SHALLOW WATER FLOWS

Table of contents. Shallow WATER flows ..................................................................................................... 1

Table of contents. ......................................................................................................... 1 Introduction .................................................................................................................. 2 Sand prediction ............................................................................................................ 4 Pore pressure prediction .............................................................................................. 6 Operational Guidelines ............................................................................................ 9 Drilling Techniques ..................................................................................................... 11 Cementing techniques ............................................................................................... 14 Preparing for “open water” shallow flow(s). ................................................................ 17 Operating procedures. ............................................................................................... 18 Flow detection during riser-less operations. ............................................................... 19 Emergency procedures. ............................................................................................. 19 Shallow flow procedures. ........................................................................................... 21 Special Practices ........................................................................................................ 24 Remedial operations/P&A concerns ........................................................................... 29 References ................................................................................................................. 30

Appendices .................................................................................................................... 31 Appendix 1: SWF incident report. ............................................................................... 31 Appendix 2. Seismic interpretation. ............................................................................ 33 Appendix 3; Pressure Prediction for Shallow Water Flow .......................................... 38 Appendix 4: Definitions and nomenclature ................................................................. 45

Introduction Shallow flow geo-hazards and their mechanisms were described in section 5 In the deepwater arena, shallow water flows (SWF) incidents have been documented since 1984 and have resulted in costly lost operational time due to well control problems experienced. E.g. The most significant incident was at Shell’s operated URSA template development site in Mississippi Canyon block 810. Twenty one partially drilled wells were lost as a result of shallow waterflow.

Estimated costs of shallow water flows. Analysis of a deepwater well study by Mark Alberty of BP concluded that the industry spends an average of $1.6 million per well for the prevention or remediation of SWF induced problem, in the following key areas;

• The addition of MWD/PWD for SWF purposes adds $20,000 to the cost of a well. • The use of 24-in./26-in. casings adds $500,000 to the well cost. • Pilot holes add $300,000 to the cost of a well. • The use of SWF cement adds $200,000 to the cost of a well. • The use of a riser for drilling the shallow section adds $500,000 to the cost of a

well. Planning for the purposes of identifying shallow geopressured sands prior to drilling typically adds $20,000 to the cost of a well.

Minor flows in exploration wells can typically be tolerated, but minor flows in development wells need to be quantitatively assessed. Stress induced in nearby wells from planned or executed drilling operations can be modelled using current geo-mechanics understanding. Appraisal wells should be designed to collect data on SWF sand strength, porosity, permeability, pore pressure, and seismic properties and overlying fracture gradients to reduce risk associated with development design. Techniques to drill SWF sands using dual gradient mud systems hold high promise to significantly reduce risk associated with developments in areas of SWFs and provide a means to set shallow casings significantly deeper; thereby, significantly reducing well costs.

Risk assessment Failure of an exploration or appraisal well in an isolated location can result in the loss of the well, reduction in evaluation of objective horizons, hydrocarbons to surface, disturbance of seabed integrity, and reduction in shallow fracture gradients for future drilling. Failure of a development site can result in all of these potential problems as well as the loss of nearby wells. The probability of the occurrence of these events can be quantitatively calculated using current fluid mechanics, petro-physics, geo-mechanics, and material strength understanding. Fluid mechanics can be used to determine down hole pressures for any of the drilling techniques that might be employed to control shallow water flows (PWD can be used under actual operating conditions). Petro-physics can be used to determine brine flow rates from shallow geo-pressured sands, given the down hole wellbore pressure. Geo-mechanics can be used to determine sand erosion rates, given the brine flow rates and petro-physical properties of the formation (rates can also be determined from PWD data under actual operating conditions). Given expected drilling constraints, total sand erosion can be estimated and distributions of stresses in the well area estimated, quantitatively. Stress distributions can then be used to determine stress loads on the drilling or adjacent wells. This would allow material strength relationships to be used to assess the degree of loading on wells and the probability of collapse, buckling, or failure. Operators are currently in the process of assembling software models that will allow simulation of the drilling of a SWF site and to determine stress loading on casings for a variety of drilling techniques. From such modelling, a variety of operational drilling proposals can then be simulated and the stress loads evaluated and relative risks quantitatively assessed. This will be used to determine a plan of action that provides the desired risk/cost ratio. This same model will be used to monitor stresses while operations are conducted. If stresses are building at a higher rate due to drilling conditions or changes in formation properties, operations can then be altered or well placement changed to mitigate the risk of a failure. Some additional steps can be taken to aid in reducing the risk of well failure due to SWFs. These include:

1. Running baseline casing caliper logs and directional surveys to serve as a baseline for detecting early signs of buckling

2. Running ditch magnets to monitor metal shavings for detecting early signs of

casing wear that might be caused by early stages of buckling.

3. During the appraisal process, enhancing the ability to model stress behavior at a potential template site should be included. Critical data to obtain are sand strength, shallow LOT data, formation pore pressure, seismic properties of the geopressured sand packages, and sand permeability and porosity.

Sand prediction The prediction of geo-pressured sands requires two separate exercises, i.e.

1. predict the sand 2. predict the presence of geo-pressure.

Sand prediction The presence of sand is best predicted, assuming no offset wells in the immediate area, using seismic attributes. A number of different techniques exist to identify sands. Best practices would use as many of the different techniques as feasible at a proposed location. These techniques include: Offset correlation - Shallow sands from offset wells can be identified from logs or measurement while drilling (MWD) data in those wells. Equivalent stratigraphic age units mapped from the offset location can also be related to the proposed location using seismic data. This provides a first cut at identifying intervals that might have high potential for sand. Seismic stratigraphy - Seismic images are used to develop a depositional model of the intervals of interest at the proposed location. Once a depositional model has been established, analogs can be used to identify the most likely areas for sands to have been deposited. Previous experience in the GoM has shown the following depositional environments to be sand prone: slope fans, parts of the levee system, lag sands in channels, and on unconformity surfaces. Amplitude character interpretation - One method uses RMS amplitude maps between key sequence boundaries, time, and horizon slices, and various edge detection maps. Generally, amplitude itself has not proven a consistent indicator of sand. However, amplitude character has proven quite useful. It is best to determine the character of amplitudes associated with shallow sands in nearby wells and then look for that character in the seismic section at the proposed location. Typically, this character has been: discontinuous, moderate to high amplitude. Amplitude geometry - The shape of an amplitude anomaly can be an important tool in discriminating sand, particularly when it can be looked at in the context of expected depositional environments. Using 3-D data from either high resolution conventional seismic or from 3-D hazard data can allow the interpreter to picture the shape in three dimensions. Matching that shape to the type of sand can significantly increase the reliability of the prediction.

2-D & 3-D Seismic interpretation. Predictions can be made from 2-D and 3-D conventional seismic and 2-D or 3-D hazard data. The seismic data needs to be properly conditioned for use this shallow. Water bottom multiples need to be removed. Care should be taken to restore the resolution normally lost when the data is reduced from typically 32 bits to 8 bits in making the data set manageable in size for conventional prospect processing. Restoring the high resolution can greatly enhance the ability to image these shallow sands. Reprocessing of the data may also be required to enhance imaging shallow. Closer trace spacing can greatly enhance the ability to image highly dipping objects such as rotated slide blocks. 3_D migration will reduce the number of out-of-plane objects that might lead to mis-interpretations in 2-D data. Once the sand prone facies have been mapped, the probability of pressure needs to be established. Normally pressured sands pose little risk to drilling in these shallow sediments.

Seismic Rules of thumb

1. The best practical approach for assessing the potential for SWF in a deepwater well is through a pre-drill seismic stratigraphic analysis using some combination of 3D seismic data and high-resolution seismic data.

2. Offset well information is used to correlate known SWF or no-SWF sediments, but the available data may be limited and/or the offset wells may be distant.

3. The final risk assessments for SWF are necessarily qualitative as they are most often made with limited information and are, so far, based on simple models.

4. Nevertheless, pre-drill assessments have been shown to be reasonably effective for identifying potential SWF sediments in order that they be either avoided, or planned for during the well design

Pore pressure prediction Accurate knowledge of pore pressure prior to drilling can be used to reduce induced fractures, to select appropriate mud weights to prevent flow, to design stable cement slurries, and to eliminate any confusion that may arise over wellbore storage. Determining the absence of overpressure (the pressure over and above hydrostatic) can be used to essentially eliminate the need for nearly all special drilling and casing practices associated with shallow water flows. Two approaches are generally used for the prediction of pore pressure in shallow sands.

