ResEngCh1

CONTENTS

1 INTRODUCTION1.1 Reserves Estimation1.2 Development Planning1.3 Production Operations Optimsation

2 RESERVOIR ENGINEERING TECHNIQUES

3 RESERVE ESTIMATING3.1 Definitions3.2 Proven Reserves3.2.1 Exercises - Reserve Definitions3.3 Unproved Reserves3.3.1 Probable Reserves3.3.2 Possiible Reserves3.4 Reserve Status Categories3.4.1 Developed:3.4.1.1 Producing3.4.1.2 Non-producing:3.4.2 Undeveloped Reserves:

4 PROBABILISTIC REPRESENTATION OFRESERVES

5 VOLUME IN - PLACE CALCULATIONS5.1 Volume of Oil and Gas in-Place5.2 Evolution of Reserve Estimate5.3 Reservoir Area5.4 Reservoir Thickness5.5 Reservoir Porosity5.6 Water Saturation5.7 Formation Volume Factors5.8 Recovery Factors5.9 Production Capacity5.10 Hydrocarbon Pore Volume Map

6 OTHER APPRAISAL ROLES

7 DEVELOPMENT PLANNING7.1 Reservoir Modelling7.2 Technoconomics7.3 Coping with Uncertainty

8. PRODUCTION OPERATIONS OPTIMISATION8.1 Development Phase8.2 History Matching8.3 Phases of Development

11Introduction To Reservoir Engineering

9. THE UNIQUENESS OF THE RESERVOIR

10. CONCLUSIONS

2

LEARNING OBJECTIVES

Having worked through this chapter the Student will be able to:

Show using a block diagram the integration of reservoir engineering with otherpetroleum engineering and other subjects.

Define the SPE definitions of reserves; proven reserves, unproved reserves;probable reserves and possible reserves.

Calculate given the prerequisite data proved, probable and possible reserves.

Describe in general terms reserve estimation.

Sketch a diagram showing the probability versus recoverable reserves indicating,proven, proven + probable and proven + probable + possible reserves.

Present a simple equation for volumes of oil and gas in-place.

Describe in general terms the evolution of reserves through successiveexploration wells.

Describe briefly with the aid of a sketch the various maps used to representreservoir; area, thickness porosity, saturation.

Describe briefly the use of the production (well0 test to determine reservoirflowability and properties.

Describe briefly the various elements of development planning: reservoirmodeling technoeconomics and uncertainty.

Illustrate with a sketch the impact of different technical parameters on theassociated uncertainties on a project.

Describe in general terms in the context of production operations, optimizationin history matching.

Draw a sketch showing the various phases of production from build up toeconomic limit.

Draw a sketch illustrating the various recovery scenarios from primary totertiary recovery.

Department of Petroleum Engineering, Heriot-Watt University 3


1 INTRODUCTION

With the petroleum industrys desire to conserve and produce oil and gas moreefficiently a field of specialisation has developed called Petroleum ReservoirEngineering. This new science which can be traced back only to the mid 1930s hasbeen built up on a wealth of scientific and practical experience from field andlaboratory. In the 1959 text of Craft & Hawkins1 on Applied Reservoir Engineeringit is commented that as early as 1928 petroleum engineers were giving seriousconsideration to gas-energy relationships and recognised the need for more preciseinformation concerning physical conditions as they exist in wells and undergroundreservoirs. Early progress in oil recovery methods made it obvious that computationsmade from wellhead or surface data were generally misleading. Dake2, in his text"The Practise of Reservoir Engineering", comments that Reservoir Engineeringshares the distinction with geology in being one of the underground sciences of theoil industry, attempting to describe what occurs in the wide open spaces of thereservoir between the sparse points of observation - the wells

The reservoir engineer in the multi-disciplinary perspective of modern oil and gasfield management is located at the heart of many of the activities acting as a centralco-ordinating role in relation to receiving information processing it and passing it onto others. This perspective presented by Dake2 is shown in the figure below.

ExplorationGeophysics/Geology

Petrophysics

Reservoir Engineering

Economics(Project viability)

General EngineeringPlatform Topsides Design

ProductionProcess Egineering

Dake2 has usefully specified the distinct technical responsibilities of reservoirengineers as:

Contributing, with the geologists and pertophysicists , to the estimation ofhydrocarbons in place.

Determining the fraction of discovered hydrocarbons that can be recovered. Attaching a time scale to the recovery. Day-to-day operational reservoir engineering throughout the project lifetime.

Figure 1.

Reservoir Engineering in

Relation to Other Activities

(adapted Dake2)

4

The responsibility of the first is shared with other disciplines whereas the second isprimarily the responsibility of the reservoir engineer. Attaching a time scale torecovery is the development of a production profile and again is not an exclusiveactivity. The day-to-day operational role is on going through the duration of theproject.

A project can be conveniently divided into two stages and within these the aboveactivities take place, the appraisal stage and the development phase. The appraisalphase is essentially a data collection and processing phase with the one objective ofdetermining the viability of a project. The development phase covers the remainingperiod if the project is considered viable from the time continuous productioncommences to the time the field is abandoned. Reservoir engineering activity invarious forms takes place during both of these stages.

The activities of reservoir engineering fall into the following three general categories:

(i) Reserves Estimation(ii) Development Planning(iii) Production Operations Optimisation

1.1 Reserves EstimationThe underground reserves of oil and gas form the oil companys main assets.Quantifying such reserves forms therefore a very important objective of the practisingreservoir engineer but it is also a very complex problem, for the basic data is usuallysubject to widely varying interpretations and on top of that, reserves may be affectedsignificantly by the field development plan and operating practice. It is an on-goingactivity during, exploration, development planning and during production. It isclearly a key task of the appraisal phase for it is at the heart of determining projectviability.

Before any production has been obtained, the so-called volumetric estimate ofreserves is usually made. Geological and geophysical data are combined to obtaina range of contour maps with the help of a planimeter and other tools the hydrocarbonbearing rock volumes can be estimated. From well log petrophysical analysis,estimates of an average porosity and water saturation can be made and when appliedto the hydrocarbon rock volume yield an estimate of oil in place (STOIIP). Since itis well known that only a fraction of this oil may in fact be recoverable, laboratorytests on cores may be carried out to estimate movable oil. The reserve estimate finallyarrived at is little more than an educated guess but a very important one for itdetermines company policy.

In 1987 the Society of Petroleum Engineers in collaboration with the World PetroleumCongress published definitions with respect to reserves and these are now acceptedworld-wide 3. These definitions have been used in the summary of reserve definitionswhich follow.

1.2 Development PlanningOilfield development, particularly in the offshore environment, is a front loadedinvestment. Finance has to be committed far in advance not only of income guaranteed



by the investment, but frequently also of good definitive data on the character of thefield. Much of the responsibility for this type of activity falls on the reservoirengineers because of their appreciation for the complex character of sub-surfacefluid behaviour under various proposed development schemes.

1.3 Production Operations OptimisationProducing fields will seldom behave as anticipated and, of course, by the very natureof this sort of activity, the balance of forces in the reservoir rock gets severely upsetby oil and gas production. The reservoir engineer is frequently called upon toexplain a certain aspect of well performance, such as increasing gas-oil ratio, sandand/or water production and more importantly will be asked to propose a remedy.The actual performance of the reservoir as compared to the various model predictionsis another ongoing perspective during this phase.

