Identification of Uncertainty in Reserves Estimation

Numerous uncertainties exist in estimating reserves and remaining recoverable

resources of conventional oil held by countries. These uncertainties include: geo￾logic, production performance, product market and uncertainties in oil price forecast,

the use of ambiguous definitions and inclusion of different subcategories of conven￾tional oil by reporting sources, the inclusion of politics in reserves estimation, the

inconsistent and unclear effects of aggregation of reserve data to country and

regional estimation, the anticipated volume of undiscovered oil, and the nature and

extent of reserve growth and its allocation to individual countries.

2.5.1 Uncertainty in Geologic data

Uncertainties arising from geological data include errors in getting the exact loca￾tions of the geologic structure, the field size, pay thickness, porosity and permeabil￾ity variation, reservoir and aquifer sizes, reservoir continuity, fault position,

petrofacies determination, and insufficient knowledge of the depositional environ￾ment. A number of techniques are available for the quantification of geologic

uncertainties. One of the widely used techniques is to quantify the uncertainty in

the geological model with a geostatistical tool. Geostatistics involves synthesizing

geological data using statistical properties such as a variogram (Bennett and Graf

2002). This process enables the geologists to generate multiple realizations of the

geological models (Stochastic) which allows quantification and minimization of

uncertainties associated with the geological information.

Uncertainty in Seismic Predictions

• The quality of the seismic data (bandwidth, frequency content, signal-to-noise

ratio, acquisition and processing parameters, overburden effects, etc.)

• The uncertainty in the rock and fluid properties and the quality of the reservoir

model used to tie subsurface control to the 3D seismic volume

2.5.3 Uncertainty in Volumetric Estimate

The uncertainties in reservoir volume estimate will arise from several properties and

characteristics of the reservoir.

2.5.3.1 Gross Rock Volume (GRV) of a Trap

• The incorrect positioning of structural elements during the processing of the

seismic and lack of definition of reservoir limits from seismic data

• Incorrect interpretation

• Errors in the time to depth conversion

• Dips of the top of the formation

• Existence and position of faults

• Whether the faults are sealing to prevent further lateral migration of the

hydrocarbon

2.5.3.2 Rock Properties: Net-to-Gross and Porosity

The uncertainty associated with the properties of the reservoir rock originates from

the variability in the rock. It is determined through petrophysical evaluation, core

measurements, seismic response, and their interpretation. Most times, the core

samples are not properly handled carefully in the process of transporting it from

the field to the laboratory for analysis. Also in the laboratory, artificial properties are

induced during the core preparation and analysis. While petrophysical logs and

measurements in the laboratory may not be quite accurate, the samples collected

may be representative only for limited portions of the formations under analysis.

Thus, there are some risks associated with the petrophysical parameters estimation

such as depth matching, operational risks, log interpretation and reservoir

heterogeneities.

Fluid Properties

For fluid properties, a few well-chosen samples may provide a representative

selection of the fluids. The processes of convection and diffusion over geologic

times have generally ensured a measure of chemical equilibrium and homogeneity

within the reservoir, although sometimes gradients in the fluid composition are

observed. Sampling and analysis may be a significant source of uncertainty. PVT

or fluid properties vary with pressure, temperature, and chemical composition from

one region to another. As a result of this regional trend, correlations developed from

regional samples that are predominantly paraffinic in nature may not provide

acceptable results when applied to other regional crude oil systems that are dominant

in naphthenic or aromatic compounds.

The effective use of PVT correlations depends on the knowledge of their devel￾opments and limitations. In addition, samplings of these properties are not always

readily available due to cost and time. Thus, the engineers in view of achieving their

goals resort to the use of empirically derived correlations in estimating these

properties. However, a significant error is usually associated with the estimation of

these fluid properties which in turn propagates additional errors in all petroleum

engineering calculations.

2.5.3.4 Fluid Contacts

One of the parameters required for the estimation of hydrocarbon reserve is the gross

rock volume (bulk volume of the rock) whose accuracy is dependent on the fluid

contacts (gas-oil and/or water-oil contact). Therefore, if the contacts are not ade￾quately determined, it will lead to either over or under estimation of the bulk volume.

Thus, affecting the overall value of the estimated reserve.