1. Accurately determine pore pressure in the shallow sands. 2. Determine if overpressure is present, regardless of the magnitude.

Accurately determine pore pressure Although the first attempts to provide much more accurate data for the tailoring of the operations, practical limitations frequently make it difficult to accomplish.e.g. Formation testers (FT) have met marginal success in these shallow sediments due to the lack of consolidation of the sands. The very low effective stress provides little formation strength to support the FT packer pressures or to resist the force of the drawdown created by the tool. Success may be improved if FT's are attempted in a pilot hole and with maximum pad surface area. Pad radius of curvature should conform to the bit size, a potential problem when working with large diameter bits. Sand control in the FT probe should be used to prevent plugging of the probe and tool flow lines. Mudcake also needs to have been developed in order to isolate the formation pressure from the hydrostatic of the borehole. Overbalance must also exist to suppress sand erosion and associated hole ruggosity. Formation pressures have also be measured in shallow sands using the Fugro-McClelland "Dolphin" device which measures permeability and pore pressure using a probe permea-meter. This device was used successfully at the Mars development site in the MC 810 #5 well but has not been used elsewhere in the deepwater GoM due to the expense and time required to run it. Most determinations of sand pore pressure are however accomplished by performing a series of flow kill activities using a variety of mud weights in open hole and observing the wellhead with the ROV. In order to capture accurate data, a minimum of one hour should be planned to verify that the placed mud weight has indeed killed the flow and to distinguish induced flow from natural flow. Care should be taken to minimize the number of kill operations performed as each operation will likely cause erosion of sand during the displacement operation. Each displacement operation also consumes a considerable amount of rig time and is, therefore, costly. Limited kill operations can at least be used to confine estimates of formation pore pressure. Pore pressure can be calculated in sands at the proposed locations when accurate pressure information is available in sands that are in pressure communication in offset

wells. These pressures can be projected to the proposed location using standard techniques and appropriate formation water gradients (typically on the order of 0.455 psi/ft).

Determine if overpressure is present The second philosophy is to simply determine if sands are over-pressured prior to drilling. In this method the actual magnitude of overpressure is not determined. This philosophy is useful in exploration and appraisal wells, but not suited in development drilling where more accurate knowledge of pore pressure may be required to minimize interaction between closely spaced wells. The usefulness in exploration and appraisal wells lies in the fact that many intervention methods well suited for isolated wells do not necessarily require accurate knowledge of the pore pressure. In these cases knowledge that the sands are overpressured is all that is required to implement the appropriate containment plan. (see the section on strategies). The presence of overpressure in sands requires two elements,

1. a source of pressure and 2. seal to trap the pressure.

There can be a variety of sources of pressure, but in the deepwater GoM, high sedimentation rate is the most common source of pressure. High sedimentation rate can be identified from seismic correlation. Correlate the layer associated with the shallowest paleo pick in the nearest offset well to the new location and use that pick to determine sedimentation rate.

Rules of thumb.

1. If sedimentation rates are less than 500 feet per million years everywhere within the footprint of the sand, then overpressure is not likely.

2. If sedimentation is above 500 feet per million years, seal quality will determine if

that pressure has been trapped. Seals can be identified from seismic data (typically very bright, continuous parallel reflectors). The seals need to be regionally continuous and must not have been breached by channels, slumps/slides, or faulting in the vicinity of the proposed well. If seals are present and sedimentation rate is above 500 feet per million years, treat the sands below the seal as pressured for planning purposes.

Fracture Gradient Prediction Another key to successfully drilling through shallow water flow sections is the proper determination of fracture gradients in conjunction with the pore pressures. The relationship between these two determines how close casing must be set to sands to insure proper control of the pressure within the sand without losses in the overlying shale. Only proper mud weight selection and management will minimize induced fractures and wellbore storage while maintaining hydrostatic to control the flow. It is thus common to drill with much lower operating margins (e.g. 0.3ppg) between mud weight and fracture gradient in top hole sections because of the narrow pore pressure fracture gradient windows. The prediction of fracture gradient also requires accurate estimation of overburden and pore pressure. Adjustments to the overburden may be necessary when working in or below salt or in unusual sediments , i.e. chert. However, nearby analogs should always be checked to validate the appropriateness of this estimator. Overburden and pore pressure need to be combined to estimate fracture gradient.

Operational Guidelines Operational Guidelines Different operational guidelines that have been developed to approach shallow water flows, and can be classed into the following presented in their order of general preference. 1. Avoid well developed sands - The reduction of these sand properties will significantly reduce the potential for flow and reduce the risk of losing the well to a shallow water flow. Properties should be distinguishable through careful analysis of seismic and hazard data. This is viewed as the preferred approach when there is no compromise to well objectives, or expense, particularly in development locations. 2. Set casing above the sand - When shallow geo-pressured sands cannot be avoided by well placement, casing must be set above the sand, riser run, and formations drilled overbalanced. The practicalities will depend upon; the water depth, the depth of the geo-pressured sands, and the ultimate number of casings required to reach the final total well depth to achieve required well integrity. Drilled overbalanced, the sands will not flow. 3. Tag the sand - If there is a risk of high pore pressures and narrow margin between pore pressure and fracture gradient, it will be very important to get the casing set immediately above the sand. Therefore it would be beneficial to tag the sand with the bit and then set casing immediately above the sand, to ensure cement integrity of the casing above the sand while retaining the option to squeeze the shoe if the geo-pressure of the sand interferes with the cementing operation. If wells are in close proximity, minimize the time the sand is allowed to flow, as sand erosion will occur during the flow which may increase risk of buckling casing in nearby wells. 4. Drill through the sand. When 1-3 are not practical should a decision may be taken to set 20 inch casing through the sand. Risk are higher and failure of the primary plan can result in costly and risky remedial action. This need will increase as the water depth increases and the depth of the sand below mudline decreases. Techniques, tools, and procedures to help insure success are discussed later in this section. Steps MUST be taken to eliminate sand erosion associated with water flowing from the sand.

Development site considerations When planning a multiple well development site, special considerations are required. 1. The spacing of wells will significantly impact the risk of a shallow waterflow event damaging adjacent wells. Well spacing driven by the balance between the risk of an event in one well affecting adjacent wells and the increase in facilities cost associated with increasing the spacing between wells. Ahmed Abou-Sayed at the first URSA site demonstrated that the interaction between wells during a SWF event can be accurately modelled. This modelling can be conducted at future sites during the design phase to help find the optimum well spacing. Accurate modelling require the following information: sand thickness, depth, porosity, permeability, and overpressure. Information from extended leak-offs will also prove valuable in developing operational plans that will minimize fracturing between wells during drilling and cementing. Shell demonstrated that accurate extended leakoffs can be run without a riser at the first URSA template site. It would be prudent to plan the gathering of this data during the appraisal process. When drilling the shallow section at a development site, it is also important to minimize the erosion of sand to prevent the interaction between wells. If shallow sands cannot be drilled with the marine riser in place, serious consideration must be given to drilling riserless with mud to minimize the sand production

Drilling Techniques Drilling techniques need to be designed to accomplish the following:

1. provide information about the quality and position of shallow flow sands, 2. identify an appropriate casing point in relation to a shallow flow zone, 3. eliminate or minimize charging of normally pressured sands, silts or permeable

zones, 4. check for shallow flow, and 5. provide mud properties for cementing.

The drilling objectives being to minimize the affects of shallow flow and at the same time, maximize probability of successfully controlling the zone.

“Rules of thumb” to prevent shallow water flows:

1. Install jet string using controlled jetting techniques. 2. Minimize casing reciprocation which disturbs the soil and reduces casing load

capacity.

3. Minimize the diameter of the hole drilled. This will help with cuttings removal and will improve cement displacement.

4. Drill hole in one pass (i.e. no pilot hole) will minimize erosion of sand and reduce

charging of shallow normally pressured sands.

5. Minimize circulation, pipe rotation and reaming to reduce hole enlargement.

6. Large diameter bits are preferred to under-reamers as they open the possibility of setting casing near the bottom of the hole, reduce the amount of exposure of the formation, minimize the amount of flow and associated sand production, and reduce the amount of charging.

7. Pump adequately sized sweeps to clean the hole every 10m (30ft) drilled to

minimise cuttings load.

8. Use low fluid loss mud sweeps where economically viable. E.g. fluid loss (less than 10 cc/30min.), low, flat gel strength ( 10 sec., 10 min., 30 min.), YP- 10, PV-15 mud ready in the pits to spot in the event of a flow.