2 RESERVOIR ENGINEERING TECHNIQUES

In the past the traditionally available reservoir engineering tools were mainlydesigned to give satisfactory results for a slide rule and graph paper approach. Formany problems encountered by reservoir engineers today this remains a perfectlyvalid approach where the slide rule has been replaced by the calculator. Increasingly,however, the advance of computing capability is enabling reservoir engineeringmodelling methods (simulations) to be carried out at the engineers desk, previouslyconsidered impossible.

The basis of the development of the 'model' of the reservoir are the various datasources. As the appraisal develops the uncertainty reduces in relation to the qualityof the forecasts predicted by the model. Building up this geological model of thereservoir progresses from the early interpretation of the geophysical surveys,through various well derived data sets, which include drilling information, indirectwireline measurements, recovered core data, recovered fluid analysis, pressuredepth surveys, to information generated during production.

3. RESERVE ESTIMATING

The Society of Petroleum Engineers SPE and World Petroleum Congress WPO1987agreed classification of reserves3 provides a valuable standard by which to definereserves, the section below is based on this classification document.

3.1 DefinitionsReserves are those quantities of petroleum which are anticipated to be commerciallyrecovered from known accumulations from a given date forward.All reserve estimates involve some degree of uncertainty. The uncertainty dependschiefly on the amount of reliable geologic and engineering data available at the timeof the estimate and the interpretation of these data. The relative degree of uncertaintymay be conveyed by placing reserves into one of two principal classifications, eitherproved or unproved.

6

Unproved reserves are less certain to be recovered than proved reserves and may befurther sub-classified as probable and possible reserves to denote progressivelyincreasing uncertainty in their recoverability.

Estimation of reserves is carried out under conditions of uncertainty. The method ofestimation is called deterministic if a single best estimate of reserves is made basedon known geological, engineering, and economic data. The method of estimation iscalled probabilistic when the known geological, engineering, and economic data areused to generate a range of estimates and their associated probabilities. Identifyingreserves as proved, probable, and possible has been the most frequent classificationmethod and gives an indication of the probability of recovery. Because of potentialdifferences in uncertainty, caution should be exercised when aggregating reserves ofdifferent classifications.

Reserves estimates will generally be revised as additional geologic or engineeringdata becomes available or as economic conditions change. Reserves do not includequantities of petroleum being held in an inventory, and may be reduced for usage orprocessing losses if required for financial reporting.

Reserves may be attributed to either natural energy or improved recovery methods.Improved recovery methods include all methods for supplementing natural energy oraltering natural forces in the reservoir to increase ultimate recovery. Examples of suchmethods are pressure maintenance, gas cycling, waterflooding, thermal methods,chemical flooding, and the use of miscible and immiscible displacement fluids. Otherimproved recovery methods may be developed in the future as petroleum technologycontinues to evolve.

3.2 Proven ReservesProven reserves are those quantities of petroleum which, by analysis of geologicaland engineering data, can be estimated with reasonable certainty to be commerciallyrecoverable, from a given date forward, from known reservoirs and under currenteconomic conditions, operating methods, and government regulations.

Proved reserves can be categorised as developed or undeveloped.

If deterministic methods are used, the term reasonable certainty is intended to expressa high degree of confidence that the quantities will be recovered. If probabilisticmethods are used, there should be at least a 90% probability that the quantities actuallyrecovered will equal or exceed the estimate.

Establishment of current economic conditions should include relevant historicalpetroleum prices and associated costs and may involve an averaging period that isconsistent with the purpose of the reserve estimate, appropriate contract obligations,corporate procedures, and government regulations involved in reporting these reserves.In general, reserves are considered proved if the commercial producibility of thereservoir is supported by actual production or formation tests. In this context, the termproved refers to the actual quantities of petroleum reserves and not just the productivityof the well or reservoir. In certain cases, proved reserves may be assigned on the basisof well logs and/or core analysis that indicate the subject reservoir is hydrocarbon



bearing and is analogous to reservoirs in the same area that are producing or havedemonstrated the ability to produce on formation tests.

The area of the reservoir considered as proved includes (1) the area delineated bydrilling and defined by fluid contacts, if any, and (2) the undrilled portions of thereservoir that can reasonably be judged as commercially productive on the basis ofavailable geological and engineering data. In the absence of data on fluid contacts,the lowest known occurrence of hydrocarbons controls the proved limit unlessotherwise indicated by definitive geological, engineering or performance data.Reserves may be classified as proved if facilities to process and transport thosereserves to market are operational at the time of the estimate or there is a reasonableexpectation that such facilities will be installed. Reserves in undeveloped locationsmay be classified as proved undeveloped provided (1) the locations are direct offsetsto wells that have indicated commercial production in the objective formation, (2) itis reasonably certain such locations are within the known proved productive limits ofthe objective formation, (3) the locations conform to existing well spacing regulationswhere applicable, and (4) it is reasonably certain the locations will be developed.Reserves from other locations are categorised as proved undeveloped only whereinterpretations of geological and engineering data from wells indicate with reasonablecertainty that the objective formation is laterally continuous and contains commerciallyrecoverable petroleum at locations beyond direct offsets.Before looking at further detail we will carry out some tests to help emphasise theabove definition.

3.2.1 Exercises - Reserve DefinitionsThe section on Reserve Definitions as put together by the SPE and the WorldPetroleum Congress, defines the various aspects of reserve definitions. Thesedefinitions, are important both to companies and countries, and they can have verysignificant commercial impact. The following tests are presented to help understandthe working of these earlier definitions.

Test 1

There are 950 MM stb ( million stock tank barrels) of oil initially in place in a reservoir.It is estimated that 500 MM stb can be produced. Already 100 MM stb have beenproduced. In the boxes below, identify the correct answer.

950STOIIP is: MM stb500 400

450 400 500 MM stbThe Reserves are:

Turn to page 9 for answers

Test 2

Before starting production it was estimated that there was a 90% chance of producingat least 100 MM stb, 50% chance of producing 500 MM stb and 10% chance ofproducing 700MM stb. That is we are sure we can produce at least 100MM stb, and

8

we will probably produce as much as 500 MM stb, and we will possibly produce asmuch as 700 MM stb.

Tick the correct answers.

500400

400 500

400 500

200

200

200

100

100

100

600

600

600

700

700

700

Proved reserves (MM stb):

Probable reserves

Possible reserves

Turn to page 9 for answers

Test 3

What is wrong with the following definitions?

1. Reserves are those quantities of petroleum which are anticipated to be recoveredfrom a petroleum accumulation.

Test 4

1. We have a structure in our licence area which we intend to explore. We anticipateit to contain a STO IIP of 2000 MM stb, and recovery factor of 65% using primarymethods (30%), secondary (25%) and tertiary (10%) recovery methods. What are thereserves?

Test 5

A reservoir has been discovered by drilling a successful exploration well, and drillinga number of producing wells. We have even produced some 200 MM stb of oil.

STOIIP = 2000MM stb Recovery factor = 35%

What are the reserves?



Test 1 answer

There are 950 MM stock tank boards in place. It is estimated that 500 MM stb can beproduced and 100 MM stb have been produced then 400 recoverable reserves remain.

950STOIIP is: MM stb500 400

450 400 500 MM stbThe Reserves are: X

X

X

X

Test 2 answer

Proved : 100 MM stbProbable : 500 - 100 = 400 MM stbPossible : 700 - 500 = 200 MM stbProved : 100 MM stbProved & Possible 500 MM stbProved & Probable & Possible : 700 MM stb

Test 3 answer

Reserves are those quantities of petroleum which are anticipated to be commerciallyrecovered from a petroleum accumulation.Clearly economics is a very important aspect of the definition.

