass.306

I agree that the right to explore for minerals is a valuable propertyright and that a mineral owner should have the right to control geophysicaloil and gas operations that involve a direct entry onto or beneath suchowner’s parcel. I submit, however, that a mineral owner (including suchowner’s permittee) should be privileged to use his own tract to gather

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307 Kennedy v. General Geophysical Co., 213 S.W.2d 707, 709 (Tex. Civ. App. -Galveston 1948, writ ref ’d n.r.e.).308 Ohio Oil Co. v. Sharp, 135 F.2d 303 (10th Cir. 1943).

seismic data from another targeted parcel without having to obtainpermission from a mineral owner of the targeted parcel. In other words, Isubmit that the mineral owner of a targeted parcel should have no causeof action when seismic data are gathered from the targeted parcel solelythrough the use and occupancy of nearby parcels. I would not regardsound waves that penetrate a target parcel as a use and occupancy of anearby parcel. Rather, for an actionable trespass, I would require a directphysical entry onto or beneath the target parcel—such as the placing of ageophone on the surface of the target parcel or the drilling of a shot holeon the target parcel. Thus, I reject the argument that the intentionalgathering of seismic data from a targeted parcel solely by geophysicaloperations conducted from nearby lands (and without permission of theowner of the targeted parcel) is wrongful, immoral, unethical, andunreasonable (thereby constituting “geophysical trespass”).

I reach these conclusions even though I concede that the use of 3Dseismic techniques may often result in the gathering of information thatgeophysicists and their principals would regard as valuable, useful, andreliable. I concede that, in Kennedy v. General Geophysical Co.,307 thecourt emphasized, in dicta, that the defendant obtained no valuable oruseful information regarding the plaintiff’s minerals. I further concedethat, in the case of a 3D-seismic survey targeted at a nearby parcel, thatthe gathered information would most likely be very valuable and useful.Nevertheless, in partial response to the dicta in Kennedy, my view issupported in the concurring opinion of Justice Phillips in Ohio Oil Co. v.Sharp:308

I do not think that a geological investigation of a substantial area,conducted from lands rightfully entered, constitutes a trespassupon adjoining land or a wrong against the owner thereof, or ofthe oil and gas rights therein, where there is no actual entry uponsuch adjoining land, although it may disclose geophysical

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information with respect thereto. To hold otherwise would greatlyimpede geological investigations which are essential to thediscovery and development of oil and gas.309

I respectfully submit that this manner of gathering seismic data shouldfall within the venerable rule of capture.

The rule of capture, one of the most fundamental and commonlyunderstood principles of oil and gas law, provides that a mineral ownerwho is lawfully engaged in extracting oil and gas from his property is notliable to his neighbor for any resulting drainage.310 The rule of capturegoverns even though there is evidence of the amount of oil and gas drainedfrom an adjacent parcel.311 In other words, although a mineral interest isa valuable property interest that deserves to be protected from a directsurface312 or subsurface313 trespass and from any resulting conversionof production, a mineral owner has no cause of action against a neighborwho drains oil and gas from a common reservoir through a well bore

309 Id. at 310.310 See, e.g., Kelly v. Ohio Oil Co., 49 N.E. 399 (Ohio 1897). For a thorough discussionof the continuing vitality of the rule of capture, see Phillip Wm. Lear, Thomas A. Mitchell,and William R. Richards, “Modern Oil and Gas Conservation Practice: And You Thoughtthe Rule of Capture Was Dead?,” 41 Rocky Mtn. Min. L. Inst. 17-1 (1995).311 See, e.g., Edwards v. Lachman, 534 P.2d 670, 673, 51 O&GR 343 (Okla. 1974).And the rule of capture implicitly governs situations where substances injected intoformations for enhanced recovery displace oil and gas from beneath neighboring lands—at least where the neighbor was given a reasonable opportunity to participate in theenhanced recovery operations, but refused. See, e.g., Syverson v. North Dakota StateIndustrial Comm’n, 111 N.W.2d 128, 133, 15 O&GR 478 (N.D. 1961). While the lawcould require a geophysical operator to first make a reasonable effort to obtain permissionto conduct seismic operations from mineral owners of all targeted parcels, I see no basisfor this burdensome and inefficient requirement in the context of geophysical operationsgiven that this same operator could proceed to freely capture any oil and gas beneathtargeted parcels by drainage. Moreover, in the case of injected substances, such as water,a physical substance intrudes into neighboring parcels and may remain there indefinitely.In the case of seismic, only vibrations and sound waves momentarily enter neighboringparcels.312 See, e.g., Swiss Oil Corp. v. Hupp, 69 S.W.2d 1037 (Ky. 1934).313 See, e.g., Alphonzo E. Bell Corp. v. Bell View Oil Syndicate, 24 Cal. App. 2d 587,76 P.2d 167 (1938).

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located wholly within such neighbor’s property boundaries. In addition,if a mineral owner drills several dry holes, thereby reducing the speculativevalue of surrounding lands, that owner is not liable to neighbors for anyresulting loss of speculative value.

The rule of capture implicitly governs situations where substancesinjected into formations for enhanced recovery displace oil and gas frombeneath neighboring lands—at least where the neighbor was given areasonable opportunity to participate in the enhanced recovery operations,but refused.314 While the law could require a geophysical operator to firstmake a reasonable effort to obtain permission to conduct seismic operationsfrom mineral owners of all targeted parcels, I see no basis for thisburdensome and inefficient requirement in the context of geophysicaloperations given that this same operator could proceed to freely captureany oil and gas beneath targeted parcels by drainage. Moreover, in thecase of injected substances, such as water, a physical substance intrudesinto neighboring parcels and may remain there indefinitely. In the case ofseismic, only vibrations and sound waves momentarily enter neighboringparcels.

Accordingly, I submit that the gathering of seismic data by a mineralowner (or such owner’s permittee) through geophysical operationsconducted on such owner’s parcel and concerning the possible presenceof oil or gas beneath a neighbor’s parcel should be privileged under therule of capture.315 In other words, such operations should be treated nomore restrictively than the drilling of a producing well that drains oil orgas from a neighbor’s parcel or the drilling of a dry hole that causes aneighbor’s parcel to suffer a decline in speculative value.

Applying the rule of capture to my hypothetical seismic problem wouldyield the following answer. Because Wilson may drill a producing well

314 See, e.g., Syverson v. North Dakota State Indus. Comm’n, 111 N.W.2d 128, 133, 15O&GR 478 (N.D. 1961).315 To date, no reported case has either accepted or rejected my argument; however, aTexas trial court granted summary judgment based upon a motion and brief that reliedupon and cited my argument. Villarreal v. Grant Geophysical, Inc., No. DC-00-214,220th Judicial District, Starr County, Texas, July 20, 2002 (appeal pending).

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316 This rule-of-capture argument is also endorsed in Jones & Faber supra note 130 atJ-10 and J-11, and implicitly endorsed in Summer supra note 130 at § 662, p. 148.