9. The mud weight should be sufficient to offset the hydrostatic pressure of the zone

with a slight margin, but not cause fracturing of weak formations or ballooning. A low fluid loss, thin filter cake, and low gel strengths will allow for effective and efficient hole maintenance, cement displacement at the low annular velocities..

10. Place MWD as near the bit as possible to assist correlation to seismic, for casing

point selection, sand location, thickness, and quality. This also ensures minimal sand penetration.

11. If a sand in penetrated, check for flow. If flow is encountered, observance should

determine whether the flow is persistent or dissipates over time. Charging of sands due to cuttings load can give a false indication of a flow zone.

12. ROV should be monitoring the wellhead continuously while drilling through

potential zones.

13. Use PWD (pressure while drilling) to monitor annular pressure when drilling riserless. PWD will display a shift in annular pressure when a geo-pressured sand is drilled, flows, and erodes sand.

14. The casing point should be as close as possible to the shallow flow zone to

maximize the shoe integrity.

15. If flow is encountered and the casing is set above the flow zone, spot heavy mud below casing point to act as base for cement.

16. A casing packer can help maintain cement segregation as well as keep the flow

from disturbing the cement during transition (see the section on special practitces).

17. If drilling proceeds through the flow zone, flow from the zone should be

minimized to reduce sand accumulation at the mudline, hole enlargement, and potential damage to nearby wells.

18. Use production cementing practices when cementing the strings above and

across the shallow flow interval. - Use centralizers. - Pre-flush density should not allow the zone to flow. (i.e. do not use seawater

ahead of the cement, maintain hydrostatic during cement job). - Use inner string cementing to reduce volumes pumped and contamination. - Fill casing with kill mud to prevent circulation of seawater during cementing. - If permissible, reciprocate casing in place across the flow zone

19. Reduce surge when running casing. Use convertible float shoes if necessary.

20. Use flow resistant cement slurries as detailed in cement section.

21. Accurate knowledge of leakoff data is essential to efficient drilling in the shallow

section.

22. Extended leakoff's should be conducted unless there are existing conditions where it would not be prudent, i.e., nearby faults to the surface, in salt, etc.

23. At development locations well spacing should be maximized to minimize

exposure to problems resulting from inadvertent flow in adjacent wells.

24. Development drilling operations should include alternate sequencing to maximize the time and distance between operations on adjacent wells.

Cementing techniques The objective of cementing in shallow water flow areas are to:

1. achieve a competent seal that will prevent fluid movement, and 2. give structural support to the casing.

The key to successful conductor casing cementing is to improve mud management, to shorten slurry transition times, and make mud and cement slurry weight compatible with formation pore and fracture gradients. Containment is complicated by weak formations that can fracture and cause loss of mud and cement returns. Design parameters for deepwater cementing include pump time, free water, fluid loss, rheology, transition time, density, compressive strength, and compressibility. Free water If the slurry has excessive free water, channels will form that may result in a loss of zonal isolation. Free water will also lead to a slurry volume reduction. As water is removed the pressure in the column will drop possibly leading to an influx of reservoir fluids. Settling will cause density differentials that may result in insufficient hydrostatic pressure to maintain zone control. Rheology The primary concern is efficient annular fluid displacement. The lead slurry must generate a friction pressure greater than the spacer and less than the tail slurry. Transition time The transition time should be kept as short as possible to reduce exposure to flow. Transition time is defined as the time lapse between onset of hydration until cement gains compressive strength. During transition time the shallow flow can migrate up through the setting cement slurry, forming channels that destroy cement integrity. Fluid migration is possible during the transition time because the cement column begins to support itself and stops exerting hydrostatic pressure on the fluid source, but does not have enough compressive strength to prevent fluid migration. A variance in temperature of a few degrees from the planned temperature can adversely affect transition time. Density The cement weight, as well as spacer weight, must be designed to maintain hydrostatic pressure during the displacement process without exceeding the formation strength. Compressive strength The cement must develop adequate mechanical properties to support the casing for the life of the well. Obtaining the compressive strengths needed requires special cement blends at the densities and temperatures involved. Compressive cements Compressed gas in cement will maintain pressure in the slurry above the pore pressure as the cement is in the transition phase. The large volume of gas will also help compensate for slurry volume reductions due to fluid loss and volumetric shrinkage.

Two major cement systems have been developed for shallow water flow control as follows:

1. Microfine cement in combination with mircospheres provide a light weight high performance cement slurry. It allows control of the density to prevent formation fracturing, thereby enabling full returns during placement, provides for transition times of about 30 minutes, low fluid loss to maintain hydrostatic, and provides the compressive strengths needed at low densities in the cool temperature environment. Densities range from 11.0 ppg to 14.0 ppg for the lead with base slurry for tail at 15.2 ppg.

2. Nitrogen foamed cement provides a variable density high performance slurry. It

allows control of density on the fly, provides for transition times of about 45 minutes, provides fluid loss control, low free water, and provides superior compressive strength and improved ductility at low densities in the cool environment. It provides the best compressibility possible to prevent flow. It provides efficient mud displacement. Requires cryogenic fluid on deck and higher friction pressure losses. Densities range from 11.0 ppg to 12.5 ppg for the lead with base slurry for tail at 15.2 ppg. The density is easily changed by the amount of gas injected and the density can be varied throughout the column. Special dry blends are not required. Limitations are as follows: Foamed cementing requires additional specialize equipment, software, and personnel expertise; requires cryogenic fluid on deck; has higher friction pressure losses; and refrigerated test equipment is limited.

In general all techniques used in production casing cementing should be considered. In addition to the above the following should be considered:

“Rules of thumb” Shallow flow cementing.

1. Centralise casings to prevent the formation of channels. E.g. Standoff efficiency required entails a minimum of two centralizers per joint from the shoe to at least 50 feet above any geo-pressured sands.

2. Rotation and reciprocation of the casing can be used to improve cement

placement, however, insure that the mechanical features of the casings hanger mechanisms and seals are suitable.

3. The lead cement should be designed to set after the tail cement thereby

maintaining hydrostatic pressure until a seal is formed.

4. Tail cement should be placed across the flow interval.

5. The cement should be pumped in place as fast as possible.

6. Minimize seawater circulation prior to cement job as outlined in drilling techniques section.

7. Dyes, mica flakes in spacers and cement can be useful as an informational aid. It

is frequently difficult to distinguish cement from mud with the ROV. Dyes may improve the ability to recognize cement.

8. Consider using the ROV to capture cement samples at the mudline to determine

if cement returns reached mudline and for future cement volume adjustments

Preparing for “open water” shallow flow(s).

1. A onshore and offshore (pre-spud) meeting shall be held prior to commencing drilling operations. Shallow Flow Procedures, roles and responsibilities, communications, and actions planned for each category of personnel on board should a shallow flow occur would be discussed.

2. Weather forecast and tidal currents expected for the anticipated period from spud to setting the casing would be reviewed and incorporated into plans.

3. Discuss emergency procedures for dropping drill string if damage to rig structure is likely whilst moving off location. Ensure procedures are posted at various locations around the rig. E.g. drillfloor, recreation rooms, etc.

4. Inform standby boat of intended operations ensuring it is operating in a safe zone with respect to the rig’s position at all times.

5. Saltwater service pumps will be maintained on line at all times to ensure adequate seawater supply available at the pits. Check the delivery rate of the seawater to the pits prior to commencing drilling operations.

6. All hot work will be suspended prior to riserless drilling if seismic surveys show likeliness of shallow flow anomalies. Otherwise, hot work will be conducted while maintaining good communication with the Bridge/control room operator.

7. If seismic survey shows bright spots, personnel will only be permitted down in confined spaced with consent from the offshore installation manager (OIM). Entry will be strictly controlled by Permit to Work system from the Bridge/control room.

8. Ensure that cement unit is operational and can be connected quickly to the standpipe manifold to be used when needed.

9. Ensure that specified bulk material is onboard. (barite, bentonite, cement.) to meet any contingency required.

10. A minimum of two pits of kill mud must would be prepared, normally 0.2 - 0.4 s.g. heavier than the active weighted fluid, care must be exercised not to break-down formation with kill mud weight.

11. The Radio/control room Operator should have pre-written and addressed faxes ready for informing the relevant authorities of any shallow gas emergency. Emergency contact numbers are to be readily available in the Radio Room and on the vessel bridge/control room.

Operating procedures.