Economic Variables

What economic factors are used in the calculations? What oil and gas price do we usefor proved reserve estimates? Is inflation taken into account? Do we predict futureprice trends? Do we apply discount factors to calculate present value of the project?Are all these used in proved reserve calculations? The current economic conditionsare used for the calculations, with respect to prices, costs, contracts and governmentregulations.

Test 4 answer

1. Answer is zero by SPC/WPC definition.2. Intentions and anticipations are not the basis for reserves. In this case no well hasyet been drilled.Note: Some companies allocate potential reserves for internal use but these cannot beused for public and government figures.Reserves are those quantities of petroleum which are anticipated to be commerciallyrecovered from a known accumulation.

Requirements for Proved include

The following sources are required for proved reserves. Maps (from seismic and/geological data). Petrophysical logs. Well test results and rock properties from coreanalysis tests on recovered core.

10

Facilities

An important perspective which might be forgotten by the reservoir engineer, is thatfor reserves to be classified as proven, all the necessary facilities for processing andthe infrastructure for transport must either be in place or that such facilities will beinstalled in the future, as backed up by a formal commitment.

Contribution to the Proved Reservoir Area

This comes from drilled and produced hydrocarbons, the definition of the gas and oiland water contacts or the highest and lowest observed level of hydrocarbons. Also theundrilled area adjacent to the drilled can be used.

Test 5 answer

Ultimate recovery = 2 000 x 0.35 = 700 MM stbMinus production to date = 200Reserves = 500 MM stb

Reserves are those quantities of petroleum which are anticipated to be commerciallyrecovered from known accumulations from a given date forward.i.e. Reserves refer to what can be produced in the future.

Figure 2 gives a schematic of reserves showing the progression with time.

SPE / WPC DefinitionsPotentialP10

P50

P90

TimeStart of

ProductionAbandonmentStart of Dev

PlanningDiscovery of

WellSeismic

Data

Before Drilling Exploration Well

Prior and DuringAppraisal

Delineation, Evaluation,Development

ProductionPERIOD

Geophysicaland Geological

Geophysical,Geological,Petrophysicaland Well Test Data

Geophysical,Geological,Petrophysicaland Well Tests and Production Data

Reservoir Performanceand Production Data

TYPE OFDATA

Mostly Probabilistic Deterministic and ProbabilisticMETHOD

Possible

Probable

Provan

Possible

Probable

Provan Cumulative Production

RE

SE

RV

E C

ATE

GO

RIE

SP

roba

bilit

y Le

vels

What are the amounts termed that are not recoverable? The quantity of hydrocarbonsthat remains in the reservoir are called remaining hydrocarbons in place, NOTremaining reserves!

Reserves which are to be produced through the application of established improvedrecovery methods are included in the proved classification when :

Figure 2.

Variations of Reserves

During Field Life



(i) Successful testing by a pilot project or favourable response of an installedprogram in the same or an analogous reservoir with similar rock and fluidproperties provides support for the analysis on which the project was based,and,

(ii) It is reasonably certain that the project will proceed. Reserves to be recoveredby improved recovery methods that have yet to be established throughcommercially successful applications are included in the proved classificationonly :

(i) After a favourable production response from the subject reservoir from either

(a) A representative pilot or

(b) An installed program where the response provides support for the analysison which the project is based and

(ii) It is reasonably certain the project will proceed.

3.3 Unproved ReservesUnproved reserves are based on geologic and/or engineering data similar to that usedin estimates of proved reserves; but technical, contractual, economic, or regulatoryuncertainties preclude such reserves being classified as proved.Unproved reserves may be further classified as probable reserves and possiblereserves. Unproved reserves may be estimated assuming future economic conditionsdifferent from those prevailing at the time of the estimate. The effect of possiblefuture improvements in economic conditions and technological developments can beexpressed by allocating appropriate quantities of reserves to the probable and possibleclassifications.

3.3.1. Probable ReservesProbable reserves are those unproved reserves which analysis of geological andengineering data suggests are more likely than not to be recoverable. In this context,when probabilistic methods are used, there should be at least a 50% probability thatthe quantities actually recovered will equal or exceed the sum of estimated proved plusprobable reserves. In general, probable reserves may include :

(1) Reserves anticipated to be proved by normal step-out drilling where sub-surface control is inadequate to classify these reserves as proved,

(2) Reserves in formations that appear to be productive based on well logcharacteristics but lack core data or definitive tests and which are not analogousto producing or proved reservoirs in the area,

(3) Incremental reserves attributable to infill drilling that could have beenclassified as proved if closer statutory spacing had been approved at thetime of the estimate,

12

(4) Reserves attributable to improved recovery methods that have been establishedby repeated commercially successful applications when;

(a) a project or pilot is planned but not in operation and(b) rock, fluid, and reservoir characteristics appear favourable for commercialapplication,

(5) Reserves in an area of the formation that appears to be separated from theproved area by faulting and the geologic interpretation indicates the subjectarea is structurally higher than the proved area,

(6) Reserves attributable to a future workover, treatment, re-treatment, change ofequipment, or other mechanical procedures, where such procedure has notbeen proved successful in wells which exhibit similar behaviour inanalogous reservoirs, and

(7) Incremental reserves in proved reservoirs where an alternative interpretation ofperformance or volumetric data indicates more reserves than can be classifiedas proved.

3.3.2. Possible ReservesPossible reserves are those unproved reserves which analysis of geological andengineering data suggests are less likely to be recoverable than probable reserves.In this context, when probabilistic methods are used, there should be at least a 10%probability that the quantities actually recovered will equal or exceed the sum ofestimated proved plus probable plus possible reserves. In general, possible reservesmay include:

(1) reserves which, based on geological interpretations, could possibly existbeyond areas classified as probable,

(2) reserves in formations that appear to be petroleum bearing based on log andcore analysis but may not be productive at commercial rates,

(3) incremental reserves attributed to infill drilling that are subject to technicaluncertainty,

(4) reserves attributed to improved recovery methods when

(a) a project or pilot is planned but not in operation and(b) rock, fluid, and reservoir characteristics are such that a reasonable doubt

exists that the project will be commercial, and

(5) reserves in an area of the formation that appears to be separated from theproved area by faulting and geological interpretation indicates the subject areais structurally lower than the proved area.



3.4 Reserve Status CategoriesReserve status categories define the development and producing status of wells andreservoirs.

3.4.1. Developed:Developed reserves are expected to be recovered from existing wells includingreserves behind pipe. Improved recovery reserves are considered developed only afterthe necessary equipment has been installed, or when the costs to do so are relativelyminor. Developed reserves may be sub-categorised as producing or non-producing.

3.4.1.1 Producing:Reserves subcategorised as producing are expected to be recovered from completionintervals which are open and producing at the time of the estimate. Improved recoveryreserves are considered producing only after the improved recovery project is inoperation.

3.4.1.2. Non-producing:Reserves subcategorised as non-producing include shut-in and behind-pipe reserves.Shut-in reserves are expected to be recovered from (1) completion intervals which areopen at the time of the estimate but which have not started producing, (2) wells whichwere shut-in for market conditions or pipeline connections, or (3) wells not capableof production for mechanical reasons. Behind-pipe reserves are expected to berecovered from zones in existing wells, which will require additional completionwork or future recompletion prior to the start of production.