Note that Wilson, as mineral owner, may make any reasonable and necessary use ofthe surface of Whiteacre for exploration of that portion of the reservoir that is beneathWhiteacre. The fact that information is simultaneously gathered about nearby parcelsshould not, by itself, be viewed as exceeding the permitted scope of surface use. Surely,a severed mineral owner who drains oil from beneath nearby tracts under the rule ofcapture does not exceed the lawful scope of surface-use rights. If, however, Wilson (orWilson’s geophysical permittee) used Whiteacre solely for the purpose of gatheringinformation about Blackacre, or if Wilson used more of the surface of Whiteacre thanwas reasonably necessary to explore Whiteacre (e.g., to gather information aboutBlackacre), then such use (in the absence of an express provision in the severanceinstrument) would exceed the scope of Wilson’s surface-use rights. This matter is furtherdiscussed below.317 The principle that one may use land to gain economically valuable information

about a neighbor’s land has been recognized in other contexts. See, e.g., Victoria ParkRacing & Recreation Grounds Co. Ltd. v. Taylor, 58 C.L.R. 479 (1937)(holding that noaction arises where neighbor erected platform on his property to facilitate the broadcastof horse races conducted on plaintiff’s tract). Cf., Pittsburgh Athletic Co. v. KQVBroadcasting Co., 24 F. Supp. 490, 492 (W.D. Pa. 1938)(holding that the defendant, whomade unauthorized broadcasts of baseball games with the aid of observers stationedoutside of the ballpark, engaged in unfair competition and interfered with advertiserswho had contracted with the owner of the baseball franchise for exclusive broadcastingrights). Note that this last case is distinguishable from the first and, by analogy, iscomparable to the situation where a landowner gives exclusive geophysical explorationrights to one geophysical operator who then suffers an invasion by a competing

on Whiteacre and capture oil and gas from beneath Blackacre withoutliability to Baxter, and because Wilson may drill a dry hole on Whiteacrewithout liability to Baxter for loss of speculative value, Wilson should beprivileged to “capture” information about the possible presence of oil andgas beneath Blackacre through geophysical operations on Whiteacre.316

A rule-of-capture approach to the gathering of seismic data would beefficient and would provide some encouragement for the furtherdevelopment of domestic oil and gas resources317 at a time when majorand many independent oil and gas companies are spending the lion’s share

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geophysical operator. In the geophysical context, I would not permit a direct invasion ofone’s exclusive exploration right by a competing geophysical operator, but I would allowthe rule of capture to govern where the competing geophysical operator obtained theinformation through activity conducted from nearby parcels.

In Rock and Roll Hall of Fame and Museum, Inc. v. Gentile Productions, 134 F.3d749 (6th Cir. 1998), the Court of Appeals for the Sixth Circuit vacated a preliminaryinjunction barring defendant from selling a poster depicting and identifying the Rockand Roll Hall of Fame building. The defendant had taken pictures of the building frompublic property. In dissolving the injunction and remanding the case, the court concludedthat the plaintiff failed to establish the likelihood of an intellectual property right in thebuilding as a trademark. In R.M.S. Titanic, Inc. v. Haver, 171 F.3d 943, 968-70 (4th Cir.1999) the court reversed the trial court’s order enjoining a photographer from takingpictures of the Titanic wreckage, thereby rejecting the salvor’s argument that aphotographic expedition would unlawfully infringe on the salvor’s exclusive salvagerights.318 To further encourage more geophysical exploration, Congress should amend thetax code so that geological and geophysical costs could be uniformly treated as an ordinarybusiness expense, rather than as a capital expenditure in the event prospects are developed.

of their exploration and development budgets overseas.318 Acquiringpermits from multiple mineral owners, lessees, and surface ownersregarding all lands affected by a seismic survey is costly in both time andmoney. A rule-of-capture approach would greatly reduce transaction costsby reducing the number of seismic permits needed to conduct a surveyand by discouraging “hold-out” bargaining by mineral owners bent oncollecting large fees from geophysical operators. Moreover, by not havingto purge its database of information concerning nonpermitted parcels, thegeophysical operator would be able to maintain seismic data that wouldbe more useful, more reliable, more complete and hence, more valuable.In short, a rule-of-capture approach would encourage more 3D seismicsurveying, which, in turn, should optimize orderly and efficientdevelopment of remaining oil and gas resources. In the oil and gasconservation sense, a rule-of-capture approach to geophysical explorationwould serve to prevent economic waste.

A relevant legal limit on the rule of capture is that the operator musthave a lawful right to conduct operations on the land where the well is

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located. An operator must not allow the well bore to physically invadeneighboring land.319 That is, the well bore itself must remain within the

319 See, e.g., Alphonzo E. Bell Corp. v. Bel View Oil Syndicate, 76 P.2d 167 (Cal. App.1938).

Yet another recent technology that raises trespass concerns is hydraulic fracturing.Hydraulic fracturing is a technique used to increase the permeability of reservoir rock–that is to increase the ability of a fluid such as oil to flow through reservoir rock. Thistechnique forces proppants into reservoir rock, creating and maintaining fractures thatincrease permeability. Because the extent or length of a fracture cannot be preciselycontrolled, both the proppants and the resulting fractures can extend beyond propertyboundaries, raising the issue of trespass. The Texas Supreme Court, in an opinion thatwas subsequently withdrawn, held that such a physical invasion constituted unlawfulsubsurface trespass. Geo Viking, Inc. v. Tex-Lee Operating Co., 1992 WL 0263 (Tex.1992), writ withdrawn as improvidently granted, Geo Viking, Inc. v. Tex-Lee OperatingCo., 839 S.W.2d 797, 798, 117 O&GR 357 (Tex. 1995)(letting stand the court of appealsdecision that fracturing was protected by the rule of capture, 817 S.W.2d 357, 364(Texarkana - 1991, writ denied)). Even if one were to concede (and I do not) that thesupreme court’s initial opinion was correct, hydraulic fracturing beyond one’s propertyboundary is distinguishable from seismic vibrations and sound waves penetrating beyondone’s property boundary because seismic activity does not physically alter subsurfaceformations and no physical substance enters the neighboring property. For discussion ofthe trespass concerns that arise from hydraulic fracturing, see Laura H. Burney andNorman J. Hyne, “Hydraulic Fracturing: Stimulating Your Well or Trespassing Theirs,”44 Rocky Mt. Min. L. Inst. 19-1 (1998).

Professors Burney and Hyne offer an excellent discussion of hydraulic fracturingtechnology, related trespass concerns, and a lessee’s potential obligation to engage inhydraulic fracturing under the reasonable and prudent operator standard. Concerninghydraulic fracturing from a trespass standpoint, I would argue that both the rule of captureand an operator’s obligation to prevent underground waste should protect an operatorwho conducts prudent fracturing operations against a suit for trespass, nuisance,conversion, or other related action. Using waste as the lynchpin, a prudent operatorshould act to prevent waste and refrain from taking action that causes waste, especiallyunderground and economic waste, i.e., the failure to recover oil and gas reserveseffectively and efficiently. Thus, this obligation to both prevent waste and not causewaste, together with the rule of capture, should shield an operator from liability forconducting a prudent fracturing operation. If a fracturing operation damages a reservoir,a neighboring well, or causes damage other than drainage, liability could arise on grounds

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physical boundaries of the operator’s land. Applying this same legal limitto geophysical operations, shot holes and receivers could be located onany “permitted” parcels so as to optimize the gathering of informationfrom the entire targeted area, but could not be placed within theboundaries—surface or subsurface—of “nonpermitted” parcels.320

This legal limitation on the scope of the rule of capture is also a physicallimit in that the rule governs the correlative rights of parties having an

of waste or negligence. Cf., Snyder Ranches, Inc. v. Oil Conservation Comm’n, 798 P.2d587 (N.M. 1990)(court, in dicta, stating that an injector of salt water, a waste product,would be liable for damages to neighboring landowners) and Elliff v. Texon DrillingCo., 210 S.W.2d 558 (Tex. 1948)(operator whose drilling operations resulted in a blowoutheld liable for damage to reservoir on grounds of negligence and waste). This approachwould promote reasonable and prudent fracturing operations as desirable public policywhile discouraging waste and negligence.