2.5.3.5 Recovery Factor (RF)

Recovery is based on the execution of a project and it is affected by the shape and the

internal geology of the reservoir, its properties and fluid contents, and the develop￾ment strategy. If a reservoir is poorly defined, material balance calculations or analog

methods may be used to arrive at an estimate of the range of RFs. Uncertainty ranges

in the RF can often be based on a sensitivity analysis. Besides, the reservoir drive

mechanism and the problem of reservoir monitoring or management of some level of

uncertainties

Economic Significant of Reservoir Uncertainty

Quantification

During the life of a reservoir, the pre-reservoir and post-reservoir performance

evaluations are generally not equal. This is due to inadequate quantification of

uncertainties associated with the reservoir model input parameters and the resulting

composite uncertainty associated with the pre-reservoir performance prediction. The

decision to develop a reservoir is based on the prediction of production performance

following history-matching process. Likewise, in some instances, the decision to

obtain additional reservoir measurement data is taken when the uncertainty of the

forecast is great.

Hence, acquisition of further data is the reason for accurate quantification of

uncertainty associated with reservoir performance forecast so that projected recovery

will be accurately estimated for economic decisions. These vital reasons underline

the economic importance of increasing interest to properly quantify the uncertainties

associated with reservoir performance simulation.

2.6 Reservoir Characterization

An accurate description of reservoir rock, fluid contents, rock-fluid systems, fluid

description and flow performance are required to provide a sound basis for reservoir

engineering studies. Hence, proper reservoir characterization is important to analyze

the effects of heterogeneity on reserve estimation and reservoir performance due to

primary, secondary, and/or enhanced oil recovery operations. Porosity and perme￾ability are important flow properties; an accurate reservoir characterization requires

accurate porosity and permeability description as a function of space.

Reservoir characterization is a process carried out to reduce geological uncer￾tainties by quantitatively predicting the properties of a reservoir and define reservoir

structural changeability or variability. It is a process ranging from the discovery

phase to the management phase of a reservoir. Prior to performing a reservoir

simulation, accurate characterization is the first key step to undertake which helps

to identify uncertainty range inherent in reservoirs. Here we try to assess the range of

reservoir performance from an understanding of the subsurface uncertainties. This

concept is a limitation and it is not considered in the material balance method

presented in Chap. 5 of this book.

At this point, we need not border ourselves with a thorough review of literature in

reservoir rock characterization which would not be practically possible because of

the wide nature of this discipline and it is not incorporated in this present book.

However, the process combines the technical disciplines of geology, geophysics,

reservoir engineering, production engineering, petrophysics, economics, and data

management with key objectives on modeling each reservoir unit, understanding and

predicting well behavior, understanding past reservoir performance, and forecasting

future reservoir performance. Hence, it is used to assert a strong impact on plans for

the development and performance of a field.

 

Resources and Reserves 1

 Introduction

The development of oil and gas fields today depend solely on the amount of the

recoverable hydrocarbon fluid (reserves) discovered in the subsurface formation

(reservoir) and its economic viability. The estimation of these reserves are usually

associated with some level of uncertainties and when these uncertainties are not

factored into the prospect evaluation, the result is a wrong estimation of the reserves.

This means that the value of reserves estimation is a key driver for exploration and

production companies to decide whether to develop or abandon the prospect based

on their set criteria. Therefore, in estimating oil and gas reserves, we rely on the

integrity, skill and the judgment of the evaluator based on the amount of data

available, the complexity of the formation geology and the degree of depletion of

the reservoir (SPE, 1997)

Parties that Use Oil and Gas Reserves

• Companies operating oil and gas field or own an interest in petroleum operations

for in-house valuation

• Banks and other financial institutions involved in financing

• Stock markets around the world

• Regulatory bodies to protect the general public, to manage natural resources, and

to promote uniformity

• Taxation agencies with authority over petroleum products

• Investors in petroleum companies

• Mineral rights owners

• Arbitration (negotiation, settlement, etc) parties. i.e. to work out a deal

• Government for energy policies and strategic planning

2.3 Reasons for Estimating Reserves

• To obtain approvals from relevant ministries and other regulatory bodies

• For exploration, development & production of oil and gas reservoir

• To negotiate property sales and acquisitions

• To determine the market value

• To design facilities

• To obtain financing

• Evaluation of profit/interest

• Government regulations & taxation

• Planning & development of national energy policies

• Investment in oil/gas sector

• Reconcile dispute or arbitration involving reserves

2.4 Resources and Reserves

Resources, sometimes referred to as accumulations, are the total assumed quantities

of hydrocarbons found beneath the earth crust that could exist which may or may not

be produced in the future.