3.4.2. Undeveloped Reserves:Undeveloped reserves are expected to be recovered:

(1) From new wells on undrilled acreage,(2) From deepening existing wells to a different reservoir, or(3) Where a relatively large expenditure is required to

(a) Recomplete an existing well or(b) Install production or transportation facilities for primary or improved

recovery projects.

4. PROBABILISTIC REPRESENTATION OF RESERVES

Whereas in the deterministic approach the volumes are determined by the calculationof values determined for the various parameters, with the probalistic statisticalanalysis is used, using tools like Monte Carlo methods. The curve as shown in thefigure 3 below presents the probability that the reserves will have a volume greater orequal to the chosen value.

14

'Proven'

'Proven + Probable'

Pro

babi

lity

that

the

rese

rve

is a

t lea

stas

larg

e as

indi

cate

d.

'Proven + Proable+ Possible'

1.0

0.9

0.5

0.1

0Recoverable Reserve

On this curve:The proven reserves represent the reserves volume corresponding to 90% probabilityon the distribution curve.The probable reserves represent the reserves volume corresponding to the differencebetween 50 and 90% probability on the distribution curve.The possible reserves represent the reserves volume corresponding to the differencebetween 10 and 50% probability on the distribution curve.

As with the deterministic approach there is also some measure of subjectivity in theprobalistic approach. For each of the elements in the following equation, there is aprobability function expression in low, medium and high probabilities for theparticular values. A schematic of a possible distribution scenario for each of theelements and the final result is given below in the figure 4.

Net rock Net rock Connate Formation Estimatedvolume. average water volume recovery

porosity saturation factor factor

[ Vnr x x (1 - Swc) / B ] x RF = Reserveso

Uniform Triangular Gaussian Uniform p90p50

p10=P

The resulting calculations result in a probability function for a field as shown inthe figure 5 below, where the values for the three elements are shown

Proven = 500 MM stb the P90 figure.

Probable = 240 MM stb which together with the proven makes up the P50 figure.of 740MMstb

Figure 3.

Probabilistic

Representation of

Recoverable Reserves.

Figure 4.

Probablistic Reserve

Estimates.



Possible = 120 MM stb which together with the proven and probable makes up theP10 value of 860MMstb

Reserves distribution for a new field.

Reserves / MMstb

Pro

babi

lity

/ %

100

90

80

70

60

50

40

30

20

10

00 200 400 600 800 1000

P10 = 860 MMstbP50 = 740 MMstbP90 = 500 MMstb

Proven 500 MMstb

Probable 240 M

P+P+P = 860 MMstb

Proven Probable Possible

P90

P50

120 P10

As a field is developed and the fluids are produced the shape of the probability curvechanges. Probability figures for reserves are gradually converted into recoveryleaving less uncertainty with respect to the reserves. This is illustrated in figure 6.

100

90

80

70

60

50

40

30

20

10

00 200 400 600 800 1000

Reserves / MMstb

Pro

babi

lity

/ %

Proved ultimate recovery.

Proved reservesProduction

P90

P50

P10Figure 6.

Ultimate Recovery and

Reserves Distribution For a

Mature Field.

Figure 5.

Reserves Cummulative

Probability Distribution.

16

5. VOLUME IN-PLACE CALCULATIONS

5.1 The volume of oil and gas in-place depends on a number of parameters :The aerial coverage of the reservoir. AThe thickness of the reservoir rock contributing to the hydrocarbon volume. h

n

The pore volume, as expressed by the porosity , , the reservoir quality rock.The proportion of pore space occupied by the hydrocarbon ( the saturation ). 1-S

w

The simple equation used in calculation of the volume of fluids in the reservoir, V, is

V=Ahn(1-S

w): (1)

where:A= average areah

n = nett thickness. nett thickness = gross thickness x nett: gross ratio

= average porosityS

w = average water saturation.

When expressed as stock tank or standard gas volumes, equation above is divided bythe formation volume factor B

o or B

g.

V Ah S Bn w o= ( ) /1 (2)

To convert volumes at reservoir conditions to stock tank conditions formation volumefactors are required where B

o and B

g are the oil and gas formation volume factors.

These are defined in subsequent chapters. The expression of original oil in place istermed the STOIIP.

The recovery factor, RF, indicates the proportion of the in-place hydrocarbons

expected to be recovered. To convert in place volumes to reserves we need to multiplythe STOIIP by the recovery factor so that:

Reserves = STOIIP x RF

(3)

The line over the various terms indicates the average value for these spatial parameters.

The reservoir area A, will vary according to the category; proven, probable orpossible, that is being used to define the reserves.

Before examining the contributions of the various parameters it is worthwhile to giveconsideration of the evolution of the reserve estimate during the exploration anddevelopment stage.

5.2 Evolution of the Reserve Estimate Figure 7 gives a cross section view of a reservoir structure as suggested from seismicand geological data.



Oil

Suggested 0il and water contact

Using this data and possible suggested structure we can carry out some oil in placecalculations and estimate reserves. These figures however are not admissible inpublic reserve estimates. They are useful inside the company to justify projectexpenditure! The question is where do we locate the first exploration well and getinvolved in large exploration expenditure costs. Figure 8 suggest three alternatives

Oil

Suggested oil and water contact

Suggest this location.

In figure 9 an exploration well has been drilled and a core recovered and thestructure of the field with respect to formations and contacts redefined. Theredefined structure can now be used to provide an estimate of reserves accordingto the three, proven, probable and possible perspectives. Figure 10

Figure 7.

Cross Section

Interpretation From

Seismic and Geological

Data.

Figure 8.

Alternative locations of

Exploration Wells

18

Oil and water contact

Oil

Cored interval

OilPos

siblePr

obab

le

Prob

able

Possi

bleProved

Subsequent appraisal wells are now drilled to give better definition of the reserves ofthe field. Well 2 aimed at defining the field to the left identifies some additionalisolated hydrocarbon structure with its own oil water contact. Figure 11. The well,as well as increasing the proven reserves, further identifies previous unknownreserves. The next appraisal well is aimed at defining the reserves in the otherdirection. During well testing on wells 1or 2 indications of faulting are also helpingto define the flowing nature of the accumulation. Figure 12 for the further appraisalwell confirms the accumulation to the right and also identifies the impact of the faultwith a new oil water contact. Subsequent appraisal wells and early development givegreater definition to the field description. Figure 13

Figure 9.

Interpretation After

Exploration Well Drilled

and Cored.

Figure 10.

After The Exploration Well

Was Drilled.



Oil

Proven

Well 2. Well 1. Proposeddelineationwell 3.

Proven

Initial appraisal stage.

OilProven

Well 2. Well 1. Well 3.

Proven

New oil water contact.

Gas

Oil

Proven

Well 2. Well 1. Well 3.

Proven

New oil water contact.

Well 4.

Gas

Figure 12.

After Further Appraisal.

Figure 11.

Further Delineation Well.

Figure 13.

Final Appraisal Well.

20

From a deterministic perspective the various reserve estimates, that is, proven,probable and possible can be further determined. The indication of the variouselements based on the top structure map are shown. Figure 14

Possible

Probable

Proved

1

2

34

5.3 Reservoir AreaThe reservoir area can be obtained by separately evaluating the individual unitsmaking up the reservoir as obtained from various reservoir maps. These maps arederived from the evidence given from seismic and subsequent drilled wells. The mapsgenerally indicate the upper and lower extent of the reservoir section or sections andthe aerial extent as defined by faults or hydrocarbon contacts. Figure 15 shows anaerial section with the defined limits. The contour lines are lines of constant subseadepths. Figure 16 gives a cross section of a reservoir unit. The combination of the tworepresentations of the unit(s) can be used to calculate the gross rock volume.