1. Ensure standby boat is operating in a safe location at all times. 2. In the event that shallow flow is encountered, the Bridge/control room will be

first point of contact, who will then contact the OIM, the Company Representative and the Radio Room, where senior personnel will then make maintain necessary emergency preparedness.

3. A 24 hour watch will be maintained by the ROV and in the moonpool areas.

This watch will contact the Bridge/control room every 30 minutes for a status report. ROV operator/Watch instructions would be typically to report immediately any sign of flow to the Driller, Bridge/control room immediately. The watch person would be relieved at regular intervals and must remain in constant contact with the Bridge and the ROV Operator in order to confirm the direction of the current, checking over the side of the rig from time to time.

4. Continuous and early warning Seabed monitoring detection will be provided

by the ROV that will remain at a safe distance from the well. The ROV Operator will report any signs of flow to the Driller and the Bridge/control room immediately.

5. Flow checks are to be made using ROV prior to displacing to gel mud and

prior to pumping out of hole. Flow checks should be long enough for the cuttings at the wellhead to settle after the pumps have been switched off. Continuing disturbance at the wellhead may be an indication of the well flowing.

6. Trips out of the hole will be executed at a pre-determined and controlled

tripping speedrate so as to minimise swab pressures. All stands will be pumped out.

7. Hot work in zone 1 areas will only to be undertaken if it is extremely urgent.

All hot work would be closely monitored, and immediately shut down upon first signs of flow.

8. All watertight doors and hatches should be kept close while drilling open

water hole sections.

Flow detection during riser-less operations. 1. Changes in drilling parameters (drilling break, pressure while drilling sub ECD

changes, ) can be detected at the drill floor, by the mud loggers. 2. Seabed monitoring by ROV or rig camera, maintained at a safe distance from

the well, for subsea visual contact.

3. The constant watch keeper in the moonpool as described in previous sections.

Emergency procedures. If shallow flow is detected or encountered, the following procedures will be performed:

Drill Floor

1. In the event that shallow flow is encountered/detected, the Driller will inform the Bridge/control room immediately.

2. The Driller will inform the Assistant Driller as to the extent of flow release. The

Assistant Driller will ensure that the entire drill crew is accounted for.

3. The Derrickman will line up the mud pumps on the prepared mud, then kill mud and then back to sea water as instructed by the driller.

4. Pump mud immediately, at maximum pump rate.

Note : Pumping must not be stopped to switch to kill mud. Killing of a shallow flow is a “dynamic kill” operation and the greatest chance of success occurs if the kill fluid is pumped before any significant washing of the hole has taken place. All available kill mud should be pumped at first attempt.

5. The Driller will maintain rig pumps circulating and evaluate the situation with

the Assistant Rig Superintendent advised by the OIM and the Company Representative assembled on the vessels Bridge.

6. In the event that the hole is not killed, does not bridge and if flow continues to release, further contingency procedures will be initiated.

Bridge/ control room

Bridge Control 1. The Bridge/ control room will contact the Barge Engineer, OIM, Company Representative and the Radio Room to standby.

2. The OIM, & the Company Rep will proceed to the Bridge/ control room. The

Toolpusher will proceed directly to the Drill Floor to evaluate the situation.

3. The Bridge/ Control room will announce the designated muster point. All departments will report to the muster point except the on duty drill crew and members involved with the emergency procedures.

4. Bridge/ Control room will establish non-interruptible lines of communication

with the Drill Floor by the use of sound powered telephone or hand held radio systems.

5. The standby boat will be informed of the shallow flow release and placed on

stand by in a safe location.

Shallow flow procedures.

Shallow flow “detected” while drilling Driller 1. Inform the Bridge/control room immediately. 2. Inform the Assistant Driller that flow is detected. 3. Pump all mud and/or kill mud available at maximum pump rate.

If hole does not bridge off and the flow continues. 4. Maintain maximum rate with rig pumps circulating sea water.

Evaluate situation with OIM, Toolpusher, Company rep. Assistant driller. 1. Ensure that the entire drill crew is accounted for. 2. Inform toolpusher and company representative. 3. Assist driller as required. Derrickman 1. Line up the mud pumps on the prepared mud, kill mud as

advised, then back to sea water is flow is not controlled. 2. Leave the mud pumps lined up to sea water Drillcrew 1. Muster on the drill floor.

Shallow flow while tripping or running casing.

Driller 1. Install safety valve and/or top drive. 2. Inform the Bridge immediately. 3. Inform the Assistant Driller that flow is detected. 4. Pump all mud and/or kill mud available at maximum pump rate.

If hole does not bridge off and the flow continues. 5. Maintain maximum rate with rig pumps circulating sea water.

Evaluate situation with OIM, Toolpusher, Company rep. Assistant driller. 1. Ensure that the entire drill crew is accounted for. 2. Inform toolpusher & company representative. Derrickman 1. Line up the mud pumps on the prepared mud, kill mud as

advised, then back to sea water is flow is not controlled. 2. Leave the mud pumps lined up to sea water Drillcrew 1. Muster on the drill floor.

Shallow flow during after cementing

Driller 1. Inform the Bridge immediately. 2. Inform the Assistant Driller that flow is detected. 3. Await further instructions to perform remedial operations Assistant driller. 1. Ensure that the entire drill crew is accounted for. 2. Inform toolpusher & company representative. 3. Assist driller as required. Derrickman 1. Secures the pump room before leaving to muster on the drill

floor. Drillcrew 1. Muster on the drill floor.

Special Practices

Mechanical shut off devices Mechanical shut off devices are designed to provide a second sealing mechanism along with the cement. During cement transition hydrostatic pressure is reduced and the mechanical devices provide a pressure seal which prevents the shallow flow zone from

disturbing the cement. This mechanical control is usually accomplished in two ways. First, the shoe of the jet string is effectively deepened by installing an intermediate string between the jet string and the casing which is run across the shallow flow zone. This intermediate string provides the shoe integrity needed to seal the zone as the jet string shoe integrity is not sufficient to hold the shallow flow zone. Secondly, a mechanical device to seal the annulus between the intermediate string and the casing string which is run across the shallow flow zone. There are some exceptions but the majority of the systems use these principles. Mechanical shutoff devices can have a serious downside. Any pressure trapped at the seal is also equally applied to all points in the well. The conductor shoe typically does not have much strength and it will not take much trapped pressure at the mechanical shut off device to fail the conductor shoe and cause flow outside the conductor to the seafloor. Remediation of flow outside the conductor is much more difficult than flow inside the conductor and minimal flow outside the conductor may do significant damage to its load capacity. This practice should never be used without an intermediate casing string.

Other Mechanical devices. Other groups are working on a riserless drilling project involving a subsea blowout preventer (BOP) and rotating drilling head mounted to the initial casing joints by an inflatable packer. Intent would be to use riserless technology to address the first 1,000 ft below the mudline, to get past the potential flow zones. This would provide the well integrity needed to contain the SWF and allow the initial casing joints to be set. Using such technology, the operator would set one joint of casing at the mudline, install the "virtual riser," includes a subsea rotating control head and high-presssure BOP mounted to the casing by an inflatable packer. This virtual riser allows the operator to maintain back pressure on the SWF.

The back pressure would comes from the mud pumps, which pump seawater through the bit and up the annulus against the control head. The mud pump pressure can be regulated by controlling the amount of back pressure needed to contain, but not invade, the formation. One advantage of this solution is that the packer, BOP, and rotating control head are all off the shelf hardware that have been proven in the field and only need to be made suited and proven in deepwater.

External Casing Packers External casing packers have been used successfully to control flow and insure that cement is allowed to cure without disturbance from flowing sands. They offer the additional benefit, when place opposite sands, of helping to insure that any erosional cavities are filled, thereby reducing the chance that sand may later mobilize to fill the void and increase the load on the casing. The packers will be most effective if placed immediately above the geo-pressured sand and inflated after the cement is placed.

Shallow water “subsea”diverter Shallow water diverter are also under development e.g. there are a total of three hardware JIPs currently targeting this emerging problem. These solutions may beneficial, but may not eliminate the SWF phenomenon. In fact, there some SWF conditions might actually be aggravated by such systems. E.g. sand flows. Diverting could lead to a washout and potential crater around the subsea BOP. In a sand flow situation, the well is being drilled riserless. When it hits the sand flow, the SWF zone begins producing a massive amount of water, sand, and debris.These flows can be spectacular. E.g. In a video presentation at the seminar, one operator showed a tape obtained by an ROV camera of a SWF producing plumes of sand and debris that boiled up 60 ft from the seafloor. One attendee described it as an endless column of black water building huge mounds of debris around the subsea BOP stack. With flow rates as high as 25,000 b/d, the water in the flowing sand is usually quickly depleted. The sand in the flow zone then compacts and gives up its porosity under the pressure, which actually increases the flow. It is suspected that this was the situation at Ursa.