Reserves are estimated remaining quantities of oil and natural gas and related

substances anticipated to be recoverable from known accumulations, as of a given

date, based on the following:

• Analysis of drilling, geological, geophysical, and engineering data;

• The use of established technology;

• Specified economic conditions, which are generally accepted as being reasonable,

and shall be disclosed.

Hydrocarbon Resources

Resources are the total estimated quantities of hydrocarbons found beneath the earth

crust that could exist which may or may not be produced in the future. These are

commonly referred to as “Accumulations”. Resource is basically different from

reserve whose hydrocarbon deposit is known to exist with reasonable certainty

based on studies from geology and engineering. It encompasses all of the hydrocar￾bons that could exist, regardless of whether it is recoverable or known to exist.

Therefore, a resource can either be discovered or undiscovered (unknown and cannot

be estimated), economically recoverable or not economically recoverable. It includes

portions of hydrocarbons that are assumed to be present but are not measured

because they have not been explored or are located in inaccessible position.

The amount of naturally occurring accumulations of hydrocarbon estimated to be

originally in place is known as original resources. Hence, if the prospect has been

produced for a particular period of time, the original resources can also be defined on

a given date as the sum of the estimated quantities of hydrocarbon remaining in the

reservoir (naturally occurring accumulation) plus the quantities of the hydrocarbon

already produced plus quantities in the accumulations yet to be discovered if any.

Original resources can be classified as discovered or undiscovered and each of these

is further classified in the flow chart below (Fig. 2.2).

Contingent Resources

Contingent Resources are those potentially recoverable estimated quantities of

hydrocarbon from discovered accumulations on a given date, whose prospect or

project is not currently viable commercially or mature enough and are uneconomical

for development due to one or more uncertainties or contingencies. Some of these

contingencies may be that there is no current viable market(s) for the hydrocarbon, or

if commercial recovery of the hydrocarbon content is clinging on technology under

development, or evaluation of the accumulation is insufficient to clearly assess

commerciality.

Furthermore, the fact that contingent resource is not commercially viable does not

mean it cannot be seen as a reserve (that is, the movement from contingent resources

into reserves category) but if the key contingencies preventing commercial devel￾opment are adequately addressed or removed, then it can be called a hydrocarbon

reserve.

Classification of Contingent Resources

Development Not Viable

A discovered accumulation of hydrocarbons where viable processes of recovering

the hydrocarbon content have not yet been developed or a scenario where there are

no current plans to develop or to acquire additional data at the said time due to

limited production potential.

Development Unclarified or on Hold

A discovered accumulation of hydrocarbons of significant size where activities of

the project are not cleared or are on hold and/or where justification as a commercial

development may be subject to significant delay such as political, environmental,

technical or the dwindling market conditions.

Development Pending

This is an accumulation of discovered hydrocarbons where further data acquisitions

are required to confirm commerciality. In this case, the activities of the prospect are

presently happening or ongoing to provide an acceptable explanation of commercial

development in the anticipated or foreseeable future.

2.4.1.2 Prospective Resources

On the other hand, prospective resources which can be referred to as expected or

soon-to-be resources; are defined as the estimated volumes associated with

undiscovered accumulations or as estimated quantities of hydrocarbon as of a

given date to be potentially recoverable and are analyzed on the basis of indirect

evidence but have not yet been drilled. They are technically viable and economical to

produce but they present a higher risk than contingent resources since the risk of

discovery is also added.

Furthermore, we should note that while the engineers and geoscientists take into

consideration the possibility of hydrocarbons discovery and development when

determining the quantities of prospective resources, they also make some assump￾tions which include a range of uncertainty whether the hydrocarbons will be found.

The prospective resources are further classified as low, best and high estimate as

shown in Fig. 2.2.