For decades, courts have protected a party’s ownership of gas stored undergroundand protected such a party from claims of trespass in the event some of the stored gasmigrates beneath a neighbor’s tract. See, e.g., Lone Star Gas Co. v. Murchison, 353S.W.2d 870 (Tex. Civ. App. - Dallas 1962, writ ref ’d n.r.e.)(also properly recognizingthat stored gas is “personal” property and not subject to the rule of capture). Courts havedone so to further the public policy of efficient gas storage. In part, the storage of gasprevents the economic waste of having to build larger pipelines and prohibitively expensiveman-made storage facilities. See also, Board of County Comm’rs v. Park CountySportsmen’s Ranch, LLP, 45 P.3d 693 (Colo. 2002)(holding that the storage of water inan underground acquifer is not a trespass against neighboring landowners where therewas no physical invasion by directional drilling). Similarly, because prudent hydraulicfracturing will increase the effective and efficient recovery of reserves, fracturingoperations should be encouraged and protected. See also, Railroad Comm’n v. Manziel,361 S.W.2d 560 (Tex. 1962)(declining to enjoin a water-flooding operation, designed toincrease ultimate recoveries, on grounds of trespass).

If necessary, conservation agencies could regulate fracturing operations to guardagainst overreaching, waste, negligence, and environmental damage. And, perhaps inthe future, fracturing technology will improve so that the extent or length of fracturescan be controlled. In the meantime, however, such operations should be encouraged, notfettered.320 In this context, “permitted” parcels refers to land for which the geophysical operatorhas the appropriate permission to enter and use, in contrast to “nonpermitted” parcels forwhich the geophysical operator has no right to enter or use.

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321 See, e.g., Alphonzo E. Bell Corp. v. Bel View Oil Syndicate, 76 P.2d 167 (Cal. App.1938). Note that this is true even if the reservoir also underlies Wilson’s land.322 The cautious geophysical operator could include in the terms of the permit the owner’sexpress consent to image the structure from other tracts, including acreage beyond theedge of the targeted structure.323 The geophysical operator would need to secure the permission of a mineral ownerof the occupied lands even if the occupied acreage were not a target of the survey. See,e.g., Phillips Petroleum Co. v. Cowden, 241 F.2d 586, 590, 7 O&GR 1291 (5th Cir.1957).

interest in a common oil or gas reservoir. In other words, returning to myhypothetical seismic problem, for Wilson to be able to lawfully drain thegeologic dome under the rule of capture, Wilson must be able to penetratethe dome from a well bore that is entirely within the boundaries ofWhiteacre. Of course, this penetration can only be accomplished if thereservoir is physically located beneath Whiteacre, because Wilson maynot drain the reservoir by drilling a directional well that penetrates thereservoir at a point beneath Blackacre.321 Should this same limitationapply to geophysical operations where no part of the targeted structureunderlies Whiteacre?

Initially, I submit that this question is largely academic (i.e., the kindof question a particularly cantankerous professor might ask on a law schoolexamination). Most likely, the geophysical operator would be able to obtainpermission from someone having an interest in the targeted structure.Once a permit is obtained from a fee or mineral owner having an interestin the targeted structure, the operator would be free to survey the acreageburdened by the permit, either directly or from nearby lands.322 Thenpermission could be obtained from a surface owner and mineral owner323

of the lands where the actual surveying operations would occur.Accordingly, this problem would rarely arise.

But suppose this situation did arise. While I concede the above physicallimitation on the rule of capture where production is at issue, I submitthat the gathering of geophysical data in this situation should still bepermitted. Returning to my hypothetical problem, the rule of captureshould protect the right of Wilson to use Whiteacre to gather information

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324 Cf., Mountain Fuel Supply Co. v. Smith, 471 F.2d 594, 45 O&GR 321 (10th Cir.1973)(construing Utah law and holding that an oil and gas lessee could not use thesurface of leased acreage to transport production from other leaseholds).

about other targeted parcels regardless of the physical presence of acommon geologic structure beneath Whiteacre and the targeted parcels.My view might be identified as a corollary “exploration rule of capture”which governs the correlative rights of all mineral owners within acommon area of interest (not necessarily a common oil and gas reservoir).

One justification for the rule of capture is that a court is often unableto determine the limits of a common reservoir with certainty so thatproduction from a well can be fairly allocated among all parties sufferingdrainage. A more restrictive rule for geophysical operations would requirecourts to engage in an extensive fact finding inquiry about the existenceof a common structure or reservoir—something that would be highlyspeculative, especially where wildcat acreage is involved. And in adeveloped area, the limits of a common reservoir might not be knownuntil after 3D seismic data have been gathered and interpreted.

Jurists who do not agree with the application of the rule of capture tothis latter fact situation might nevertheless apply the rule where all imagingis done from tracts that contain a portion of the targeted structure. Andjurists who do not agree with my rule-of-capture argument at all mightreach the same end result by applying the balancing test suggested as ameans of resolving the question of aerial surveying. Finally, jurists whodo not agree with any of these arguments may find themselves in thegood company of those learned commentators who believe that Baxtershould have a cause of action after all.

My rule-of-capture approach also addresses the surface-use problemthat arises from the need to image structure (that is, gather seismic data)from an angle rather than from above the targeted structures. Conventionalwisdom suggests that, if the mineral rights beneath the occupied tractsare not a target of the survey, a geophysical operator must securepermission from the surface owner of the occupied lands.324 Thisconventional wisdom is subject to one exception: if the severanceinstrument to the occupied lands expressly authorizes the use of the surfaceto explore and develop nearby lands, then no further permission would

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be needed from the surface owner in the absence of an applicable surface-owner-protection statute. A rule-of-capture approach should alter thisconventional wisdom. If a mineral interest owner has the right to captureseismic data from neighboring parcels, then the scope of a mineral owner’sright of surface use should implicitly include the use of the surface forsuch purpose.

[i] — Measure of Damages for ActionableGeophysical “Trespass.”

In my view, the only actionable geophysical trespass should be onewhich involves a direct, physical surface entry on, or a subsurface entryinto,325 the property at issue. When such a wrongful entry occurs, theplaintiff should be allowed, through discovery, to learn whether theinformation obtained and processed reveals favorable or unfavorableprospects for oil and gas development and whether the information hasbeen disclosed to another party or used by the trespasser in makingdevelopment decisions. Then, in order to deter this direct trespass, theplaintiff should be allowed an election of remedies for the wrongfulacquisition of geophysical information. The specific relief should dependon whether the trespass was in good faith or in bad faith. And the surfaceowner should be allowed to recover for any actual surface damages andfor wrongful use of the surface.

In case of bad-faith trespass, the plaintiff should be allowed to obtainthe data, in processed form, in a reasonably usable state,326 but not theinterpretations.327 In general, the plaintiff should also be allowed to

325 By subsurface entry, I mean a physical intrusion such as the drilling of a directionalshot hole beneath the property at issue, not mere concussion or sound waves generatedby seismic operations conducted on nearby lands.326 By reasonably usable state, I mean that the plaintiff should be allowed to obtain theprocessed data and interpretations of that data that directly relate to plaintiff’s acreagetogether with sufficient information concerning neighboring lands so as to be useful tothe plaintiff in evaluating the acreage for development.327 I draw this line regarding the raw data, the processed data, and the interpretationsby balancing. Although processing occurs after the trespass has occurred and beyond theboundaries of the affected acreage, raw, unprocessed data are of little use to the averagemineral owner. Thus, I would allow the mineral owner to acquire the processed data so

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recover as damages the greater of the following: the value of the plaintiff’sexploration right;328 the loss of the subject acreage’s speculative valuefor leasing and further development;329 any resulting loss of a specificbargain; the plaintiff’s lost profits, if any (such as where the plaintiff hadissued a lease to a party who had already obtained the data and negotiatedthe lease at a time when the plaintiff was unaware of the trespass);330 orthe reasonable gross market value331 to the defendant332 of the informationreasonably attributable to the plaintiff’s acreage.333 Further exemplarydamages or damages for mental anguish generally should be denied.

