well logging

FACULTY OF ENGINEERING

DEPARTMENT OF PETROLEUM ENGINEERINGGROUP 1

COURSE’S NAME: WELL LOGGING

STUDENTS NAMES REGISTRATION NUMBERS

i. ALFA JONATHAN HUSSSEINI 13/NG/173/BSPE-J

ii. JOSEPHINE PONI CHARLES 13/SS/182/BSPE-J

iii. LAVINA PONI DAVID DATA 13/SS/277/BSPE-S

iv. DERPNY

v. AWAS DENIS TREVOR 13/UG/139/BSPE-S

vi. MACHAR

vii. KISEMBO

vii. BAGOSA ABRAHAM 13/UG/170/BSPE-S

vii. MAGO IAN 13/UG/207/BSPE-S

Assignment 1:

Read and make notes on the following measurements which are usuallymade on core plugs (including the procedures how they are measuredtheir relevance, techniques employed, etc):

GROUP 1; WELL LOGGING ASSIGNMENT

1. Porosity and permeability at overburden conditions2. Cementation exponent (m).3. Saturation exponent (n).4. Capillary pressure (Pc).

1.POROSITY AND PERMEABILITY AT OVERBURDEN CONDITIONS

POROSITY OF RESERVOIR ROCKSThe porosity of a rock is a measure of the storage capacity (porevolume) that is capable of holding fluids. Porosity is simply the ratioof the void space in a rock to the bulk volume of that rock multipliedby 100 to express in percent.

In actual rocks porosity is classified as:i. Absolute Porosity

Total porosity of the rock, regardless of whether or not theindividual voids are connected.

Total pore volume Bulk volume – Grain volume = Bulk volume .ii. Effective Porosity

Is the percentage of the interconnected pore space with respect tothe bulk volume?

Interconnected pore volume


= Vs = Vb - Vg Vb Vb

The effective porosity is the value that is used in all reservoirengineering calculations because it represents the interconnectedpore space that contains the recoverable hydrocarbon fluids (O.Torsæter, 2000).

Relevance Of Porosity On Core Blocks1. Petroleum engineers and scientists study porosity because it is

one of the important factors in determining how much oil may befound in a rock formation (SEED, 2015).

2. The porosity and its distribution also need to be calculated asaccurately as possible because they are almost always directlyused in the water saturation (Sw) and permeability calculationsand, possibly, in the net pay calculations (Petrowiki, 2012-2015).

Procedures For Measuring Porosity On Core PlugsEstimates of reservoir porosity can be obtained from several

sources both direct and indirect.

DIRECT METHODS Direct measurements are conducted on samples of the reservoir rockrecovered during drilling of wells. These samples could be rockfragments (cuttings) that are brought up to the surface by thedrilling mud or samples cut during coring operations, which arecalled cores. Core samples are more desirable since they arerelatively larger and more uniform, and their depth is knownprecisely. Small pieces, called core plugs, are usually cut fromthe cores for use in various tests. The plugs or cuttings arefirst cleaned with solvents to remove their fluid content of oiland water and then dried. To determine porosity of a sample, all that is needed is toestimate two of the three parameters in the equation below. Wewill start with the bulk volume since it is usually the easiest todetermine.


i. Bulk Volume Estimation ( Vb)If the sample is regular in shape, e.g., a cylindrical core plug,then Vb is computed from its length and cross-sectional area. Vb = Ac L where Ac is the core plug cross-sectional area in cm2 and L is thecore plug length in cm. If the sample is irregular in shape, e.g.,a cutting, then Vb is estimated by submerging it in water andmeasuring the volume of water it displaces (Fig 1. b). To preventwater from entering the sample's pores, the sample is first coatedwith a thin layer of wax or varnish. The volume of the coatingmust obviously be subtracted later; this volume is determined fromthe mass of the coating and the density of the coating material.Mass of the coating is obtained from the difference in the mass ofthe sample before and after coating.

ii. Grain volume estimation If the rock is predominantly composed of one mineral, e.g.,quartz, then the mass of the clean and dry sample, ms, divided bythe density of the mineral, ρg, equals the total volume of thegrains Vg = ms / ρg (2.4)