Also, there can be a movement from prospective resources to contingent

resources, only if hydrocarbons are discovered and the accumulated discovery

must be further evaluated to determine an estimated quantity that would be recov￾erable under appropriate development projects.

Classification of Prospective Resources

According to the guidelines for the evaluation of petroleum reserves and resources by

Society of Petroleum Engineers (2001), prospective resources can be classified as:

Play

A project associated with a prospective trend of potential prospects, but requires more

data acquisition and/or evaluation to define specific leads or prospects. This is a

concept of exploration that includes a specific source rocks, reservoir rocks, migration

path and the type of trap to allow the discovery of recoverable quantity of hydrocarbon

(Norwegian Petroleum Directorate,1997).

Lead

A project associated with a potential accumulation that is currently poorly defined

and requires more data acquisition and/or evaluation to be classified as a prospect.

This implies that the data available is not enough to fully classify it as a prospect for

development.

Prospect

A project associated with a potential accumulation that is sufficiently well defined to

represent a viable drilling target. It implies a trap that has been identified and

adequately mapped but yet to be drilled. At this stage, there are some questions

asked to fully evaluate the play or prospect. These are:

• If we are certain of the hydrocarbon source, what then is the content (oil or/and

gas)?

• Can the content in the source rock migrate to the reservoir rock where it is

accumulated and how much of it?

• Does the reservoir have a storage capacity?

• What are the characteristics of the reservoir?

• Are there trapping mechanisms to help prevent the content of the reservoir from

further migration?

• If there is a trap, how efficient is it (seal or non-sealing)?

2.4.2 Hydrocarbon Reserves

Reserves are seen as the heart of the oil and gas business. These can be defined as the

estimated quantities of hydrocarbon such as crude oil, condensate, natural gas

(associated or non-associated gas) that are anticipated to be commercially recover￾able with the use of established technology on a known hydrocarbon accumulations

from a given date forward under existing economic conditions, established operating

conditions and current government regulations with a legal right to produce and a

production & transportation facilities to deliver the products to the market. Also, the

interpretations of reliable geologic, geophysics, drilling and engineering data avail￾able at the time of estimation are key factors that support the reserves definition.

Reserves estimates are generally revised as additional geologic or engineering data

becomes available or as economic conditions change.

In the previous statement, we established that contingent resources can be moved

to reserves. Therefore, based on development project(s), hydrocarbon reserves must

satisfy four criteria, and these are: discovered, recoverable, commercial, and

remaining quantity as at the date of evaluation (PRMS, 2017). Also, there must be

a reasonable expectation that all required internal and external approvals will be

forthcoming and evidence of company’s intention to proceed with the development

within a reasonable time frame; say 10 years to the international oil companies.

Generally, if they cannot develop it within this time frame, they might be mandated

by the regulatory body to farm-out to marginal field operators.

2.4.2.1 Hydrocarbon Reserves Classification

Classification by Development Operations

Oil and gas reserves can be classified to be on production, which implies that the

prospect is currently producing and the product delivered to the market for con￾sumption. It can be classified as being under development, which means that every

expedient approval has been obtained and the project development is in progress.

Furthermore, having satisfied all criteria for reserves, It can be classified has been

scheduled or outlined for development with substantial desire to develop but all

mandatory approvals have not be finalized or complete detailed development plan

have not been made.

Reserves are further classified according to the degree of certainty associated with

the estimation (Ross, 2001). These are: proved and unproved (probable and possible

reserves).

Classification by Degree of Uncertainty of Estimation

Proved Reserves

Proved reserves are those quantities of hydrocarbon reserves based on analysis of

geological and engineering data that can be estimated with a reasonably high degree

of certainty to be commercially recoverable from a given date forward from known

reservoirs and under current economic conditions, operating methods, and govern￾ment regulations. It is likely that the actual remaining quantities recovered will

exceed the estimated proved reserves. In general, reserves are considered proved if

the commercial producibility of the reservoir is supported by actual production or

formation tests. In its method of estimation, if probabilistic methods are used, there

should be at least a 90% probability that the quantities actually recovered will equal

or exceed the estimate and if deterministic methods are used, the term with reason￾able certainty is intended to express a high degree of confidence that the quantities

will be recovered.