In case of a good-faith trespass, the plaintiff should be allowed toobtain the data, in processed form, in a reasonably usable state, but not

that the mineral owner may obtain a meaningful evaluation from a geophysicist. For thelimited purpose of proving damages (such as assessing any resulting loss in speculativevalue), however, I would allow a mineral owner to also discover relevant interpretations.328 If most landowners in the area issue oil and gas leases rather than prospecting permitsor lease options, damages might include the lease bonus that plaintiff could havereasonably expected to receive for the acreage that a lessee would ordinarily expect toacquire.329 A plaintiff might elect this remedy if the data were unfavorable to oil and gasdevelopment and have been disclosed to third parties, or used by the trespasser in makingdecisions about lease acquisitions.330 The plaintiff might elect this remedy if the data were favorable to oil and gasdevelopment and if a more lessor-oriented lease would have been negotiated by a plaintiffwho also possessed the data.331 By “gross,” I mean that the defendant should not be permitted to deduct the costs ofgathering and processing the data.332 The value to the defendant of the information wrongfully obtained from the plaintiff’sacreage could be based upon the proportion that the plaintiff’s acreage bears to the totalacreage explored by the defendant during the course of the particular survey. This measureof damages is criticized by Hawkins, supra note 130 at 316-317, arguing that such ameasure would bring “[d]oodle-bug superstition” (a slang expression used to describeany unorthodox or superstitious means of finding oil) into the courtroom. I do not findHawkins’ reasoning persuasive.333 Perhaps the court would first determine the market value of the entire survey andthen reduce that value by the proportion that the plaintiff’s acreage bears to the totalacreage explored by the defendant in the course of that particular survey.

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any interpretations, by compensating the defendant for the costs of thesurvey and processing that are reasonably attributable to the data that theplaintiff acquires. In general, the plaintiff should be allowed to recoveras damages the greater of the reasonable value of the plaintiff’s explorationright,334 or the reasonable net market value335 to the defendant336 of theinformation reasonably attributable to the plaintiff’s acreage.337

A bad-faith trespass would encompass the situation where thedefendant intentionally or recklessly trespasses onto the plaintiff’sproperty. A good-faith trespass would encompass the situation where thegeophysical trespasser reasonably believes that it has the right to enterplaintiff’s property for purposes of exploration, such as where thetrespasser enters with permission of a party the trespasser reasonablybelieves is a rightful mineral owner.

A directional subsurface trespass (such as drilling a directional shothole) generally should be presumed to have been done in bad faith,338

just as in the case of directional well drilling. In the context of oil and gasexploration,339 the permission of a surface owner who owns no recordinterest in the oil and gas rights should not serve as evidence of a good-faith trespass—even in states where the issue of who owns the exploration

334 This recovery could include recovery for an oil and gas lease bonus if the customand practice of mineral owners in the locality were to issue leases, not prospecting permits.335 By “net,” I mean that the defendant should be permitted to deduct the costs ofgathering and processing the data.336 Again, the value to the defendant of the information wrongfully obtained from theplaintiff’s acreage could be based upon the proportion that the plaintiff’s acreage bearsto the total acreage explored by the defendant during the course of the particular survey.337 Again, perhaps the court would first determine the market value of the entire surveyand then reduce that value by the proportion that the plaintiff’s acreage bears to the totalacreage explored by the defendant in the course of that particular survey. Costs could bedetermined and allocated in the same manner.338 Again, the imaging of a tract from a location on other land would be protectedunder the rule of capture and would not constitute a trespass against the imaged tract.339 I make this qualification because I recognize that, under certain circumstances, asurface owner may have the right to engage in the gathering of subsurface data. Seesupra § 11.04[3][b].

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right has not been addressed. Moreover, geophysical operations conductedalong highway rights-of-way without the permission of the underlyingmineral owner should be regarded as a bad-faith trespass.340 I reach theselatter two views because it is no longer reasonable, if indeed it ever wasreasonable, to believe that either a surface owner or the owner of a highwayright-of-way has the right to engage in geophysical operations related tooil and gas exploration and production.

In the typical geophysical trespass context, the trespasser may haveentered and explored the subject property in connection with the gatheringof information from a larger area, and that much of the total informationmay have been lawfully gathered. Accordingly, the plaintiff shouldordinarily be denied the right to enjoin the further use and disclosure ofseismic data that have already been wrongfully gathered, but a plaintiffshould be permitted to enjoin the wrongful entry itself.341 Enforcing theinjunction regarding the information wrongfully gathered, whilepreserving the defendant’s right to the information rightfully gathered,would be difficult to accomplish fairly. Moreover, requiring the defendantto purge its records of the wrongfully gathered data seems wasteful. Onthe other hand, the trespasser should not be permitted to defend againstliability or reduce damages by contending that the same data could havebeen lawfully gathered by exploration activities on nearby lands.342

340 I realize that this may seem inconsistent with my view that aerial surveys innavigational airspace should be permitted. See supra § 11.04[3][h][5]. However,geophysical operations, such as seismic surveys, conducted along a highway right-of-way are simply more physically invasive of the mineral owner’s rights than is an aerialsurvey.341 See, e.g., Hastings Oil Co. v. The Texas Co., 234 S.W.2d 389, 398 (Tex.1950)(enjoining the anticipated drilling of a well).342 Ample analogous law defends this view. For example, a trespasser who is producingoil and gas cannot reduce its liability for damages by showing that a quantifiable portionof the production is being drained from the adjacent property that the trespasser owns.Edwards v. Lachman, 534 P.2d 670, 676, 51 O&GR 343 (Okla. 1974). Also, ProfessorsHoward Williams and Charles Meyers contend that a lessee should not be permitted todefend against the violation of the implied covenant to prevent drainage by assertingthat the lessee’s existing well is draining the same amount of oil from beneath adjacenttracts that is being lost to drainage by neighboring wells. Williams & Meyers § 822.3.

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At first glance, these suggested measures of damages may seem harshwhen compared to existing case law; however, I am only proposing totreat direct physical entry onto or beneath the subject property as a trespass.The gathering of seismic data relating to the subject property by seismicoperations conducted on nearby lands would be protected under the ruleof capture. I would also protect the right to gather information from allstrata beneath acreage lawfully occupied even though the mineral rightshave been horizontally severed, and, in general, I would protect the rightof the owner of a specific mineral (e.g., oil and gas), to gather informationregarding other substances (e.g., coal).343 Moreover, these suggestedremedies are generally consistent with and analogous to the remediesgenerally available to a plaintiff who suffers a trespass that results in aproducing well and the conversion of the production344 or that results ina dry hole.345 And bad-faith trespass, as I define it, would rarely occur;346

however, there is little reason why a bad-faith trespass should not betreated harshly if it does occur. Finally, ethical geophysical operatorsshould not be concerned with these penalties. Indeed, deterring trespasswith harsh remedies should serve to enhance the reputation of thegeophysical industry in the long run because any “bad apples” wouldeither reform their practices or find little work.

343 See supra §§ 11.04[3][e] and [f], respectively.344 Cf., Alaska Placer Co. v. Lee, 553 P.2d 54, 56 O&GR 187 (Alaska 1976)(discussing,in a mining case, the differences in the governing measures of damages between a good-faith trespass and conversion and a bad faith trespass and conversion). I am aware thatTexas courts have denied recovery for conversion in cases involving geophysical trespass.See, e.g., Phillips Petroleum Co. v. Cowden, 241 F.2d 586, 593, 7 O&GR 1291 (5th Cir.1957) and Shell Petroleum Corp. v. Moore, 46 F.2d 959, 961-962 (5th Cir. 1931).345 Cf., Humble Oil & Refining Co. v. Kishi, 276 S.W. 190 (Tex. Comm’n App. 1925,judgm’t adopted).346 This is especially true of the 3D seismic method which is predominantly used as adevelopment tool. At the development stage, mineral ownership is generally well-knownand documented.