If the rock is composed of many minerals whose types and volumefractions are known, an average grain density, gρ must then beestimated as follows:ρ = Σ vi ρgi

where vi : volume fraction of mineral i ρgi : density of mineral i, g/cm3

Fig 1: Measurement of volume by submerging in water (Abu-Khamsin,2004)

iii. Pore volume estimation


Estimating Vg requires simple procedures and, usually, availableequipment. On the other hand, direct measurement of the porevolume provides a more accurate porosity value. However, thisrequires some additional instruments. A simple method starts withweighing the sample in air followed by placing the sample in avacuum flask (Fig 2. a) for a few hours. Water is then introducedinto the flask gradually until the sample is completely submerged(Fig 2. b). The sample is then removed from the flask, shaken toremove excess water and then weighed quickly. The increase in themass of the sample is equal to the mass of water introduced intothe sample, and the volume of the water is equal to the connectedpore volume. Care must be taken to minimize water evaporation; andif the rock contains clay minerals that absorb water, anotherliquid – oil, mercury, or KCl brine – must be used instead.

Fig 2: Pore volume measurement by the liquid saturationmethod (Abu-Khamsin, 2004)

INDIRECT METHODS


Indirect methods of estimating porosity rely on measurement ofother rock and fluid properties. These measurements are carriedout in the well employing special instruments as part of welllogging operations. Therefore, no core samples are needed and theporosity is estimated for the rock as it exists in the reservoir.Two of the most common well logs are discussed below.

i. The sonic (acoustic) log In this log, the instrument - the sonde - generates sound waves,which travel through the reservoir - in the vicinity of the wellbore - and are detected by the sonde upon their return. The timelapse between generation and detection – travel time - is recordedcontinuously versus the depth of the instrument. Since travel timeis related to porosity by Δtlog = ϕ Δtf + (1 - ϕ)Δtma

where Δtlog : sound travel time in the reservoir as measured by the log, μs Δtma : sound travel time in the grain material of the reservoir, μs Δtf : sound travel time in the fluids of the reservoir, μs and since Δtma and Δtf are usually known for the reservoir, the porositycan be estimated at all depths.

ii. The formation density log Another logging sonde emits gamma rays, which mostly pass throughthe reservoir rock and fluids, but some are scattered back intothe well bore and are detected by the sonde. The fraction ofscattered gamma rays is used to compute the bulk density - rockand fluids - of the reservoir, which is related to porosity by

ρlog = ϕ ρf + (1 - ϕ)ρma

where ρlog : bulk density of the reservoir as measured by the log, g/cm3

ρma : density of the grain material of the reservoir, g/cm3

ρf : density of the fluids of the reservoir, g/cm3

Since laboratory values of the porosity are more reliable, theseare used to correct log-estimated values at the same depth(s) of


the core sample(s), and then the same correction is applied to theentire thickness of the reservoir. It should be noted that bothlogs provide estimates of the absolute porosity.

ROCK PERMEABILITY Permeability is defined as the ability of a porous medium, e.g.,sedimentary rock, to conduct fluids. The larger the permeability, themore fluid flow can be achieved through the medium for a given set ofconditions. The earliest attempt at quantifying permeability was thework of Henry Darcy in 1856. Conducting many experiments on beds ofpacked sand and using different liquids, Darcy observed the following relationships: q ∝ ΔP q ∝ A q ∝ 1 / Lwhere q : volumetric flow rate of the fluid through the medium, cm3/s ΔP : difference in pressure between inlet and outlet of medium, atm A : cross-sectional area of medium that is open to flow, cm2

L : length of medium, cm Combining the three relationships, the following equation was obtained q = c A ΔP / L The proportionality constant, c, was found to be inversely proportionalto the viscosity of the fluid used. Therefore, it was replaced with k /μ and the equation became q = k A ΔP μ L


The new constant, k, was found to be the same for a given porous mediumregardless of its dimensions, the type of fluid used or the pressuredrop applied. It was an inherent property of the medium that controlledits ability to conduct fluids. Darcy termed this property thecoefficient of permeability, which was later called simply thepermeability, and the equation above became known as Darcy’s law. Itshould be noted that implicit in the definition of permeability is therequirement that the fluid saturates the porous medium completely.