Probable Reserves

Are those quantities of hydrocarbon based on geologic and/or engineering data

similar to that used in the estimation of proved reserves; but technical, contractual,

economic, or regulatory uncertainties deter such reserves from being classified as

proved. In this context, when probabilistic methods are used, there should be at least

a 50% probability that the quantities actually recovered will equal or exceed the sum

of estimated proved plus probable reserves.

Possible Reserves

Possible reserves are those additional reserves that are less certain to be recovered

than probable reserves. It is unlikely that the actual remaining quantities recovered

will exceed the sum of the estimated proved plus probable plus possible reserves.

They can also be defined as those unproved reserves which analysis of geological

and engineering data suggests that they 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 of estimated proved plus probable plus possible reserves.

Introduction reservoir engineering 6 Productivity Index (PI or j) The productivity index

 The productivity index is calculated mathematically as

The productivity index is calculated mathematically as

Factors Affecting the Productivity Index

• Phase Behaviour of Fluids in the Reservoir

• Relative Permeability

• Oil Viscosity

• Oil Formation Volume Factor

• Skin

1.6.2 Phase Behaviour in Petroleum Reservoirs

As reservoir pressure drops below the bubble point, free gas begins to form and thus

the oil relative permeability (kro) is reduced. If a well is produced at a flow rate that

requires the wellbore flowing pressure (Pwf) to be less than the bubble point pressure

(Pb), the oil relative permeability and the productivity index (PI) will be decreased

around the wellbore.

1.6.3 Relative Permeability Behaviour

As free gas form in the pores of a reservoir rock, the ability of the liquid phase to

flow is decreased. Even though the gas saturation may not be great enough to allow

gas to flow, the space occupied by the gas reduces the effective flow area of the

liquid. Conversely, in gas reservoir, the relative permeability to gas will be decreased

if liquid saturation develops either as a result of retrograde condensation or water

formation in the pores.

1.6.4 Oil Viscosity Behaviour

The viscosity of oil saturated with gas at constant temperature will decrease as

pressure is decreased from an initial pressure to bubble point pressure (Pb). Below

Pb, the viscosity will increase as gas comes out of solution leaving the heavier

components of the hydrocarbon.

Oil Formation Volume Factor

As pressure is decreased in the reservoir, the hydrocarbon will expand and when the

bubble point pressure is reached for an oil reservoir, gas starts coming out of solution

which causes the oil to shrink thereby reducing the volume of the oil.

1.6.6 Skin

A well that is damaged results in low fluids flow potential. Thus, formation damage

is an impairment of reservoir permeability around the wellbore, leading to low or no

well production or injection. Or simply refers to the decrease in permeability that

occurs in the near wellbore region of a reservoir. Formation damage is often

quantified by “Skin” factor. Skin is strictly a measure of an excess pressure in the

producing formation as fluids flow into a well. Skin alters the flow of fluid; that is an

impairment to flow.

The excess pressure drop can occur from one or several of a wide variety of

causes such as drilling mud, cement, completion fluid filtrate invasion, solids

invasion, perforating damage, fines migration, formation compaction, swelling

clays, asphaltene/paraffin deposition, scale precipitation, emulsions, reservoir com￾paction, relative permeability effects, effects of stimulation treatments, etc.

Application of Dimensionless Parameters in Calculating

Flow Rate and Bottom Flowing Pressure

Now, let us write the pressure drop in dimensionless pressure

Shape Factors for Various Closed Single – Well Drainage Areas

Check for the flow regime at the given shape of the reservoir

Note, at any given time, the reservoir will behave like an infinite acting system,

that is, the reservoir is still undergoing transient flow condition if

tDA calculated ð Þ < tDA tabulated ð Þ

Thus, PD is calculated based on area as:

Introduction reservoir engineering 5 ( Unsteady or Transient-State Flow )

 The state of fluid flow is termed unsteady-state flow, if the rate of change of pressure

with respect to time at any position in the reservoir is not zero or constant. It is also

called transient state whose behavior occurs when the boundary effect of the

reservoir has not been felt and at this point, the reservoir is said to be infinite￾acting. It can simply be defined as the flow regime where the distance/radius of

pressure wave propagation from the wellbore has not reached any of the reservoir

boundaries as shown in the figure below. Thus, at a short period of flow, the reservoir

behaves as if it has no boundary, this will continue until the pressure transient gets to

the boundary of the reservoir. Therefore, after the reservoir boundary has been

contacted, the flow will either buildup to steady state or pseudo-steady state flow.