PorosityBoundary

Fault Boundary

Fault Bound

ary

FluidContact

Figure 14.

Reserves Uncertainties by

Deterministic Method.

Figure 15.

Structure Contour Map. 7



Reservoir

Rock Volume

Hydrocarbon Water

Contact Elevation

Heighest Elevationon Top Structure

Heighest Elevationon Base Structure

Con

tour

Ele

vatio

n(u

nits

ss)

Area Contained by Contour

Top Structure

o

Base Structure

Figures 17 & 18 show an example of a top structure map and cross section of the RoughGas field in the North Sea.

47/7 A4

A2

47/8-1

47/8-2

47/2 47/3

47/8

A3

A6

A5x

x

x

Gw

C

GwC

95509500

95009500

9600

9450940093509300

9250

9200

9100

9150 9350

9300

9250

9200

8

88

Platform A

Completed Producers

Proposed Well Locations

Abandoned Wells

C.I. = 50ft.

88

888

B

88

8 A

AA

A

A

9000

9200

9400

9600

9800

A2

A3

A5

A1 A4Depth (ft)subsea

CarboniferousSands

Tentativehydrocarbon/water contact

Fau

lt Fault

UnconformityRotliegendesUnconformity

Figure 16.

Reservoir cross section. 7

Figure 18.

Schematic Cross Section of

The Rough Field. 5

Figure 17.

Top Sand Structure Map

Rough Gas Field. 5

22

5.4 Reservoir ThicknessAnother representation of the reservoir formations is the reservoir thickness map.Where the areal contour maps show the thickness normal to the plane of the reservoirthe contours are called isopachs. When the thickness is mapped as a vertical thicknessthen the contour is called an isochore. Not all the reservoir thickness will contributeto fluid recovery and will include non-productive strata. Those contours whichinclude these non-productive material are called gross reservoir isopach and thosewhere non-productive material is excluded are called net reservoir isopach maps.Those intervals contributing to flow are termed pay. The ratio of net to gross, h

n/h

t , is

an important aspect in reservoir evaluation. Figure 19 shows a net pay thicknessisopach and the isopach map for the Rough field is shown in figure 20

0150

125100

75

Isopach C I25 Units

100

100

90

80

70

110

110116

120

GwC

Gw

C

130

140

A4

A1

A2

47/8-1

47/8-2

47/2 47/3

47/7 47/8

A3

A6

A5x

x

Figure 19.

Net Pay Thickness

Isopach.7

Figure 20.

Rough Field Isopach. 5



The isopach map can also be used to calculate reservoir volume. For example in figure21 the area under a plot of net pay thickness vs. area contained within the contourprovides a net pay volume. These plots can be generated for each section or rock type.The thickness plots for each section are called isoliths.

OWC

Area Enclosed = Net Rock Volume

Area Contained by Contour

Net

Pay

Isop

ach

Val

ue

0

40

80

120

140

180

5.5 Reservoir PorosityThe variation of porosity can also be represented . The average porosity, , in a wellcan be calculated from the thickness-weighted mean of the porosities 4 .

w

k n kk

m

n

h

h= =

,1 (4)

where k is the average porosity derived from the log over a small thickness h

n,k within

the net pay thickness, hn.

These values of porosity can then be plotted to generate an isoporosity map asillustrated in figure 22. The example of an isoporosity map for the Rough Field isshown in figure 23.

5 1015

2025

Porosity C I5%

Figure 21.

Hydrocarbon Volume From

Net Pay Isopach.7

Figure 22.

Iso Porosity Map.7

24

14%

12%

10%

8%

6%

Gw

C

GwC

A4

A1

A2

A3

A6

A5A

47/7 47/8-1

47/8-2

47/2 47/3

47/8x

x

5.6 Water Saturation, SwThe water saturation in a reservoir is influenced by the characteristics of the reservoirrock and the location with respect to the position above the free water level near theoil-water or gas-oil contact (see section Reservoir Rock Properties Chapter 7). Theaverage water saturation S

w,w , can be calculated in a similar way to porosity by

calculating the volume weighted mean across the producing elements of the forma-tion, the pay.

SS h

hw ww k k n k

k

m

w n,

, ,

= =

1 (5)

The values of Sw,w

can be plotted and contours of constant saturation (isosaturation)presented. Figure 24.

15 2025

30 35 40

WOC

Shale

A more detailed description together with exercises are given in the mapping sectionof the geology module.

Figure 23.

Rough Field Iso Porosity

Map.7

Figure 24.

Iso Saturation (sw) Map.4



5.7 Formation Volume Factors Oil, Bo and Gas, BgThese properties of the oil and gas which convert reservoir volumes to surfacevolumes, are generated from measurements made on fluid samples from the reservoir.They do not vary significantly across the reservoir when compared to the other rockrelated parameters. These parameters are covered in the gas properties and oilproperties chapters. In some reservoirs where the formations are thick there is acompositional gradient over the depth. This variation in composition from heavier(less volatile components) to lighter components at the top results in a variation of theoil formation volume factor, B

o over the thickness. In such cases an average value

based on values measured or calculated at depth would be a preferred value.

5.8 The Recovery Factor, ERThe proportion of hydrocarbons recovered is called the recovery factor. This factoris influenced by a whole range of factors including the rock and fluid properties andthe drive mechanisms. The variability of the formation characteristics, the heteroge-neity can have a large influence on recovery. The development process beingimplemented and the geometries and location of wells again will also have a largeinfluence. Calculating recovery therefore in the early stages is not feasible and manyassumptions have to be included in such calculations. It is in this area that reservoirsimulation can give indications but the quality of the calculated figure is limited bythe sparse amount of quality data on which the simulation is based.

The American Petroleum Institute6 has analysed the recoveries of different fields andcorrelations have been presented for different reservoir types and drive mechanisms.Figures 25 and 26 give the residual saturations and oil recovery efficiences fordifferent drive mechanisms. The API also presents correlations for recoveries,E

R,

For sandstone and carbonate reservoirs with solution gas drive

For sandstone reservoirs with water drive

ES

Bk

Spp

ES

Bk

S

R ow

ob obw

b

a

R ow

oi

wi

oi

,

. ..

.

,

. .

. ( )

.

=( )

( )

=( )

0 41851

6

0 548981

0 1611 0 09790 3722

0 1741

0 0422 0 0770

ww

o i

a

pp

( )

. . ( )1903 0 2159 7

b refers to bubble point conditions, i is the initial condition and a, refers to abandonmentpressure.

26

1.00

0.50

0.10

0.05

02

1.00

0.50

0.10

0.05

5 10 20 30 40 50 60 70 80 95 98

2 5 10 20 30 40 50 60 70 80 95 98

0

ME

DIA

N

+

Sor

(O

R S

gr)

as F

ract

ion

of T

otal

Por

e S

pace

RESIDUAL SATURATIONS

PERCENTAGE OF CASES LARGER THAN

Sor In Water DriveReservoirs

Sgr In Solution Gas DriveReservoirs

1.00

0.50

0.10

0.05

02

1.00

0.50

0.10

0.05

5 10 20 30 40 50 60 70 80 95 98

2 5 10 20 30 40 50 60 70 80 95 98

0

ME

DIA

N

+

OIL

RE

CO

VE

RY

EF

FIC

IEN

CY

AT

FIE

LD A

BA

ND

ON

ME

NT

IN P

ER

CE

NT

OF

OIL

PLA

CE

RESIDUAL SATURATIONS

PERCENTAGE OF CASES LARGER THAN

Water Drive

Gas Cap Drive

Solution Gas Drive

Gas Cap Drive +Water Injection

Figure 25.