The units of permeability are a little confusing. If we substituteconsistent units for all the variables in the equation above – such asg/cm.s2 for pressure and g/cm.s for viscosity, we find that the unit ofpermeability is cm2 and this is indeed one of the units employed in themetric system of units. However, one cm2 is a very large permeabilitythat is not encountered in natural rock. Therefore, reservoir engineershave adopted another, more practical, unit defined as follows:

If 1 atmosphere of pressure drop is required to flow a liquid of 1 cp viscositythrough a porous medium of 1 cm length and 1 cm2 cross-sectional area at a rateof 1 cm3 per second, then the medium has a permeability of 1 darcy.

Thus, 1 darcy = 9.869 x 10-9 cm2. A more common unit of reservoir rockpermeability is the millidarcy (md), which is one thousandth of adarcy. Since the petroleum industry still uses the system of fieldunits, a conversion factor is introduced in Darcy’s law as follows q = 1.127 k μ ΔP A Lwhere q, k, A, ΔP, μ and L are in bbl/day, darcy, ft2, psi, cp and ft,respectively.

Procedures For Measuring PermeabilityLaboratory measurement is performed under steady-state conditionsusing a permeameter such as the one shown in Fig. 3 below. Theclean and dry core sample is mounted in the core holder and thenplaced under a suitable confining pressure to simulate reservoiroverburden conditions. The sample is then placed under vacuum for


a sufficient period of time to remove all air from the sample. Thefluid – usually brine, oil or air – is then flowed through thesample until steady-state flow is established; such state ischaracterized by equal fluid injection and production rates. Theflow rate and the inlet pressure are then recorded. Such data issufficient to compute the permeability according the equationabove however, the test is usually repeated at different sets offlow rate and inlet pressure and the data is plotted as shown inFig. 4 below. The slope of the straight line is the core sample’spermeability multiplied by A/ μL

Fig 3: Measurement of permeability (Abu-Khamsin, 2004)


Fig 4: Computation of permeability (Abu-Khamsin,

2004)

Relevance Of Permeability

Rock formation permeability is the most important parameter that

indicates how efficient the reservoir fluids flow through the rock

pores to the well bore (Kaen, 1995).

2. CEMENTATION EXPONENT OR FACTORSCementation exponent also known as cementation factor is a criticalparameter, which affects water saturation calculation.

In carbonate rocks, due to the sensitivity of this parameter to poretype, water saturation estimation has associated with high inaccuracy.Hence Cementation Exponet is a reliable mathematical strategy todetermine these properties accurately (Reza, 2013).

Procedures For Measuring Cementation Exponent

Relevance Of Cementation ExponentialGROUP 1; WELL LOGGING ASSIGNMENT

Cementation exponent is one of the parameters used in measuring theconductivity of the reservoir rock and fluids. .It models how muchthe pore network increases the resistivity as the rock itself isassumed to be non-conductive.

3. THE SATURATION EXPONENT, N The saturation exponent usually is fixed to values close to 2. Thesaturation exponent models the dependency on the presence of non-conductive fluid (hydrocarbons) in the pore-space, and is related tothe wettability of the rock (Wikipedia, 2015)

Procedure For Measuring Saturation Exponent

WhereI = Resistivity IndexSw = Water Saturationn = Saturation exponent, ranging from 1.4 to 2.2 ( n = 2.0 if no datagiven)Rt = Resistivity of the rock filled with water and oil (Ohm-m)Ro = Resistivity of the rock filled with only water (Ohm-m)


In this equation, Rt and Ro can be obtained from well loggingdata, saturation exponent n is experimentally determined inlaboratory. Therefore, the in situ water saturation can becalculated with Archie’s equation. Based on the material balanceequation for formation, Sw + So + Sg = 1.0, the hydrocarbonreserve in place may be calculated.

Relevance Of Saturation ExponentSaturation exponent measurement monitors carbon and oxygen elementwhich provide information on the presence of water and hydrocarbonrespectively in the reservoir. However, Since many rock typescontain carbon and oxygen (e.g limestones – CaCO3 and Organic-richshales), it is important that the element contained in rock-forming minerals can be identified (Jean, 1996).