Riserless Drilling Drilling with mud and returns to the seafloor can insure that sands do not flow nor erode sand. The distribution of hydrostatic pressure when drilling with mud returns to the seafloor mimic's the typical fracture pressure curve which opens the possibility of significantly reducing the number of casings required. This technique was tried on the MC 899 #5 well. The major problems are associated with logistics involved in being able to access the significant amount of mud required and in insuring that the released mud does not negatively impact the environment. If these two issues are addressed this could be a preferred method of tackling shallow water flows.

Use of 24 Inch Casing A number of operators have set 24 inch casing above the SWF sand to aid in drilling through the sand. When a 26 inch riser is available to use with that 24 inch casing, the benefits are obvious. However, when a riser is not available, the benefits of the use of a 24 inch casing are much less obvious. It use would prove beneficial in cases where conventional riser with a pin connector or when using a subsea diverter. The 24" casing is one of the best options to use when the geopressured sand is shallower than the expected tail cement on the 20" casing. However, when drilling without a riser or diverter or when the top of any pressured sands is covered by the tail cement of the 20" casing, the 24 inch casing provides very little benefit, if any, but does increase the exposure time of the formation and adds in excess of half a million dollars onto the well costs. The benefits of the use of 24 inch casing should well understood before invoking a decision to incorporate it. Example; Vastar Energy, a fully owned subsidiary of Arco Oil and Gas, used weighted drilling fluid with seabed returns to drill the Mississippi Canyon 941 #2 well in the GoM. This well is offset to the Exxon MC 941 #1 well which was drilled in 1991 and was lost before reaching planned TD due to complications associated with shallow waterflows. Vastar premixed 25,000 barrels of 11.4 ppg calcium chloride mud with viscosifier onshore and shipped it to the rig using conventional supply boats. The premixed mud was stored in four 7000 barrel ballast tanks of the Diamond M rig. The mud was weighted on the fly to a 13 ppg density using calcium carbonate. Vastar drilled with seawater until geopressure was detected through convention flow checks, at which time, they switched to drilling with the weighted mud. They drilled 1200 feet of 26 inch hole at an average ROP of 80 fph with the weighted fluid. Upon reaching TD the calcium chloride drilling fluid was displaced with a conventional kill mud. 20 inch casing was run and while cementing, the lines to the cement unit plugged. The partially pumped cement was fully displaced with seawater and the well was allowed to flow while a new kill pill was prepared. The well was then killed and successfully cemented with foam cement. Reported mud costs for the surface hole was approximately $2,000,000.

Drive in casing Drive surface casing to the top of shallow water flows zones and thereby increase casing integrity and reduce possibility of water or sand production and associated compromise of casing structural integrity. Operators view this as applicable to preventing shallow water flows in only the shallowest of the known cases and therefore not widely useful in the current drilling environment. However, this technique may prove to be useful when used in conjunction with the mud lift system currently under development and due to be delivered in 2002. A deep driven conductor could be used as the foundation for the mud lift system and rotating BOP in a riserless arrangement. The Deepstar work has been focusing on establishing technical feasibility of the installation method. It also includes the preparation of scope of work, sequence of operations, and cost for an actual offshore test that will be required to validate the installation method. Theoretical results show that a hammer of the size of the IHC S-280 will be required with a minimum 39 inch internal clearance and a casing of a minimum outside diameter of 42" to accommodate it. The casing is driven close-ended. Preliminary casing design and bottom hole hammer interfaces have been performed to optimize fatigue life and lifting/handling issues. Given typical GoM deepwater soil strengths, the casing might be driven to 850-1000 ft using the IHC S-280 hammer. Sand layers 40 ft thick located as deep as 600 ft below mudline should be penetrable. Sands layers either thicker or located deeper might cause refusal. Key findings from studies conducted include: (a) 42"OD conductor can penetrate 1000’ BML in normally consolidated clays and to

650’ BML in the presence of a 40’ dense sand layer; (b) Preliminary designs of the hammer system were prepared by two hammer

manufacturers (IHC for 42" and MENCK for 48"); (c) A driving shoe was designed to satisfy conductor fatigue criteria; and (d) Conductor/hammer deployment handling procedures developed.

Chemical alternatives Stabilization polymers or resins that, when put in place, could potentially seal off the SWF zone and add strength to sediments. This would be a particularly attractive solution in the above mentioned sand flow situations in which stopping the flows early is critical to saving the well. One product that has shown promise is currently being applied to the rubble zones above and below a salt intrusion. These areas are technically stressed, meaning there is a risk of the rubble entering the wellbore. Formation-control-while-drilling products that include water-based epoxy resin that may have SWF applications. Such products could be combined with a water-based drilling fluid to improve the integrity of a formation, in effect increasing the fracture gradient

and decreasing the pore pressure. The products penetrate and seals the pores of the formation and have been tested at compressive strengths up to 10,000 psi, higher than any formation strength it is likely to encounter and at temperatures as low as 50° F, which is similar to those found in SWF zones in the Gulf of Mexico. In an SWF zone, the product could be transported downhole with a heavy weight mud to hold back the flow zone while the epoxy penetrates the formation and sets. In addition to sealing the formation, Products may also to the development of a stronger mud cake. Placement and pump times can be tailored from 2 to 12 hours. Sodium silicate pill has been used to control unconsolidated sands and could also have SWF

applications if it were applied to the right strength flow before it was flowing too hard. The key to this product and any chemical treatment for this condition, would be to kill the flow first so the product would have time to work. It is thus seen as essential that the well is killed before any treatment is considered. The worst mistake is to drill through the flow zone expecting the pressure to deplete and the problem to go away.

Remedial operations/P&A concerns

Once shallow flow has initiated behind pipe, it is usually very difficult to stop. The general approach is to stop the flow temporarily and then cement for long term control. Identification of the flow interval and pressure is important. If logging while drilling data is not available it will be necessary to run temperature, noise, or thermal decay logs to determine the flow interval. However, this data may be very difficult to interpret and some experience has shown the only reliable source of detection is the water flow version of the thermal decay log. Once the location of source of the flow is determined, operations can proceed to stop the flow. If the flow is behind pipe, this usually requires perforating the casing, setting a cement retainer for control, and pumping kill mud on the back side of the casing. Once the flow has stopped, cement is pumped to seal off the annulus. Various types of cement have been used such as diesel oil cement with synthetic fluid for base oil, standard, and right angle set cement. However, in most cases the annulus area is very difficult to cement due to it's size and requires high placement rates. Also, any additional pumping enlarges the disturbed area. Very often after cementing the flow creates an alternate path to the mudline. Flow has been found to broach as far as several hundreds of feet from the wellhead.