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§ 11.05. Surface-Use Limitations on theRight to Explore.

Because 3D seismic surveys generally cover a large area and becausethe survey grid involves more intensive use of the surface than do 2Dseismic surveys, the likelihood of friction between surface owners andgeophysical operators increases when 3D seismic operations occur.However, in the long run, 3D seismic operations should be a net gain formany surface owners concerned about extensive oil and gas development.For example, areas interpreted as being unfavorable for development basedupon 3D seismic are less likely to be subjected to further oil and gasoperations. Moreover, the use of 3D seismic reduces the number of dryholes that are drilled. Nevertheless, because of the more intense surfaceuse required for 3D operations, I offer the following brief summary of thelaw of surface use as it relates to seismic operations.

As previously discussed, a surface owner generally does not “own”the right to conduct geophysical operations in search of minerals.Moreover, absent a statute,347 a surface owner is not entitled to

347 Several states have surface owner damage compensation acts. At least two of theseacts govern geophysical operations: The North Dakota Act, N.D. Cent. Code §§ 38-11.1-03 & 06 (governing both the drilling of oil and gas wells and geophysical andseismograph exploration activities); and the Montana Act, Mont. Code Annot. §§ 82-10-501 & 502 (governing “exploration” as well as drilling).

The Oklahoma Surface Damage Act, Okla. Stat. tit. 52, §§ 318.2 - 318.9, does notapply to geophysical operations; however, a separate act, the Seismic ExplorationRegulation Act provides for the registration, bonding, and regulation of seismic operatorsby the Corporation Commission. Okla. Stat. tit. 52, §§ 318.21 - 318.23. The Act requiresthat the rules to be promulgated by the Commission “shall include” a requirement thata seismic operator give all surface owners at least 15 days advance notice through theUnited States mail of its planned operations. The notice must include a copy of the leaseor seismic permit authorizing the planned operations. Id. at § 318.22. The Act alsoprohibits seismic blasting within 200 feet of any habitable dwelling, building or waterwell without written permission from the owner. Id. at § 318.23.

Under the rules of the Colorado oil and gas conservation agency, seismic operatorsmust have permission from surface owners to lawfully conduct seismic operations. Colo.Oil & Gas Cons. Comm’n Rule 333, 2 Colo. Code Regs § 404; 404-1. In Alberta, Canada,

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before a party may engage in seismic surveying an exploration license is required and acondition to the granting of such a license is the consent of the surface owner or lessee.Alta. Reg. 214/98. Cf., Western Energy Co. v. Genie Land Co., 737 P.2d 478, 98 O&GR116 (Mont. 1987)(holding unconstitutional a statute that required surface-owner consentprior to obtaining a coal strip-mining permit) and Devon Corp. v. Miller, 280 S.E.2d108, 114, 71 O&GR 421 (W. Va. 1981)(upholding a statute requiring surface-ownerconsent to the drilling of deep oil and gas well, but partly on the basis that the cotenantlessee did not have the entire interest under lease prior to enactment of the statute).348 For more detailed treatment of surface-owner/mineral-owner conflicts, see John S.Lowe, “The Easement of the Mineral Estate for Surface Use: An Analysis of Its Rationale,Status & Prospects,” 39 Rocky Mtn Min. L. Inst. 4-1 (1993).349 See, e.g., Taylor v. Brigham Oil & Gas, L.P., 2002 WL 58423 (Tex. App.-Amarillo2002).350 See, e.g., Hunt Oil Co. v. Kerbaugh, 283 N.W.2d 131, 139, 65 O&GR 202 (N.D.1979). Two limits previously mentioned are (1) that the lessee’s use of the surface(including geophysical surveys) must be consistent with the underlying lease objectives,see supra § 11.04[3][g]; and (2) that the lessee’s use of the surface must be related toexploration and development of minerals beneath that surface, see supra § 11.04[3][h][1].

compensation for, or even notice of, a mineral owner’s reasonable andnecessary surface use in connection with mineral exploration ordevelopment.348 Likewise, a fee owner is not entitled to compensationfor an oil and gas lessee’s or a seismic surveyor’s reasonable and necessarysurface use relating to mineral exploration and development.349

Specifically, geophysical operations are ordinarily within the scope of amineral owner’s (or lessee’s) right to explore.350 Nevertheless, surfaceowners (whether or not they own an interest in minerals) are customarilypaid for the use of the surface even though the right to conduct geophysicaloperations is held by a mineral owner or by an oil and gas lessee. Thesepayments are commonly made for two reasons: (1) to compensate surfaceowners who may suffer damages or may be inconvenienced by geophysicaloperations; and (2) to obtain a signed waiver that the surface owner willnot bring suit alleging an unreasonable, negligent, or excessive use of thesurface respecting the activities described in the waiver. In addition, in

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351 See, e.g., Colo. Rev. Stat. §§ 34-60-102 & 103; Fla. Stat. Ann. § 377.2424; Mont.Code Annot. §§ 82-01-101 through 111; N.D. Cent. Code ch. 38-08.1; Okla. Stat. tit.52, §§ 318.21 - 318.23; and Wyo. Stat. Ann. § 30-5-104. Louisiana has a regulatory lawthat is limited to state-owned land. La. Rev. Stat. Ann. § 30:212.352 Hunt Oil Co. v. Kerbaugh, 283 N.W.2d 131, 139, 65 O&GR 202 (N.D. 1979).353 See, e.g., Bynum v. Mandrel Indus., Inc., 241 So. 2d 629, 632, 37 O&GR 227(Miss. 1970); Magnolia Petroleum Co. v. McCollum, 51 So. 2d 217, 219 (Miss. 1951);and General Geophysical v. Brown, 38 So. 2d 703, 705 (Miss. 1949).354 See, e.g., Harrison v. Petroleum Surveys, 80 So. 2d 153, 158, 4 O&GR 1506 (La.App. 1955)(awarding special damages for the temporary economic loss of destroyingthe land’s utility for trapping muskrats).355 See, e.g., Phillips v. California Standard Co., 31 W.W.R. 331 (Alta. 1960)(findinggeophysical surveyor liable in nuisance for damage to water well); Francis v. Sun OilCo., 340 P.2d 824, 826, (Mont. 1959)(awarding special damages for harm to a flowingspring and holding defendant liable as a trespasser ab initio even though defendant hadentered the property with landowner’s permission); Western Geophysical Co. of Americav. Martin, 174 So. 2d 706 (Miss. 1965)(declining to hold geophysical company liablefor water well damage absent showing that blasting proximately caused the damage);and General Geophysical v. Brown, 38 So. 2d 703, 705 (Miss. 1949)(awarding specialdamages for injury to water well). In North Dakota, surface owners are aided by a specialstatute addressing damage to water supplies resulting from geophysical operations. N.D.Cent. Code § 38-11.1-06.356 Shell Petroleum v. Scully, 71 F.2d 772, 774 (5th Cir. 1934)(construing Louisianalaw).

some states, geophysical operations are regulated for the protection ofboth mineral and surface owners.351

A right of a mineral owner or lessee to use the surface is implicitlylimited to non-negligent, non-excessive use of the surface relating toexploration and development operations conducted in accordance withthe accepted custom and practice of the oil and gas industry. Properlyconducted geophysical operations, including seismic operations, do notviolate these limits.352 However, if the mineral owner exercises the rightto explore in an unreasonably, excessive, or negligent manner, the surfaceowner may sue for any resulting damages, generally measured by thedecline in value of the land.353 In each of these instances, damages mayinclude a variety of special damage claims,354 especially for damages towater resources.355 Special damages may include costs of restoration356