Log - Probability Residual

Oil Saturation For Water

Drive and Solution Gas

Drive Reservoirs. (API6)

Figure 26.

Log - Probability of Oil

Recovery For Various Drive

Mechanisms. (API6)



5.9 Production CapabilityAnother concept, isocapacity, is used to signify production capability. Isocapacitydenotes equal values of permeability-net thickness product. This product can bemapped instead of permeability. The figure 27 shows an isocapacity map where theabsolute permeability has been obtained as an arithmetic average in the zone.

0.25

0.51

23454

32

1

The permeability map for the Rough Field is given in figure 28

A4

A3

A2

47/8-1

47/8-2

47/2

A6

A5x

x

Gw

C

GwC

Platform B

80100120

60

40

0

Contour Intervals 20 millidarcies

47/7 47/8

5.10 The Hydrocarbon Pore Volume MapThe hydrocarbon pore volume can be obtained by combining the net rock volume witha mean porosity and a mean hydrocarbon saturation. An alternative is the mapping ofhydrocarbon thickness (HPT) at each well. HPT at a well in a given zone is:

HPT h Sn h= _ _

. . (8)

Figure 27.

Isocapacity Map.7

Figure 28.

Rough Field Permeability

Map.5

28

where:

S Sh w_ _

= 1

Figure 29 gives an HPT map and the Rough Field HPT map is given in figure 30

0

9

1011

12

13

14

15

14

13

12

11

10

0

A4

A2

A3

A1

A6

A5

9

10

0

8

7

6

5

4

6. OTHER APPRAISAL ROLES

In building up the picture to enable the reserves estimates and recoveries to bedetermined the reservoir engineer will be involved in an number of aspects. One of themost powerful tools is the production test.

In a well test an exploration or appraisal well is converted to a short term producingwell, with all the associated facilities put in place to handle the produced fluids andmonitor fluid rates. A downhole pressure monitoring device is also located in the well.Figure 31. The well is flowed at a constant rate , and sometimes two rates as illustrated

Figure 29.7

Hydrocarbon Pore

Thickness Map.

Figure 30.

Rough Field Hydrocarbon

Pore Thickness.5



in figure 32a, a two rate test. The downhole pressure device responds to the productionand pressure declines. After a short or longer time period depending on the nature ofthe test, the well is shut in, i.e. the flow is stopped. In the well the pressure buildsup and eventually as monitored by the downhole pressure device, recovers to theoriginal pressure. Figure 32b. It is in the analysis of the pressure drawn down andbuild up curves and the rates that the reservoir engineer is able to determine theflowability of the reservoir. If the flowing interval thickness is known, the permeabilitycan be calculated. The presence of faults can also be detected.

A considerable amount of reservoir data can be obtained from these well testssometimes called DSTs ( drill stem tests). It has been the practise over recent yearsfor the produced fluids to be flared since there is unlikely to be an infrastructure tocollect these fluids. Now that companies are moving to a zero or reduced hydrocarbonemission policy the nature and facilities required for these tests are changing. Afeature of the flaring approach is a public demonstration of the productivity of the wellbeing tested.

Surface casing

Cement

Perforations

Production casing

Production tubing

Packer

Down holepressure monitor

Figure 31.

Production Test Assembly.

30

q bb

ls /

day

Pf.

psig

Pressure build up

Well shut inFlow 1 Flow 2

Pressure draw down

Pi

t

t

Well test analysis is a powerful reservoir engineering tool and is treated in depth in asubsequent module of the Petroleum Engineering course.

The nature of the fluids is key to reservoir behaviour and also subsequent processingin any development. The collection and analysis of these fluids is an important roleand is at the focus of PVT analysis. This topic is covered in Chapter 14 PVT Analysis.The pressure profile in a well is another important aspect of reservoir characterisationand can be used to identify fluid contacts. When used during the early stages ofproduction it can be a powerful means of refining the structure and hydrodynamiccontinuity characteristics of the reservoir. This is covered in the next chapter. LikePVT analysis where the information is based on samples removed from the reservoir,core analysis is based on recovered core from the formation. Various tests on thismaterial and its reaction to various fluids provides many of the reservoir engineeringparameters important in determining the viability of a project. Core analysis alsoprovides a cross check for indirect measurements made downhole. These coreanalysis perspectives are covered in chapters 7 and 8.

It is clear from what we have discussed that reservoir engineering is an importantfunction in the appraisal of the reservoir. The focus for this appraisal so far hasconcentrated on determining the characteristics and potential flow behaviour of areservoir under development. Clearly there could be a whole range of possibilitieswith respect to the plan that could be used to develop the field. This developmentplanning perspective is an important part of the reservoir engineers role. Again it is

Figure 32.

Production Test Analysis.

Two Rate Test.



a team effort involving the geological community who understand the reservoir andthe various engineers who have the responsibilities of designing and operating thehardware to enable production. An important part of any future development are thefacilities that would be required for sustained production and its is therefore animportant part of the appraisal stage to provide data for those who would haveresponsibility for good quality data predictions which will enable optimised facilitydesign.

In any project new data is always being generated. Indeed for a reservoir, itscharacteristics are unlocked over the whole lifetime of the project. The duration of theappraisal stage clearly is a techno economic decision related to the confidence to goahead based on a good foundation of quality data and forecasts. Fine tuning can alwaysbe carried out but this is costly if this delays the development stage. It is important toidentify and fill the gaps for the largest uncertainties, and having sufficient informationto design a system which is safe and cost effective. The difficulty is making thedecision on the data under which a line is drawn which defines the basis for fielddevelopment design. In reservoir development the reservoir is always revealing itsproperties, indeed it is in the production phase that the true characteristics arerevealed.

7 DEVELOPMENT PLANNING

7.1 Reservoir ModellingGiven appraisal well data, and test results the reservoir engineer can consider somealternative development plans, relying heavily on experience and insight. Since the80s computer based reservoir simulation has played a major role.

The starting point will invariably be a reservoir map used to calculate reserves, but inaddition use will be made of the material balance equation (chapter 15), together withsome drive concepts (chapter 11), to predict reservoir behaviour. One of the problemsfaced in making predictions is to adequately take into account knowledge aboutgeological trends and, although individual well models can be adjusted to reflect localconditions, there is no practical desk calculator technique for using say, the materialbalance equation and well models to come up with a predictive reservoir performance.Displacement models such as those derived by Buckley and Leverett (chapter 18),mainly from observations in the laboratory, give some insight into reservoir behaviourbut again do not significantly assist in allowing the engineer to study the effect ofalternative development plans on a heterogeneous reservoir.

With insight and ingenuity, the reservoir can be divided into a number of simple unitsthat can be analysed by the traditionally available techniques but such an approachremains unsatisfactory. Over recent years the integration of geological and geophysicalperspectives is contributing considerably to the confidence in reservoir modelling.

7.2 TechnoeconomicsFor hydrocarbon accumulations found on dry land the traditional reservoir engineeringtechniques available for field development planning were, in fact, quite adequate.This is mainly so because land development operations offer a high degree of planning

32

flexibility to oil companies and hence allow them to make optimal use of the latestinformation. In an offshore environment this is not the case; once platforms have beenordered most development options are closed. It is with respect to offshore fielddevelopment planning that reservoir simulation models have found their greatestapplication potential.