References Alberty, M.W., Hafle, M.E., Minge, J.C., and Byrd, T. M., " Mechanisms of Shallow Waterflows and Drilling Practices for Intervention", Proceedings, 1997 Offshore Technology Conference, OTC 8301 Byrd, T. M. Schneider, J.M., Reynolds, D.J., Alberty, M.W. and Hafle, M.E., " Identification of 'Flowing Sand' Drilling Hazards in the Deepwater Gulf of Mexico", Proceedings, 1996 Offshore Technology Conference, OTC 7971 Campbell, K.J., Humphrey, G.D., "Shallow-Water-Flows: Origins and Prediction", Proceedings, 1997 Offshore Technology Conference, OTC 8301 Campbell, K.J., "Fast-Track Development: The Evolving Role of #D Seismic Data in Deepwater Hazards Assessment and Site Investigation", Proceedings, 1997 Offshore Technology Conference, OTC 8306 Choe J., Juvkam-Wold, H.C., "Unconventional Method of Conductor Installation to Solve Shallow Water Flow Problems", Proceedings, 1997 Society of Petroleum Engineers Conference, SPE 38625 Corthay, J. E., II, "Delineation of a Massive Seafloor Hydrocarbon Seep, Overpressured Aquifer Sands, and Shallow Gas Reservoirs, Louisiana Continental Slope", ", Proceedings, 1998 Offshore Technology Conference, OTC 8594 Flatern, R.V., "Combating Shallow Water Flows in Deepwater Wells", Offshore International, v.57, no. 1, pp. 58,60, Jan. 1997 Griffith, J., " Guidelines for Cementing Deepwater Conductor Strings", Offshore, pp 46-48, January 1995 Griffith, J., Faul, R., "Mud Management, Special Slurries Improve Deepwater Cementing Operations", Oil and Gas Journal v. 95, no. 42, pp. 49-51 Griffith, J., Faul, R., "Cementing the Conductor Casing Annulus in an Overpressure Water Formation", Proceedings, 1997 Offshore Technology Conference, OTC 8004 Javanmardi, K., Flodberg, K.D., Nahm, J.J., "Mud to cement technology proven in offshore drilling project", Oil & Gas Journal, Special Feb. 15, 1993 Medley, G.H., Jr., Shallow Water Flow Technology Update", Proceedings, 1998 Offshore Technology Conference, OTC 8731 Nations, J.F., Medley, G.H., " Deep-Star's Evaluation of Shallow Water Flow Problems In The Gulf of Mexico", Proceedings, 1997 Offshore Technology Conference, OTC 8525 Simmons, E.L., Rau, W.E., Predicting Deepwater Fracture Pressures: A Proposal", Proceedings, 1988 Society of Petroleum Engineers Conference, SPE 18025 Snyder, R.E., "Industry Zeroes in on Shallow Water Flow Problems/Solutions", Deepwater Technology, pp 57-64, August 1997 (special publication of World Oil) Stiles, D.A., "Successful Cementing in Areas Prone to Shallow Saltwater Flows in Deep-Water Gulf of Mexico", Proceedings, 1997 Offshore Technology Conference, OTC 8305 Trabant, P.K., "Deep Water Drilling Shallow Water Flows: Practical Applications of Pleistocene Seismic Stratigraphy" Proceedings, 1995 Offshore Tecnology Conference, OTC 7675 Trabant, P.K., "Seismic Stratigraphy A Solution To Deepwater Drilling Problems", Oil & Gas Journal Sept. 27, 1993 OGJ SPECIAL

APPENDICES

Appendix 1: SWF incident report. Background: Green Canyon 463 #1 is an appraisal well in the Dominica basin where several other discovery and appraisal wells have already been drilled by BP and by Texaco. The offset wells in the basin have encountered shallow waterflows and have successfully handled these flows with foam cement. No wells in the basin have required 24 or 26 inch casing. GC 463 #1 is a BP operated well, drilled by the Ocean America. Kerr McGee is the only partner in the well. Pre-drill Prognosis and Plan: Analysis of seismic data and offset well resulted in placing a moderate risk of encountering a geo pressured SWF sand at 450 feet below mudline and a second moderate risk sand at 1150 feet below mudline. The drilling plan called for setting 20 inch casing 2,382 feet below mudline and using foam cement to contain any flows with the option to run an external casing packer above the shallowest geo pressured sand. Operational Summary: The well was spudded on August 28th, 1998 in 4038 feet of water. 36 inch conductor casing was jetted to 243 feet below the mudline. The well was then drilled ahead with a 24 inch bit and MWD/PWD. Pair of relatively clean thick sands were found between 466 feet and 616 feet below mudline. PWD showed flow from the sands immediately upon drilling into them (ECD increased from 8.64 to 8.95 ppg). A flow check at 548 feet below mudline confirmed the flow. While drilling ahead subsequent flow checks described the flow as varying from very slight to moderately strong. Additional sands were seen on MWD at 856 feet BML, 926 feet BML, 996 feet BML, and 1,226 feet BML. The 24 inch hole section was TD’d at 2,376 feet BML. A 13.0 ppg kill mud was placed in the hole and the ROV confirmed the well was dead. While tripping to the surface, the ROV observed the well flowing. The rig tripped back to 236 feet BML and pumped 200 bbls of 13.0 ppg mud. Tripped out of the hole. The ROV remained observing the wellhead for one hour, no flow. 20 inch casing was run to 2,349 feet BML and cemented with 972 bbls of 13.5 ppg foam lead cement and 145 bbls of 15.8 ppg foamed tail cement. Cement was observed coming from the cement ports on the well head and no flow confirmed immediately after the pumping of the cement ceased. Rig immediately rigged down for a hurricane on September 2nd. On September 5th, ROV was jumped and "small water flow" was noted coming from the 20x36 inch annulus. No remediation was performed. The rig was again evacuated on September 10th for a tropical storm. Rig was reoccupied on September 30th. On October 4th the flow was reported to have slowed considerably since first noted. Flow continued to wax and wane throughout the well. By the time the well was plugged and abandoned in late December, the flow had stopped on its own.

Lesson Learned: The operational team developed the following lessons learned relative to shallow water flows: Use MWD gamma ray/resistivity to identify shallow sands and use PWD to determine if the sands are over pressured. Use tracer in slug prior to pumping the kill weight mud at TD of the 24 inch section to help determine the amount of washout. Utilise foam cement in areas of moderate to high risk of shallow water flows. Do not shut off the 20x36 inch annulus as this may force flow outside the 36 inch. Moderate to low flows in the 20x36 inch annulus can be tolerated on expendable wells. Allow the pressure and flow to dissipate. Monitor carefully and record the data. Thoughts: PWD only identifies shallow water flow sands with sufficient velocity to erode sand (eroded sand is what increases the annular ECD). Lack of an annular pressure increase on PWD does not mean that a sand is not geo-pressured. All geo-pressured sands behind the surface casing should be covered with the tail cement. We should not expect the lead cement to provide hydraulic isolation in a 24 inch hole 1,900 feet above the shoe. Cement at this level will be heavily contaminated with mud. Casing at this level will likely be poorly centralized. The external casing packer could have been run above 466 feet BML as an alternative solution or 24 or 26 inch casing should have been set up as an option in the pre-well planning stage if shallow geo-pressured sands were predicted (as they were here). The 24 or 26 inch casing would need to be set at a depth where the tail cement would cover the sand at 466 feet BML. Once the flow is present, remediation is very expensive and potentially increases the risk of losing the well. However, a monitor program (calliper and/or deviation surveys) to identify casing loading should be started and a baseline log run. Periodic monitoring could help identify a casing collapse before it was too late.

Appendix 2. Seismic interpretation.

Identification of shallow water flow potential

SWF-prone intervals can be predicted by interpreting high-resolution 2D and 3D seismic data, in combination with offset well information. The purpose of pre-drill stratigraphic interpretation is to detect and avoid SWF-prone facies if possible, and to produce a tophole prognosis to be used for well planning. Stratigraphic interpretation is one of three aspects of the pre-drill SWF assessment. If a stratigraphic analysis of the seismic data predicts a high potential for SWF, then pore pressure prediction and fracture gradient prediction methods are employed to determine if the suspect intervals are likely to flow, and, if so, to determine if the flow can be contained.

Seismic data resolution Several types of seismic data are used for SWF assessments, including exploratory 3D, reprocessed exploratory 3D, high-resolution 2D (hazards), and high-resolution 3D. The low-resolution limitation of exploratory seismic data to interpreting geological detail is overcome, in part, by geologic information obtained from offset wells.

However, unless there are geo-technical borings or measurement while drilling (MWD) data, "high-resolution" geologic data typically is not available to constrain the interpretation. Without these, lithology has to be inferred from seismic data. Seismic resolution is important because SWF sands may be on the order of only tens-of-ft thick. A measure of resolution is given by the limit of separability between seismic reflectors. For exploratory 3D data, the limit of separability in the tophole section is about 28 ft, given a frequency of 50 Hz and a velocity of 5,500 ft/sec.

Reprocessing to generate a 3D short-offset volume typically yields a limit of separability of about 18 ft (75 Hz)

Typical 2D high-resolution airgun data can image reflectors about 9 ft apart (150 Hz). Similarly, high-resolution 3D seismic data can image reflectors 9 ft apart (150 Hz), but offers the significant added benefits of 3D data.

Seismic options Good quality 3D seismic data is the basic tool for SWF assessments. The ability to make map-view time slices and horizon slices in order to view gross sedimentary patterns, and the ability to quickly characterize stratigraphic packages with horizon-based volume attributes are some of the many advantages that 3D seismic data offers for

SWF assessments. Quality map images can often be obtained in the tophole section even with relatively low-resolution exploratory 3D seismic data.

• High-resolution 2D seismic: In most cases, 2D seismic is readily available from the 2D airgun (hazards) seismic, routinely acquired for the hazards permitting process. High-resolution 2D (hazards) seismic data can be used to calibrate 3D data and can improve lithologic, stratigraphic, and structural interpretations.