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357 Teledyne Exploration Co. v. Klotz, 694 S.W.2d 109, 110 (Tex. App.-Corpus Christi1985, writ ref ’d n.r.e.)(involving damages to topsoil and trees).358 See, e.g., Shell Oil Co. v. Murrah, 493 So. 2d 1274, 1276 (Miss. 1986)(involvingdamages to trees); Dahl v. Petroleum Geophysical Co., 632 P.2d 1136, 1136, 72 O&GR301 (Mont. 1981)(involving tort damages for flooding).359 See, e.g., Houck v. Hold Oil Corp., 867 P.2d 451, 461 (Okla. 1993)(applying commonlaw and limiting surface damages to the difference between the market value of theinjured land immediately before and immediately after the injuries in an action broughtpursuant to the Oklahoma surface damages statutes, Okla. Stat. tit. 52, §§ 318.2 - 318. 9);and Johansen v. Combustion Engineering, Inc., 834 F. Supp. 404, 412 (S.D. Ga.1993)(limiting trespass and nuisance damages for pollution of a stream to the diminutionvalue of the affected land). See generally, Restatement (Second) Torts § 929. For acomparable case caused by geophysical operations, see Petty-Ray Geophysical, Divisionof Geosource, Inc. v. Ludvik, 718 P.2d 9 (Wyo. 1986)(holding that damages are ordinarilylimited to the difference in market value of the property before and after the damage).360 Finnell v. Jebco Seismic, 2003 OK 35 (Okla. 2003).361 Getty Oil Co. v Jones, 470 S.W.2d 618, 622, 39 O&GR 657 (Tex. 1971).362 Under the Texas accommodation doctrine, for an alternative to be a reasonable, itmust be available on the land in question. In Sun Oil Co. v. Whitaker, 483 S.W.2d 808,812, 42 O&GR 256 (Tex. 1972), the surface owner argued that an oil and gas operatorcould truck salt water from other lands for use in drilling operations rather than usepotable groundwater to the detriment of the surface owner’s irrigation operations. Thecourt, however, held that requiring the operator to truck water from other lands was nota reasonable alternative to the use of fresh groundwater, which was readily available onthe premises, even though the use of fresh water might harm the surface owner’s irrigationoperations.

and possibly damages for mental anguish357 or even exemplarydamages;358 however, in some states, total recovery for permanent damagemight be limited to the market value of the injured land.359 Ordinarily, thelandowner’s cause of action is in tort for injury to land; however, if thelandowner has issued a permit to a seismic operator who then makes anegligent or excessive use of the property, the action may lie both in contractand tort.360

In perhaps most jurisdictions, the mineral owner’s surface-use rightsmay be further limited by the accommodation doctrine.361 Under thisdoctrine, if an oil and gas operator has reasonable alternatives availablefor the manner or method of contemplated operations,362 the court will

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363 Under the Texas accommodation doctrine, only the surface owner’s existing, notfuture, land use is considered when assessing the impact of an operator’s activities on thesurface owner. Getty Oil Co. v. Jones, 470 S.W.2d 618, 622 (Tex. 1971).364 Hunt Oil Co. v. Kerbaugh, 283 N.W.2d 131, 137, 65 O&GR 202 (N.D. 1979).365 Recent Oklahoma legislation prohibits seismic blasting within 200 feet of anyhabitable dwelling, building or water well without written permission from the owner.Okla. Stat. tit. 52, § 318.23. When negotiating seismic permits, the Southwest KansasRoyalty Owner’s Association recommends that vibroseis trucks operate no closer than1320 feet from a farmstead improvement, 1000 feet from a water well, 400 feet fromconcrete irrigation pipe, and 200 feet from underground PVC pipe. “Seismic Distances,”SWKROA p. 5 (Southwest Kansas Royalty Owner’s Association, October1998)(newsletter). However, due to the adverse effects that these distances have on theoptimum acquisition of seismic data, operators in Southwest Kansas have requested theAssociation to reduce these distances to 300 feet for structures, 400 to 600 feet for waterwells, and 100 feet for pipelines. Id. at 6. This same publication reports that permitcompensation paid by seismic operators to surface owners in Southwest Kansas rangesfrom $5.00 to $15.00 per acre. Id. at 5.

consider the impact of each alternative on the surface owner’s use andenjoyment of the surface.363 After balancing the interests of the operatorand surface owner, the court may order the operator to use the alternativethat will cause the least disruption of the surface owner’s use andenjoyment. If there are no reasonable alternatives to the manner or methodof the operator’s contemplated operations, then accommodation balancingis not triggered.

The North Dakota Supreme Court, in a case that accepts and appliesthe accommodation doctrine, has ruled that there is no reasonablealternative to seismic geophysical operations.364 Nevertheless, inappropriate circumstances, a court might require an oil and gas operatorto accommodate the surface owner regarding the manner in which seismicgeophysical operations are conducted. For example, a court might concurwith a landowner’s request that shot points be placed a reasonable distancefrom a building, water hole, well, or flowing spring.365 Or perhaps acourt might require an operator to postpone operations until after thesurface owner has harvested growing crops. In a detailed 3D seismicsurvey, the extent of surface use can be fairly intense. Thus, the likelihoodof a surface owner seeking an accommodation is increased—especially

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as oil and gas operations move into areas of intense surfacedevelopment.366

Because explosives may be used in seismic operations, thegeophysical operator might be held liable for any resulting actualdamages.367 Many jurisdictions hold a party engaged in blasting strictlyliable for any actual damage caused by the detonation of explosives.368

The theory of liability may be grounded in nuisance369 or trespass,370 orthe blasting may simply be viewed as an ultrahazardous activity.371 Otherjurisdictions, however, require a showing of negligence.372 Where ageophysical contractor has been hired by an oil company to do a seismicsurvey, the risk of actionable surface damage is often contractuallyallocated through indemnity clauses.373 Because the use of explosives

366 See generally, Jeanine Feriancek & Cynthia L. McNeill, “Oil Company SurfaceUse: Do Farmers Need Protection?,” 9 Natural Resources and Environment 28(1995)(dealing with surface-owner/mineral-owner clashes in Wells County, Colorado—an area of small irrigated farms and intense oil and gas development).

In Louisiana, the rights of the landowner and mineral lessee are “correlative.”Pennington v. Colonial Pipeline Co., 260 F. Supp. 643 (E.D. La. 1966), aff ’d, 387 F.2d903 (5th Cir. 1968). In Pennington, the court held that a seismic operator could notrequire a successor surface and right-of-way owner to cease its surface operations toaccommodate seismic operations where the seismic operator was deemed more able toadjust its operations to accommodate the surface and right-of-way owner.367 See, e.g., Dykes v. Peabody Shoreline Geophysical, 482 So. 2d 662 (La. App. 1stCir. 1985); General Geophysical v. Brown, 38 So. 2d 703 (Miss. 1949).368 See, e.g., Fontenot v. Magnolia Petroleum Co., 80 So. 2d 845 (La. 1955); Longtin v.Persell, 76 P. 699, 701 (Mont. 1904); Dean v. Paladin Exploration Co., 64 P.3d 518(N.M. Ct. App. 2003) and Feinberg v. Wisconsin Granite Co., 224 N.W. 184 (S.D. 1929).369 See, e.g., Rotert v. Peabody Coal Co., 513 S.W.2d 667, 678 (Mo. App. 1974); Coltonv. Onderdonk, 10 P. 395, 397 (Cal. 1886).370 See, e.g., Watson v. Mississippi River Power Co., 156 N.W. 188, 192 (Iowa 1916).371 See, e.g., Louden v. City of Cincinnati, 106 N.E. 970, 973 (Ohio 1914) and SeismicExploration, Inc. v. Dobray, 169 S.W.2d 739 (Tex. Civ. App.-Galveston 1943, writrefused).372 See, e.g., Longtin v. Persell, 76 P. 699, 701 (Mont. 1904) and Feinberg v. WisconsinGranite Co., 224 N.W. 184 (S.D. 1929).373 See, e.g., DDD Energy Inc. v. Veritas DGC Land, Inc., 60 S.W.3d 880 (Tex. App. -Houston [14th Dist.] 2001).