4. CAPILLARY PRESSURE, P C

Capillary pressure is a measurement of the force that draws a liquid upa thin tube, or capillary. The pressure difference existing across theinterface separating two immiscible fluids in capillaries (e.g. porousmedia). Calculated as:Pc = pnwt - pwt

Where:


Pc = capillary pressurePnwt = pressure in nonwetting phase

pwt = pressure in wetting phase One fluid wets the surfaces of the formation rock (wetting phase) inpreference to the other (non-wetting phase).

• Gas is always the non-wetting phase in both oil-gas and water-gassystems.

• Oil is often the non-wetting phase in water-oil systems.(E. R. (Ross) Crain, P.Eng, 2015).

Procedures For Measuring Capillary PressureOne core sample saturated with water or another wetting fluid is placed in each holder and the shaft is rotated at a constant speedfor a sufficient time.

The centrifugal force causes the pressure within the core sample to drop below atmospheric pressure. This pressure drop allows air to drive water out of the core sample where it accumulates in a receiving tube at the end of the core holder. The pressure difference between the atmospheric pressure of air and the new pressure of water is then computed using a simple formula. This simulates the capillary pressure exerted on the water by air.

The rotation speed is then raised to stimulate higher capillarypressure. This drains more water from the core sample and providesanother porosity reading(value). The air-water drainage capillary pressure curve is then plottedfrom the pressure drop values versus water saturation remaining inthe core sample at the end of each rotation step.The capillary pressure is then generated by simple conversion

using the equation,


And

where the subscripts L and R are laboratory and reservoirconditions respectively. For laboratory conditions, air-watercontact is used and for reservoir con

Pc is the capillary pressure is the surface tension at water is the angle of contact for water and oil or gasr is the pore radius Combining the two equations,

(Abu-Khamsin, 2004).

Relevance Of Capillary Pressurei. Determine fluid distribution in reservoirii. Determine recoverable oil for water flooding applicationsiii. Determine pore size distribution index λ, from capillary

pressure data. This index can be used to calculaterelative permeability using industry correlations

iv. May help in identifying zones or rock types(E. R. (Ross) Crain, P.Eng, 2015).


REFERENCES1. Abu-Khamsin, D. S. (2004). Basic Properties of Reservoir Rocks. Dhahran: King Fahd

University of Petroleum & inerals.

2. E. R. (Ross) Crain, P.Eng. (2015). Capillary Pressure. CRAIN'S PETROPHYSICAL HANDBOOK , 1.

3. Jean, M. S. (1996). All The Right Element. importance of saturation exponent to petroleum engineer , 35.

4. Kaen, K. (1995). Permeability Prediction: Core Vs Log - Derived Values. Thailand: Geotechnology and Mineral Resources of Indochina.

5. O. Torsæter, M. A. (2000). EXPERIMENTAL RESERVOIR ENGINEERING LABORATORY WORK BOOK. Norwegian: Norwegian University of Science and Technology.

6. Petrowiki. (2012-2015). Importance of porosity calculation. Society of Petroleum Engineers , 1. (RETRIEVED: 2:30 PM, Saturday, 21st February, 2015 FROM: http://petrowiki.org/Porosity_for_resource_in_place_calculations#cite_note-r1-0)


7. Reza, H. J. (2013). A New Approach to measuring Cementation Factor by Using an Intelligent System. Iran: Iranian Journal of Oil & Gas Science and Technology.

8. SEED. (2015). Laboratory Experiment Porosity Explorer. Schlumberger Excellence in Education Development (SEED), Inc. , 1. (RETRIEVED: 1:45 PM, Saturday, 21st February, 2015 FROM: http://www.planetseed.com/sciencearticle/porosity-explorer)

9. Wikipedia . (RETRIEVED: 3:19 PM, Saturday, 21st February, 2015 FROM: http://en.wikipedia.org/wiki/Archie%27s_law)


http://www.planetseed.com/sciencearticle/porosity-explorer

well logging

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