7.3 Coping with UncertaintyThe challenge to the exploration & production business of the oil & gas industry isconsiderable. The looking for the needle in the haystack scenario is not too far fromthe truth, when compared to other industrial sectors. With the challenge of reservesbeing found in technically challenging areas and the oil price moving in response topolitical as well as demand scenarios, there is the need to define more accuratelyforecasts of production and recovery. Reducing uncertainty is the message of thecurrent decade and not least in reservoir engineering and its related disciplines.

It is clear from what we have overviewed in this chapter and the topics which will becovered in the subsequent chapters that there are many parameters which contributeto the viability of the various aspects of successful oil and gas production. It is alsoclear that the various forms of data required, the confidence in the absolute values varyaccording to the type, and therefore the final impact on the final result will varyaccording to the particular parameter.

The following list summarises some of the principal uncertainties associated with theperformance of the overall reservoir model. The type of data can for example besubdivided into two aspects static and dynamic data .

Static Properties

Reservoir structure Reservoir properties Reservoir sand connectivity Impact of faults thief sands

Dynamic Properties

Relative permeability etc Fluid properties Aquifer behaviour Well productivity (fractures, welltype, condensate drop out etc.)

The impact of each of these parameters will vary according to the particular field butit is important that the company is not ignorant of the magnitude of the contributinguncertainties, so that resources can be directed at cost effectively reducing specificuncertainties. Figure 33 illustrates an outcome which might arise from an analysis ofvarious uncertainties for a particular field. It demonstrates for this particular field andat the time of analysis the impact of the various data has on the final project cost.Clearly in this case the aquifer behaviour uncertainties has the least impact whereasreservoir structure and well productivity uncertainties had the most significant.



Another field would result in different impact perspectives, and therefore a differentstrategy to reduce overall project uncertainty would be required.

Q

P

ProjectCost

Changes- +

WellproductionReservoir

area

Reservoirstructure

Sandconectives

Thief zones Faults

Fluid properties

Relativepermeabilities etc.

Aquiferbehaviour

8 PRODUCTION OPERATIONS OPTIMISATION

8.1 The Development PhaseThe development phase covers the period from the time continuous production startsuntil the production from the field stops i.e. abandonment. The decision when to stopproduction clearly is a techno-economic decision based to a large extent on the costsof the development. Low volume producers can be allowed to continue in an onshoredevelopment where well operating costs might be low but the high costs associatedwith for example in an expensive offshore operation sets a much higher economiclimit for the decision to abandon a field.

During the development phase Dake2 has identified a number of roles for theReservoir Engineering which are targeted at optimising production. It is an irony thatsome of the best data is generated during the production phase. Through productionthe reservoir unveils more of its secrets. Some of these may cause modifications to thedevelopment, perhaps in defining new well locations. The nature of the hydrodynamiccontinuity of the reservoir is mainly revealed through pressure surveys run after aperiod of production. This may define zones not being drained and thereforemodifications to the well completions might result.

As production progresses fluid contacts rise and therefore these contacts need to bemonitored and the results used to decide, for example, to recomplete a well as a resultof, for example excessive water production. As is pointed out in the chapter on

Figure 33.

Impact on a Project of

Different Uncertainties

34

reservoir pressure, development wells before they are completed provide a valuableresource to the reservoir engineer to enable surveys of pressure to be run to providea dynamic pressure-depth profile.

8.2 History MatchingThroughout the production phase the comparison of the actual performance with thatpredicted during the appraisal stage and more recent predictions is made. It is duringthis stage that the quality of the reservoir simulation model comes under examination.The production pressure decline is compared to that predicted and the reservoirsimulation model adjusted to match. This process is called history matching. Clearlyif the simulation cannot predict what has happened over the recent past it cannot beused with much confidence to forecast the future!

More simple approaches not requiring the resources of a complex simulator can alsobe used to up date early predictions, for example material balance studies.

Once production has been obtained, the additional data becomes available and makesan important contribution to the refining of the initial reserves estimates. Twotechniques historically used are decline curve analysis and material balance studies.

In material balance studies, the pressure-volume behaviour of the entire field isstudied assuming an infinite permeability for the reservoir. By assuming an initial oil-in-place from volumetric calculations, the pressure is allowed to decline followingfluid withdrawal. This decline is matched against the observed pressure behaviourand, if necessary, the original oil-in-place figure is modified until a match is obtained.In the presence of a water drive, additional variables are included by allowing waterinflux into the tank. Water influx is governed by mathematical relationships such asvan Everdingen and Hurst (These concepts are covered in Chapters 11, 12, and 13MB/MB Applications and Water Influx).

Decline curves are plots of rate of withdrawal versus time or cumulative withdrawalon a variety of co-ordinate scales. Usually a straight line is sought through theseobservations and extrapolated to give ultimate recovery and rates of recovery. Declinecurves only use rates of withdrawal and pay relatively little attention to the reservoirand flowing pressures. A change in the mode of operation of the field could changethe slope of the decline curve; hence, this is one of the weaknesses of this technique.

A noteworthy feature of these two approaches is that the engineer in fact fits a simplemodel to observe data and uses this model to predict the future by extrapolation. Asmore data becomes available the model gets updated and predicted results areadjusted. Decline curve analysis has not been used to the same extent as in the 60s and70s. With the power of computing and the efforts made to integrate geologicalunderstanding , the physics of the flow and behavior of rock and fluid systems intoreservoir simulation, the fitting and the uncertainty of earlier methods are beingsuperceded by integrated reservoir simulation modelling.

The routine company function will generate the need for on going production profileupdates. The generation of these is generally the responsibility of the reservoirengineer, who might chose simple analytical approaches to the more costly reservoirsimulation methods.



8.3 Phases of DevelopmentDuring the development there are a number of phases. Not all of these phases may bepart of the plan. There is the initial production build up to the capacity of the facilityas wells are brought on stream. There is the plateau phase where the reservoir isproduced at a capacity limited by the associated production and processing facilities.Different companies work with different lengths of the plateau phase and each projectwill have its own duration. There comes a point when the reservoir is no longer ableto deliver fluids at this capacity and the reservoir goes into the decline phase. Thedecline phase can be delayed by assisting the reservoir to produce the fluids by the useof for example lifting techniques such as down-hole pumps and gas lift. The declinephase is often a difficult period to model and yet it can represent a significant amountof the reserves. These phases are illustrated in figure 34

Build up phase

Plateau phase

Decline phase

Artificial lift

Time - years

Pro

duct

ion

rate

Economic limit

The challenge facing the industry is the issue of the proportion of hydrocarbons leftbehind. The ability to extract a greater proportion of the in-place fluids is obviouslya target to be aimed at and over recent years recoveries have increased through theapplication of innovative technology. Historically there have been three phases ofrecovery considered. Primary recovery, which is that recovery obtained through thenatural energy of the reservoir.

Secondary recovery is considered when the energy is supplemented by injection offluids, for example gas or water, to maintain the pressure or partially maintain thepressure. The injected fluid also acts as a displacing fluid sweeping the oil to theproducing wells. After sweeping the reservoir with water or gas there will still beremaining oil; oil at a high saturation where the water for a range of reasons, forexample; well spacing, viscosity, reservoir characteristics to name just a few, has by-passed the oil. The oil which has been contacted by the injected fluid will not becompletely displaced from the porous media. Because of characteristics of the rockand the fluids a residual saturation of fluid is held within the rock. Both of theseunrecovered amounts, the by-passed oil and the residual oil are a target for enhancedrecovery methods, EOR.