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in geophysical operations rarely causes substantial actual damage, furtherdiscussion of this topic is beyond the scope of this article.374

§ 11.06. Conclusion.In terms of finding and managing petroleum reservoirs, the first

significant impact on productivity probably came in the late 1950s and1960s with the widespread use of well logs and 2D seismic data.

. . .Together, these technologies greatly improved structural interpretation

of the subsurface—one through direct measurement, the other throughindirect imaging. They were as important to E&P professionals asexploratory surgery and X-rays were to physicians.

. . .With the introduction of 3D seismic technology in the early 1980s,

the industry took an even greater leap in productivity.375

Modern 3D seismic technology is a major technological innovationfor the oil and gas industry and valuable intellectual property.376 It hasbecome a critically important tool for successful and efficient primarydevelopment of oil and gas reservoirs. Through time-lapse imagery (4Dseismic), 3D seismic is proving to be a valuable enhanced recovery tool.Moreover, its use in exploration is destined to increase.

My views regarding geophysical “trespass” advocate a public policythat promotes the efficient gathering of information through the use ofmodern geophysical operations. Promoting efficient geophysicalexploration, by taking full advantage of modern technology, will promotefurther domestic exploration and production and should lessen thecompetitive disadvantage domestic operations suffer when compared tointernational and offshore operations. To require permission from eachpotentially affected mineral owner is inefficient and creates transaction

374 For an illustrative case, see R & S Dev., Inc. v. Wilson, 534 So. 2d 1008 (Miss.1988). For further discussion, see Summers, supra note 130, § 661.375 See R. P. Peebler, “Extended Integration – The Key to Future Productivity Leap,”Oil & Gas J., May 20, 1996, at 57.376 See, e.g., East Texas Seismic Data, LLC v. Seitel Data, Inc., 279 F.3d 915 (10th Cir.2002).

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377 See, e.g., La. Rev. Stat. Ann. §§ 30: 217 & 31:164, 166, 175 (an example of aregrettable legislative solution).378 See, 30 U.S.C. § 226(j)(1995)(amended by 30 U.S.C. § 226(j)) and 43 C.F.R. §3186.1. See generally Owen L. Anderson & Ernest E. Smith, III, “The Use of Law toPromote Exploration and Production,” 50 Inst. on Oil & Gas L. & Tax’n 2-1, 2-86 to 2-94(1999).379 See, e.g., Southern Utah Wilderness Alliance v. Norton, 237 F. Supp. 2d 48 (D.D.C.2002).380 See, e.g., Center of Biological Diversity v. National Science Foundation, 2002 WL31548073 (N.D. Cal. 2002); Natural Resources Defense Council v. Evan, 232 F. Supp. 2d

costs that will unduly burden the domestic oil and gas industry at a time ofever-increasing reliance on imported oil.

Regarding geophysical trespass, a middle ground could be staked outvia a legislative solution. While a legislative solution could be limited toaddressing specific issues regarding only geophysical operations,377 theproper legislative solution would be a comprehensive statute that wouldallow oil and gas conservation commissions to establish exploratory unitspatterned after those created on federal lands.378 While such a proposalwould probably face opposition from small independent operators andmineral owners, many of their concerns could be addressed by properlytailored legislation which would include reasonable compensation for theexploration right. Moreover, the establishment of exploratory units wouldserve to encourage greater investment in domestic oil and gas explorationand production operations, which, in turn, may serve to lessen Americandependence on foreign oil supplies. In any event, exploratory units arebeyond the scope of this article. In the meantime, however, I urge courts torender opinions in geophysical “trespass” cases that will serve to promote,rather than hinder, efficient geophysical operations.

In the coming years, seismic exploration, especially the more surface-intensive 3D seismic may come under closer scrutiny by environmentalists.This has already occurred on federal public domain lands, whereenvironmental organizations are demanding stringent NEPA review forseismic surveys.379 Regarding offshore exploration, there is increasingconcern that a variety of sonar and acoustical research and surveyingactivities may adversely affect marine mammals380 and oyster farmers have

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1003 (N.D. Cal. 2002). Under the Marine Mammal Protection Act, 16 U.S.C. §§ 1361 etseq., the federal government has authority to regulate the “taking” of marine mammals.16 U.S.C. § 1373(a). The term “take” includes “to harass.” 16 U.S.C. § 1362(13).“Harassment” includes “any act of pursuit, torment, or annoyance” having the “potentialto injure . . . or disturb a marine mammal or marine mammal stock . . . by disruption ofbehavioral patterns, including, but not limited to, migration, breathing, nursing, breeding,feeding, or sheltering.” 16 U.S.C. § 1362(18). As of this writing, the National MarineFisheries Service is considering whether to propose regulations that would govern theincidental taking of small numbers of marine mammals as a result of seismic surveys.Notice, 68 Fed. Reg. 9991 (March 3, 2003).381 See, e.g, Western Geophysical Co. v. Adriatic, Inc., 2000 WL 988073 (E. D. La.2000); Western Geophysical v. Adriatic, Inc., 2000 WL 235654 (E.D. La. 2000); Adriatic,Inc. v. Western Atlas Int’l, Inc., 1999 WL 151663 (E.D. La. 1999); Blue Gulf Seafood,Inc. v. Transtexas Gas Corp., 24 F. Supp. 2d 732 (S.D. Tex. 1998).382 Fla. Stat. Ann. § 377.2409 and La. Rev. Stat. Ann. § 30:209 and 209.1.383 30 C.F.R. §§ 251.12; 280.51. See also, 30 C.F.R. § 203.86 (requiring submission ofseismic data to obtain royalty relief for deep wells on the OCS) and 50 C.F.R. § 37.53(requiring submission of seismic data to the United States Fish & Wildlife Service regardingthe Alaska Arctic National Wildlife Refuge).

In addition, when a company wants to conduct a seismic survey on federal land, apermit is applied for with the controlling agency. Typically, this is the Bureau of LandManagement, which also controls seismic shoots on other land controlled by other agencies,but in other circumstances applications are made through the Forest Service, Fish andWildlife, or even the Park Service. The agency then either approves or disapproves thepermit. If the permit is approved, the agency then explains the necessary parameters of theshoot to the company. Typically for the cost of reproduction of the data, the BLM isallowed a copy of requested portions of the data, which is examined to monitor leasingvalues. Sometimes the United States Geological Survey is instructed by the Secretary ofthe Interior to assess seismic. Submitted data is confidential until all the leases in theregion are complete or for a certain time period. The company that acquired the data canapply for an extension of the confidentiality period.

sued seismic companies for alleged damage to oyster beds.381 At this time,however, it is too early to assess the long-term impact of thesedevelopments.

In the future, state regulatory agencies may begin collecting seismicdata in a manner similar to the common practice of collecting well logs,which are publicly available, subject to varying periods of confidentiality.Government collection of seismic data is well known in internationaloperations and has already begun in Florida and Louisiana respecting state-owned lands.382 The Minerals Management Service has collected seismicdata from surveys conducted on the federal OCS for many years.383

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§ 11.07. Appendix: Figures.

Figure 1A

Structural contour map from the Gulf of Thailand constucted frominterpreted 2D seismic data. Thick lines represent faults and thin linessignify contours of two-way time to the top of a particular horizon. Thelower values represent more shallow regions and the higher valuesrepresent the deeper regions. Note that most contours are semicircular inoutline and tend to interect faults at right planar angles, a commoninterpretive effect of sparse control. Compare with the greater detail ofFigure 1B. Brown, supra note 6. Reprinted by permission, courtesy ofTexas Pacific Operation Company, Inc.