Pseudo-Steady with the Effect of Skin (Tables 1.4, 1.5

and 1.6a, b)

The pressure drop due to skin at the well is

Values of exponential integral,
Ei(
y)

PD vs tD – Infinite

radial system, constant rate at

inner boundary

PD vs tD – Finite radial system with closed exterior, constant rate at inner boundary

reD

¼ 4.5 reD

¼ 5.0 reD

¼ 6.0 reD

¼ 7.0 reD

¼ 8.0 r

Pseudo-Steady or Semi-State Flow

A reservoir attains pseudo-steady state (PSS), if the rate of change of pressure

decline with time is constant. The pressure throughout the reservoir decreases at

the same constant rate, this scenario cannot occur during build-up or falloff tests. In

this state of flow, the boundary has been felt and static pressure at the boundary is

declining uniformly throughout the reservoir. Mathematically, this definition states

that the rate of change of pressure with respect to time at every position in the

reservoir is constant, or a state where the mass rate of production is equal to the rate

of mass depletion. This state can also be referred to as semi-steady state (SSS) or

quasi-steady state.

Introduction reservoir engineering 4 (Types of Fluids in Terms of Flow Regime and Reservoir Geometry)

 The fluid in hydrocarbon reservoirs can be classified in terms of pressure change occurring as fluid flow from various path of the reservoir system to the wellbore. They are further classified in terms of flow regime and reservoir geometry. The reservoir fluid can either by incompressible, slightly compressible or compressible depending on the state of the pressure change in the reservoir. When the volume or density of the fluid does not change with pressure, it is called an incompressible fluid. This implies that as the pressure within the system changes, the volume of the fluid remains the same. This fluid behavior hardly exists but it is an assumption for easy derivation for fluid flow equations. For the case of a slightly Temperature 100% Liquid (Tr Pr) Dry Gas Fluid path in the reservoir Production path Dry gas reservoir (Twf Pwf) 0% Liquid 80% 60% 20% 5% Critical point Well bone Dew point curve Two phase region Bubble point curve Pressure Separator (Tsep, Psep) Fig. 1.14 Dry gas reservoir Table 1.2 Properties of wet and dry gas reservoir fluid Parameter Wet gas Dry gas Effect of pressure reduction There are tracies of liquid at the surface No tracy of liquid at the surface Gas-oil ratio (GOR) 100,000 scf/stb >100,000 scf/stb Color Light straw to water white Water white Viscosity Low Very low API >60 1.5 Types of Fluids in Terms of Flow Regime and Reservoir Geometry 19 compressible fluid, there is a little change in volume or density as pressure changes. Also, for fluid such as gase's are easily compressible and expand to fill the volume of its container; this makes gases to experience large changes in volume as a function of pressure. This is termed a compressible fluid.

1.5.1 Reservoir Geometry Petroleum reservoir is usually trapped with fluids that are looking for ways to flow out; once a well is drilled, cased and perforated, the trapped fluid then flows from all directions in the reservoir to the wellbore where it is produced to the surface facilities. The movement of hydrocarbon fluid towards the wellbore is either characterized as radial or linear depending on the flow direction. 1.5.1.1 Linear Flow Linear flow occurs when the paths at which the fluids flow are parallel to each other such that the movement is in a single direction. In this type of flow, the crosssectional area is assumed to be constant, thereby creating a laminar flow. This is represented in Fig. 1.15. 1.5.1.2 Radial Flow On the other hand, radial flow occurs when fluids move in a multi-direction within the reservoir towards the perforations at the wellbore, thus creating an iso-potential lines. The radial flow system is shown in Fig. 1.16.