• Reprocessing: Another option to improve resolution is to reprocess to a short-offset 3D volume.

• High-resolution 3D seismic: This is the optimal seismic data set used for a SWF study because it offers far superior imaging of stratigraphic detail than exploratory or reprocessed 3D seismic data. High-resolution 3D, however, is not commonly acquired and usually is not available.

Seismic facies The identification of SWF potential from seismic data is largely based on both the evaluation of seismic reflector character and the recognition of depositional facies. Typically, SWF zones are found in sediments that contain isolated or continuous sandy sediments and that are overlain by an "impermeable" seal, which in turn has been buried by rapidly deposited overburden.

• Channels: Most SWF is associated with buried channel complexes. Buried channels and channel complexes often have high sand content, permeability, and connectivity. When sealed beneath rapidly deposited overburden, these buried channels can be high risks for SWF. Patterns indicating channels and channel complexes can be seen in 3D seismic data on datumed time slices (horizon slices). Bulk distribution of sands in a channelized unit can often be imaged by calculating volume seismic attributes that emphasize channel trends and the distribution of sands.

• Slumps and debris flows: SWF has also been encountered in overpressured

sands within rotated slump blocks and debris flows. Rotated slump blocks usually are best imaged with a series of vertical sections. Debris flows are best imaged with both vertical and horizontal sections. Coherency slices are also useful for imaging the discontinuities associated with slump blocks, and are particularly useful for imaging the internal discontinuities associated with debris flows. In both

cases, high-resolution 2D can help clarify stratigraphic and structural relationships.

Seal and overburden To produce overpressures, the rate of overburden deposition must be in excess of the ability of the sediment to de-water to normal hydrostatic pressure. If a regional condensed section (clay) separates an underlying sandy sediment from a thick section of rapidly deposited overburden, then the ability of sediments below the seal to de-water is further inhibited by the low permeability clay. Sediments other that regional clay seals may also contain overpressures. Rapidly deposited fine grained material are probably sufficient to induce overpressures and to act as a seal to the underlying sediments.

Regional clay seals in the northern Gulf of Mexico are often seen in seismic data as very continuous, moderate to high-amplitude, draping reflectors that mark significant seismic stratigraphic boundaries. Discontinuities in the seal horizon can be seen on horizon maps, especially in coherency displays. Acoustic blanking or other amplitude phenomena in the seal may suggest that breaks have occurred locally and overpressures have been transmitted through the seal. If the seal appears to be breached near the proposed well site, then significant overpressures should not be present.

Deep-towed side-scan sonar records and deep-towed pinger records are useful for determining whether overp-ressured fluids have vented to the seafloor along faults or seeps in the recent geologic past. Seafloor evidence for fluid expulsion suggests that over pressures have been reduced or been bled-off completely. The main cause of overpressures is rapidly deposited overburden. If paleontologic data or sedimentation rate data is not available, then rates of sedimentation can be qualitatively assessed, if only broadly, by evaluating seismic character.

Correlating offset well data Correlating offset well information to the proposed well site is critical to improving the reliability of SWF assessments and can be useful, even if the offset well is miles away from the study area. With offset well information, the seismic stratigraphic units that did or did not result in SWFs at the offset well(s) often can be correlated to strata at the proposed well site. MWD logs, in combination with detailed drilling reports, are the most useful information. Conventional well logs from relevant offset wells also can be helpful. But, in most cases, they do not directly correlate to the tophole strata being studied. At a minimum, conventional logs often can be useful for inferring lithology in analogous overlying sedimentary cycles based on amplitudes and seismic architecture.

The general technique is to make an arbitrary seismic line from the offset wells to the proposed location. Stratigraphic sequences from the offset location can be correlated to the study location if top hole stratigraphic and structural conditions in the offset well are the same or similar. Seismic attributes associated with SWF (or no SWF) are correlated to the extent possible with the seismic attributes in the interval at the proposed well location and are used as other indicators of SWF risk.

Other techniques If calibrated with offset well data, additional but secondary techniques can be successfully employed to help assess SWF risk. These techniques may help predict overpressured sandy zones, but are only marginally useful without good well control and probably require high-resolution 3D seismic data for best results. Trace-shape classification assigns each seismic trace to a representative trace shape "family." The representative trace shapes are determined by a neural network process that generates a series of synthetic traces that is representative of a seismic interval. Trace-shape attributes can, in some cases, be qualitatively associated with subsurface properties. In SWF studies, the trace-shape attribute may aid the interpreter in correlating a known SWF (or no SWF) interval to nearby proposed locations. Combinations of seismic attributes when "trained" onto a particular reservoir parameter (such as porosity) can be used to predict those properties throughout a seismic data set. Given high-resolution 3D seismic data and high-resolution geologic information (geo-technical boring) it is possible that this approach could be applied to overpressured sands prediction. Our limited experience with using multi-seismic attribute techniques for SWF prediction is through n-dimensional seismic attribute cluster analysis. The assumption behind this type of analysis is that a seismic response may individually correlate with each of 3 or 4 seismic attributes, but may be best defined by some combination of those attributes. As with trace-shape classification, the choice of the time window and a confident well-to-seismic tie is critical. Without calibration by an offset well, this type of analysis is only of limited usefulness. These attribute analysis techniques are probably limited for use with planning field development wells and may also require high-resolution 3D to be effective for SWF studies.

Risk assessment At the end of the stratigraphic analysis, a risk assessment for SWF is communicated to the drilling team so that the results can be used in well planning. This is typically done graphically in the form of a tophole prognosis chart accompanied with text and other relevant illustrations. We, as an industry, are well short of being able to produce a meaningful numeric assessment of SWF risk. The risk assessments, therefore, necessarily are interpretative. The following risk criteria scheme for assessing SWF risk is similar to others used in the industry. In general, a stratigraphic unit is assessed a high risk for SWF if the following conditions are found to exist:

• The seismic stratigraphy suggests a relatively young (Quaternary-age) sand-prone interval overlain by an unfaulted clay drape (or other sediments that could act as a seal).

• The section is buried by relatively thick, rapidly deposited sediments. • The unit can be correlated to a known SWF interval at an offset well, and

conditions at the proposed well site are similar.

Moderate risk of SWF is assessed if the interval has most of the characteristics of a high-risk interval, but may have, for instance, an eroded, breached, or otherwise compromised seal unit, or shows other evidence providing some, but not compelling, doubt regarding overpressure development. Low-to-moderate risk of SWF is assessed when an interval shows some features associated with SWF, but for which there may be some uncertainty, but is otherwise characterized by low-risk features. Low risk of SWF is assessed if the interval has characteristics of sediments not expected to produce SWF, such as if:

• The expected sand content in the unit is low and/or the unit is relatively old • The sealing unit is absent or substantially breached • A thick succession of slowly deposited sediment overlies the possible seal unit • Offset drilling has determined the absence of flow risk.

Appendix 3; Pressure Prediction for Shallow Water Flow

Introduction. High overpressures at shallow depths have been encountered during deepwater drilling e.g. Gulf of Mexico, Deepwater Norway, often resulting in serious problems occurring. e.g. unable to drill ahead, unable to set casing, environmental impact, and remedial actions required. With deepwater daily operating rates varying from $1500,000 – $300,000 per day, operational loss and $ cost of any unplanned operational events could deviating from the original design could be potentially $x millions or more. Reports written in recent years notably by Alberty, of BP Amoco have started to attended to recognizing and analysing problem incidents that have resulted and commenced in determining many of the necessary challenges required to better understand pore pressure prediction at shallow depths in deepwater drilling environments. The following illustrating a shallow flow evaluation techniques for pore pressure predictions associated with a typical incident experienced from a recent BP-Amoco well. Three main points were concluded:

1) Basin model derivations and seismic-derived pore pressure prediction methods must be integrated as one common process.

2) Seismic methods add greatest operational value when a basin compaction model is used to generate the normal trend line.

3) Basin model methods are more effective when permeability assumptions are coupled to petrophysical parameters.

Basin model pressure prediction methods. Basin model programs derive pore pressure for each rock layer as a function of:

• Sedimentation rate, • Shale content, • Permeability.