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Figure 1B

Structural contour map of identical region and of identical scale to thatinterpreted in Figure 1A. Note, however, that this map, which wasinterpreted from 3D seismic data, is more detailed—showing shorter andmore numerous fault segments and the consequent division of the reservoirinto the more numerous compartments. Note also that, owing to the greaterresolution of the 3D data set, these interprted contours are now more intrend with the fault traces, define elliptical rather than circular structures,and tend to intersect faults in lower planar angles than the previousinterpretation. For field development, the enhanced resolution from the3D seismic data allows a more accurate determination of hydrocarbonvolumes and a better definition of the geometrical extent of the producingreservoirs for better engineering of product. Brown, supra note 6.Reprinted by permission, courtesy of Texas Pacific Operation Company,Inc.

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A 2D vertical seismic reflection profile with the vertical scale displayedin a two-way time (approximately 1400 feet) and the horizontal dimensionin common midpoints which represent 5000 feet across. This profile isextracted from an onshore 3D seismic data volume acquired in southernLouisiana (Pigott 1993, supra note 6). The continuous numbered linesrepresent interpreted river and sand bodies imbedded with shale. Line#15 represents the valley walls of a large incised canyon which wassubsequently filled with sediment.

Figure 2A

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A structurally corrected horizon slice of the same 3D seismic data volumeused to create Figure 2A. Note that on this horizontal displayed surface,the outlined “C” shaped region represents an “oxbow” portion of ameandering paleoriver channel presently filled with sand. When comparedwth Figure 2A, one can readily appreciate that a 3D seismic sliceconsiderably facilitates geological interpretations. Could you find the sameriver channel on the conventional vertical 2D seismic section in Figure2A?

Answer: Reflector line segments #20 in Figure 2A.

Figure 2B

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Figure 3

Uninterpreted (3A) and interpreted (3B) 2D seismic lines from Italy. Theimage represents a collection of stacked vertical traces in two-way timewhich portray a vertical cross-section through the earth. The horizontallines are timing lines. The varying dark lines represent interpretations ofreflectors indicating stratal surfaces. The well locations were chosen inorder to test these structures for economic occurrences of hydrocarbons.However, without a map view or a three-dimensional volume, it is notpossible to define the lateral extent of the structures into and out of theplane of the section. Bradley, supra note 6. Reproduced by permission ofPrentice-Hall, Inc.

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Figure 4

An illustration of Shell’s law using a flashlight to shine a beam of lightinto a bodyof water. Part of the obliquely incident ray is reflected at theangle of incidence and part is refracted at an angle which depends on theration of the velocities of the two layers. The principles which affect light’sbehavior as a ray with respect to its interaction with media of differingtransmission velocities similarly apply to sound. More detaileddescriptions of Shell’s law to seismic are described in the text. Modifiedfrom Gadallah, supra note 6. Reprinted by permission of PennWell Books.

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Figure 5

Schematic diagram of wave fronts which expand as rings in twodimensions (shown here) and as spheres in three dimensions. One wave-length equals the distance between Circle A and Circle E, the inflectionpoints of propagating wave trains. The rays are lines which representdirections of propagation perpindicular to the wave fronts. Seismic soundpropagation exhibits properties both of rays and of waves. Modified afterTelford, supra note 6.

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Figure 6

Basic characteristics of a seismic trace. The amount of deflection observedat varying positions along its length and measured perpendicular to itslongitudinal dimension is termed its amplitude, with peaks and troughsrepresenting deflections of opposite magnitude. The distance between thesubsequent peaks or troughs represent spatially the wavelength. Ifmeasured in time, this distance is termed the period.

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Figure 7

Schematic representation of the normal incidence ray relationship androck properties required for calculating the reflection coefficient. Thereflection coefficient (see § 11.02 [1][b], supra for formula), determinedfrom contrasting rock properties along a boundary between two layers, isrepresented seismically as a proportionally scaled trace amplitude. Thereflection coefficient at the upper sandstone boundary is a positive 0.25which generates a peak of equivalent magnitude. At the base of thesandstone, the negative reflection coefficient of minus 0.25 generates awavelet trough of equivalent magnitude. Such differences in seismicwaveforms allow the geophysicist to interpret the positions of the upperand lower boundaries of contrasting rock types.

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Figure 8

Dramatic phase attribute 2D seismic display from the subsurface strate ofthe offshore Gulf of Mexico. The horizontal axis represents shot pointlocations and the vertical axis is recorded in two-way time (sec). Illustratredare three direct hydrocarbon indicators (DILLs): a bright spot (the concavedownward feature centered at 1.150 sec. and at shotpoint 525); a flat spot(the horizontal reflection centered at 1.200 sec. and at shotpoint 525); anda frequency shadow (the two thick dark horizontal lines making up theflat spot). Brown, supra note 6. Reprinted by permission, courtesy ofGeophysical Services, Inc.

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Figure 9

Schematic cross-sections of 2D seismic ray paths and the resulting seismictrace record which illustrate both the geometric origin and the final resultof static and dynamic (NMO) corrections made to a common midpoint(CMP) gather. See § 11.02[1][d], supra for explanation. Bradley, supranote 6. Reprinted by permission of Prentice-Hall, Inc.

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Figure 10

Illustration of the subsurface geometry specified for calculating themigration aperture. The reflection segment C’D’ in time section (b), whenmigrated, is moved updip, steepened, shortened and mapped onto its truesubsurface location to account for migration aperture. The size of a 3-Dsurvey over a subsurface structure normally is greater than that of thestructure. See § 11.02[l][e], supra for the formula and its application.Gadallah, supra note 6. Reprinted by permission of PennWell Books,courtesy of Seismograph Services Corporation.

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Figure 11

Common midpoint (CMP) method for land seismic acquisition. The upperdiagram illustrates the surface view of an in-line survey geometry foracquisition, where S indicates shot point and R indicates receivinggeophone group locations. Note that, with each advance of the line to theleft for each record, the CMP advances an equivalent distance to a newlocation to the right in order to be equidistant between the shot and anequivalent offset. The middle diagram shows the subsurface view for tworeflectors after three shot records. The lower diagram indicates the seismictrace response for the two reflectors, where the vertical axis is two-waytime and the horizontal axis is distance. Bradley, supra note 6. Reproducedby permission of Prentice-Hall, Inc.

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Figure 12

Common midpoint gather (CMP) illustrating the changes in amplitudewith horizontal offset (AVO) for a water-wet sand and a gas-filled sand.Note that the wet sand decreases in amplitude with offset, in markedcontrast to the amplitude increase with offset for the gas sand. It is thisability to discriminate hydrocarbons from water in the unstacked data(which otherwise would not be differentiable in the stacked state) thatmakes the AVO method so useful. Castagna and Backus, supra note 6.Reprinted by permission of Castagna and Backus.

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Figure 13

Figure 13C shows the forward seismic model of the wedge for a dominantfrequency of 25 Hz, which is more poorly resolved than Figure 13D wherethe dominant frequency is 50 Hz.

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Figure 14

Schematic diagram illustrating the Fresnel zone (the unmigratedseismically illuminated region in the subsurface which defines thehorizontal resolution). See § 11.02[5][e], supra for the formula and itsuse. Gadallah, supra note 6. Reprinted by permission of PennWell Books.

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Figure 15

3D seismic cube display illustrating two orthogonal vertical sections andone horizontal time section. The ability to image the earth’s subsurface inthree dimensions adds considerably to the geophysicist’s ability to providean accurate interpretation, allowing the use of information significantlymore illuminating than that provided either by a 20-inch diameterpenetrating borehold or by one singular 2D seismic line. To successfullyinterpret such a image, however, takes considerable technology and skillin 3D acquisition, processing, and interpretaton. Brown, supra note 6.Reprinted by permission, courtesy of Western Atlas International.

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