Figure 34.

Phases of Production.

36

Much effort was put into enhanced oil recovery (EOR) research up until the midseventies. Sometimes it is termed tertiary recovery. When the oil price has droppedthe economics of many of the proposed methods are not viable. Many are based on theinjection of chemicals which are often oil based. The subject of EOR has not beenforgotten and innovative methods are being investigated within the more volatile oilprice arena. Figure 35 gives a schematic representation of the various phases ofdevelopment and includes the various improved recovery methods. More recently anew term has been introduced called Improved Oil Recovery (IOR). IOR is moreloosely defined and covers all approaches which might be used to improve therecovery of hydrocarbons in place. Clearly it is not as specific as EOR but providesmore of an achievable target than perhaps some of the more sophisticated EORmethods.

As we have entered into the next millenium it is interesting to note that a number ofmajor improved recovery initiatives are being considered particularly with respect togas injection. One perspective which make a project more viable is that of the disposalof gas for example which is an environmental challenge in one field can be the sourceof gas for another field requiring gas for a gas injection improved oil recovery process.

PrimaryRecovery

Artifical LiftPump gas lift etc.

SecondaryRecovery

NaturalFlow

TertiaryRecovery

PressureMaintenance

Water, gas injection

NaturalFlow

Thermal Gas Chemical Microbial

Steam In-situcombustion.

Hydrocarbonmiscible, CO2N2 immisciblegas

Polymersurfactant/polymer

EOR

CONVENTIONAL

Figure 35.

Oil Recovery Mechanisms.



9. THE UNIQUENESS OF THE RESERVOIR

As we have discussed the role of the reservoir engineer in combination with otherdisciplines is to predict the behaviour of the reservoir. Whereas in the early years ofoil exploration little attention was paid to understanding the detailed characteristicsof the reservoir, it is now recognized that detailed reservoir properties associated withoften complex physical and chemical laws determine field behaviour. The unlockingof these characteristics and understanding the laws enable engineering plans to be putin place to ensure optimised developments are implemented. This is schematicallyillustrated in figure 36.

ReservoirBehaviour

DevelopmentPlan

Reservoir DescriptionUnique

Dynamic and Static

At one extreme for example in a blow - out situation, a reservoir produces in anuncontrolled manner only restricted by the size of the well through which isproducing. Optmised development however based on a thorough understanding of thereservoir enables the reservoir to be produced in a controlled, optimised manner.

In many other industries the effort expended on one project can be utilised inengineering a duplicate or a similar size unit elsewhere. Such opportunities are notpossible in the engineering of a reservoir. Reservoirs are unique in many aspects. Thecomposition of the fluids are unique, the rock characteristics and related propertiesare unique, the size and shape are unique and so on. From our perspective thisreservoir description is dynamic as the reservoir over a period of time gives up itssecrets. From the reservoirs perspective however the description is static, except withthe changes resulting from the impact of fluid production or injection. The challengeto those involved is reducing the time it takes for our dynamic description to match,our static description known only to the reservoir or whoever was responsible for itsformation! The answer perhaps is more of a philosophical nature. The reality is shownin figure 37 where the top structure map for a North Sea gas field with a ten year gapshows the impact of knowledge gained from a number of wells as against thatinterpreted from the one well. Considerable faulting is shown not as a result of majorgeological a activity over the ten years but knowledge gained from the data associatedwith the new wells.

Figure 36

Relationship between

Reservoir Description, and

Reservoir Behaviour.

38

49/26.1

200

200

210 220

220

5310 5310

5305 5305

SHELL/ESSO 49/26 AMOCO 49/27

Gas /water contactDepths in metresscale 1 100,000

2000

2100

2200

1000

1000 2000

800

2100

2000

2000

1000

2000

1000

2000

2000

1000

2100

1200

1000

2100

Depth in feet

0 10 1 2

MilesKMS

Gas /water contactA permanent platform

53055305

5300

5310

5300

5310

200

200 210

210

220

220

230

230

6900

6400

SHELL/ESSO 49/26 AMOCO 49/27

7000

6900

6900

63006300

7000

6900

6900

63006400

6300

6300

6200

6100

6400

6900

The coverage of the reservoir has also changed effecting the equity associated with theblocks. This illustrates the early benefits to be gained from drilling a number ofexploration wells. These equity agreements, are called unitisation agreements andsuch agreements are shortened when good quality and comprehensive reservoirdescription data is available. Clearly there can never be sufficient description,however the economics of project management will determine when decisions haveto be taken based on description to date. The value of extra information has to bebalanced by the cost of delay in going ahead with a project.

Figure 37 (a)

The Leman Field as it

Appeared to be When The

Exploration Well Was

Drilled.

Figure 37b

Leman Field Ten Years

After Discovery



10. CONCLUSION

In order to accomplish these objectives the Petroleum Reservoir Engineer should havea broad fundamental background both theoretically and practically in the basicsciences and engineering. The basic areas are:

(i) The properties of petroleum reservoir rocks(ii) The properties of petroleum reservoir fluids(iii) The flow of reservoir fluids through reservoir rock(iv) Petroleum reservoir drive mechanisms

It is also important that the Petroleum Reservoir Engineer has a thorough basicunderstanding in general, historical and petroleum geology. The influence of geologicalhistory on the structural conditions existing in a reservoir should be known andconsidered in making a reservoir engineering study. Such a study may also help toidentify and characterise the reservoir as to its aerial extent, thickness and stratificationand the chemical composition, size distribution and texture of the rock materials.

In his latest text, Dake2 comments on some of the philosophy of approach to reservoirengineering, and indentifies the importance of pinning down interpretation andprediction of reservoir behaviour to well grounded laws of physics.

Reservoir forecasting has moved on considerably since wells were drilled with littleinterest and concern into the production and forecasting of what was happening in thereservoirs thousands of feet below. The approach to coping with uncertainty asjokingly reflected in the cartoon below, (Figure 38) is no longer the case assophisticated computational tools enable predictions to be made with confidence andwhere uncertainty exists the degree of uncertainty can be defined.

"We feed the geological data for the area, the computer produces a schematic topologicaloverview designating high probability key points, then we stick the printout on the wall andLever throws darts at it."

Figure 38.

A Past Approach to

Uncertainty!

40

REFERENCES

1. Craft,B.C. and Hawkins, M.F. Applied Reservoir Engineering, Prentice-HallInc. 1959

2. Dake, L.P., The Practise of Reservoir Engineering. Elsevier. 19943. Society Of Petroleum Engineers. Reserves Definitions 1995.4. Chierici,G.L. Prociples of Petroleum Reservoir Engineering. Vol 1 Springer-

Verlag 19945. Hollois,A.P. Some petroleum engineering considerations in the change over of

the Rough Gas field to the storage mode. Paper EUR 295 Proc Europec. 1982,pg 175

6. API. A Statistical Study of the Recovery Efficieny. American PetroleumIntitute. Bull D14, 1st Edition ,1967

7. Archer,J.S. and Wall,C.G. Petroleum Engineering Principles and Practise,Graham and Trotman ,1986.

ResEngCh1

Documents

evolution of reserves

undeveloped reserves

reserves estimation1

recoverable reserves

reservoir modelling7

reservoir porosity5

reservoir area5

reservoir thickness5