The models use compaction laws relating porosity to effective stress and overburden and a user defined relationship for permeability, or a relationship based on an assumed specific surface area for each rock type. Sedimentation rate and shale permeability play the major role in determining pressure gradients as illustrated in Figure 1. It has been shown that high sedimentation rates greater than about 1500 feet per million years coupled with low permeability layers represent a potential risk for shallow water flows. A challenge with modeling is therefore in the determination of permeability parameters. In that, studies are currently ongoing to improving petrophysical relationships for estimating permeability of mudstones. BP Amoco are also proposing using CEC derived from acoustic and resistivity logs using PRESGRAF, BP-Amoco developed software, for estimating specific surface area for relationships of permeability. One other limitation is however the difficulty in describing the geologic sequence and basin history with sufficient accuracy to predict pore pressure.

Velocity based pressure prediction methods. There are three general models for relating acoustic interval velocity to pore pressure i.e.

1) Empirical, 2) Deterministic, and 3) Numeric models.

Empirical The empirical method (made popular by Eaton) requires that the analyst define a normally pressured velocity trend line, by visual inspection of a depth versus interval velocity plot as shown in Figure 2. The failings of empirical methods is that in deep water environments, where overpressures occur at shallow depths below the mud line, trend line predictions are more difficult to define, are more prone to error especially when other data is not available to be combined to delineate over-pressure.

Deterministic Deterministic models relate velocity directly to effective stress and do not require a trend line or empirical exponent. The weakness of these models are four fold:

1. Poor results near the mud line where the effective stress is small 2. Difficult calibration, 3. No accountability for unloading effects, and 4. Sensitivity to which compaction law is utilized. Common deterministic methods are Bowers (1994), Wendt (BP-Amoco), Scott and Thomsen (1993), and Alixant (1991).

Numeric A third approach is illustrated from BP-Amoco, who have developed a numeric model that incorporates concepts from basin modeling. Numerical simulation derives a normal velocity trend line and overburden using exponential compaction and modified velocity laws. A major part of BP-Amoco’s software implementation is the use of mean effective stress in the compaction and velocity laws. In their model, mean stress was based on contention that all stress components affect velocity, not just the vertical component as universally assumed. Once a normal velocity trend line is established from software model, calibrated if needed, pore pressure is then computed by an Eaton-like effective stress transform that relates the deviation of velocity from the trend line to pore pressure. A methodology integrating flexibility and stability of empirical models with compaction consideration from basin models. The limitation of all velocity based models however is that they apply only to shale’s. The pore pressure gradients in sandstones, often the major constituent in shallow deepwater sediments often being different to that in the bounding shale’s. Basin models, on the other hand, can derive pore pressure in all rock types and account for the centroid effects. Another limitation of the seismic methods is data quality. Data from reflectors between one-fourth and one cable length deep is optimal, where one cable length is the offset between the shot point and receivers. At reflectors deeper than one cable length, the angle of illumination is reduced and errors can be large. At depths near the surface, data can be poor for other reasons. But as water depth increases, data quality near the mud line improves because the cable length to depth ratio becomes more optimal.

Worked example. Given the seismic-derived interval velocity data shown in Figure 2. Determine if there is a risk of a serious water flow problem when drilling without a riser to 4000 feet.

• Water depth I= 1800 feet, • Sedimentation rate is 5000 feet per million years, • Closest control well (about 25 miles away in 300 feet of water) ,normally

pressured to a depth of 12,000 feet.

Step 1: Assess the rate of deposition. For a sedimentation rate of 5,000 feet per million years, the top of overpressures is at about 3,400ft, based on the lithology modeled in Figure 1. While a rigorous model would in reality be needed for a complete evaluation, this simple calculation shows clearly that a 4,000 foot design represented a drilling risk. If the permeability is higher than modeled i.e. if it is more sand rich, the pore pressure would be normal to much deeper depths.

Step 2: Determine normal velocity trend using basin compaction model Results in Figure 3 show that seismic velocities are slower than the normal trend and that overpressures come in as shallow as 3400 feet (1600 feet BML).

Step 3: Convert the seismic velocity to pore pressure Based on the deviation from the compaction trend line.

Step 4: Check data quality. Not shown here is an evaluation of the stacking velocity data at several shot points each side of the actual drill location. The stacking velocities show clearly a low velocity break at about 3800 feet that corresponds to an overpressure effect.

SUMMARY Figure 4 compares post drill mud weights to the pre-drill predictions. The top of overpressures was about as predicted and confirmed with wireline pressure measurements. When the conductor was set at 3600ft (1800ft below mud line) a small flow was observed on the casing annulus but the flow caused no major problem. The example is an important one as conventional and potentially reasonable evaluation might have readily predicted the top of overpressures as deep as 9000ft - similar to the offset well - using the trend in Figure 2. The well design was based on a 9000ft prediction but changed before spud to the seismic prediction set out above.

REFERENCES 1. Alberty, Mark, "Mechanisms of Shallow Waterflows and Drilling Practices for Intervention", paper OTC 8301, presented at the 1997 Offshore Technology Conference held in Houston, Texas 5-8 May 1997. 2. Thomson, J.A, T. Dodd and Andy Hill, "Formation of Shallow Water Flows", Shallow Water Flow Forum, October 6-8 th , 1999, League City, Texas 3. Bowers, G.L, “Pore Pressure Estimation from Velocity Data: Accounting for Overpressure Mechanisms Besides UnderCompaction”, Paper IADC/SPE 27488 presented at the 1994 IADC/SPE conference, Dallas, Texas, February 15-18, 1994, pp. 515-530. 4. Alixant, J. and Desbrandes, R., “Explicit Pore Pressure Evaluation Concept and Application,” SPE Drilling Engineering, September 1991, pp. 182 - 188. 5. Scott, D. and Thomsen, L.A., “A Global Algorithm for Pore Pressure Prediction”, Paper SPE 25674 presented at the SPE Middle East Oil Technical Conference, Bahrain, April 3-6 1993, pp. 645-654. 6. Towle, G.H., "Stress Effects on Acoustic Velocities of Rocks, Dissertation", Colorado School of Mines, 1978, page 43. 7. Goulty, N.R., "Relationships between porosity and effective stress in shales", First Break , v. 11,1997 p.413-419. 8. Harrold, T.W.D, Swarbrick, R.E and Goulty, N.R., "Pore Pressure Estimation from Mudrock Porosities in Tertiary Basins, AAPG Bulletin, v. 83, No. 7, July 1999, p. 1057-1067. 9. Eberhardt-Phillips, D., D-H Han, and M. D. Zoback, “Empirical relationships among seismic velocity, effective pressure, porosity, and clay content in sandstone”: Geophysics, v. 54, no. 1, 1989,p. 82-89. 10. Traugott, Martin, “Pore/Fracture Pressure Determinations in Deep Water, Deepwater Technology Supplement to World Oil, August 1997. 11. Martin Traugott, Philip Heppard and Tim Dodd BP-Amoco, Houston, Texas, Pressure Prediction for Shallow Water Evaluation. International Forum on Shallow Water Flows League City, Texas, October 6-8 th , 1999

Appendix 4: Definitions and nomenclature Basin models are numerical simulation programs used to evaluate pore pressure, porosity, overburden and other petroleum parameters. E.g. TemisPack (IFP), Genex (IFP), BasinMod (PlateeRiver Associates), and PetroMod (IES). Hydrostatic pressure; is the pressure in a column of salt water extending to the surface. Normal pressure is a pore pressure equal to hydrostatic. Overpressure is a pore pressure greater than hydrostatic. Overburden pressure is that exerted by the combined weight of the sediments plus weight of the water column above the sea floor. Centroid is the depth in a dipping sandstone bed where there is no water flow in or out of the sandstone into immediately overlying/underlying shale's. Above the centroid there should be an outflow of water from the sand into the bounding shales and below there will be an inflow of water from the bounding shales into the sandstone. These water flows lead to establishment of pressure gradients from the sandstone into the shale above the centroid and from the shale’s into the sandstone below the centroid. The scale of the pressure gradient is established by the permeability contrast between the sand and shale and the rate of water flow into and out of the sand. Vertical effective stress is overburden minus pore pressure. Mean effective stress is the average of the three orthogonal principal stress components where the two minimum components are often taken to be equal to leak off test values minus pore pressure. Compaction laws are analytical expressions of how porosity decreases with increasing effective stress. Velocity laws relate acoustic velocity to porosity, effective stress, clay content, and other parameters believed to affect velocity i.e. clay type.

Cation exchange capacity (CEC) is a measure of specific surface area and can be inferred from methylene blue tests or petrophysical relationships. Specific surface area represents the water bound to the grains of the sediments. Sedimentation rate is the rate of deposition, e.g., if the base of the Pleistocene (1.6 million years) is 1600 feet below the sea floor, the sedimentation rate is 1000 feet per million.