1.5.2 Flow Regimes 1.5.2.1 Steady-State Fluids Flow This type of flow is referred to the condition at any single or given point in the reservoir where the properties such as pressure, temperature and velocity of the fluid does not change with time. It can be defined as the flow at which the rate of change of pressure (P) with respect to time (t) at any location i in the reservoir is zero as shown in the equation below. At this state of flow, all the boundaries effects have been felt but there is no decline in the static pressure at the boundary (called constant pressure boundary). This implies that in a system of mass flow rate, there is no accumulation of mass within any component in the system. Steady state flow is more applicable to laboratory displacement experiments than to petroleum reservoir conditions which are hardly seen. This scenario can only be seen in reservoirs undergoing pressure maintenance either by water or gas injection or when the reservoir is completely recharging and supported by a strong aquifer. This is to say that; there is a flow of fluid across the boundaries of the reservoir (unbounded reservoir).

Radial Flow Equation for Steady-State (Unbounded Reservoir) Incompressible Fluid By derivation for oil flow

1.5.2.4 Steady State with the Effect of Skin Practically, during drilling and completion operations, the permeability around the wellbore of most wells have been damaged or reduced thereby causes an impairment to flow of fluid and thus create an additional pressure drop near the wellbore. This impairment to flow is known as skin. Incorporating it into the flow equation gives:

1.5.2.5 Radial Flow Equation for Steady-State (Unbounded Reservoir) Slighty Compressible Fluid

Radial Flow Equation for Steady-State (Unbounded Reservoir) Compressible Fluid (Gases) Low pressure approximation

Calculation of Real Gas Potential, m(p) The m(p) can be calculated graphically or read from Tables. The graphical method requires that P, μ, z be given and m(p) calculated from the area under a curve (Table 1.3). This is illustrated below using the trapezoid method to calculate the area under the curve. Trapezoidal rule

Introduction reservoir engineering 3 (Gas Reservoirs)

 Gas Reservoirs

Hydrocarbon reservoir can be called gas reservoir, if the temperature of the reservoir is greater than the cricondentherm of the hydrocarbon fluid. This is only applicable to non-associated gas reservoirs which can either be wet or dry gas depending on the phase present in the reservoir and at the surface separator. 1.4.5.5 Wet-Gas Reservoirs A natural gas system which contains a significant amount of propane, butane and other liquid hydrocarbons is known as wet gas or rich gas. It contains less amount of methane (85%) and more ethane than dry gas. Figure 1.13 shows a wet gas reservoir which exists solely as a gas in the reservoir throughout the reduction in reservoir

pressure. It temperature lies above the cricondentherm of the hydrocarbon mixture similar to a dry gas reservoir. The reservoir fluid will always remain in the vapor phase region as the reservoir is depleted isothermally, along with the production path unlike retrograde condensate; no liquid is formed inside the reservoir. However, separator conditions lie within the phase envelope, causing some liquid to be formed at the surface. This surface liquid is normally called condensate. Wet-gas reservoirs are characterized by gas oil ratios between 60,000 to 100,000 scf/STB, stock-tank oil gravity above 60 API, the liquid is water-white in color and separator conditions lie within the two-phase region. 1.4.5.6 Dry Gas Reservoir The hydrocarbon mixture of a dry gas exists as a gas in the reservoir (even in the two phase region) and in the surface separator characterized with a gas-oil ratio greater than 100,000 scf/STB. It contains mainly methane with some intermediates. The pressure or production path does not enter into the phase envelope (two phase region) as shown in Fig. 1.14, this means that the surface separator conditions fall outside the phase envelope which is in contrast to wet gas reservoir; hence there is no traces of liquid formed at the surface separator. Natural gas which occurs in the absence of condensate or liquid hydrocarbons, or gas that had condensable hydrocarbons removed, is called dry gas. It is primarily methane with some intermediates. The hydrocarbon mixture is solely gas in the reservoir and there is no liquid (condensate surface liquid) formed either in the reservoir or at the surface. The pressure path (line) does not enter into the phase

Introduction reservoir engineering 2

Types of Reservoir 

The classification of a hydrocarbon reservoir is basically dependent on the composition of the hydrocarbon mixture in the reservoir, the location of the initial pressure and temperature of the reservoir and the condition at the surface (separator) production pressure and temperature. A hydrocarbon reservoir can be classified as either oil black oil or volatile oil or condensate or natural gas (associated or non-associated) reservoirs. Since the hydrocarbon system has varying fluid compositions, to appropriately classify or identify the type of reservoir system, we need to understand the hydrocarbon phase envelope (pressure-temperature diagram). 

1.4.3 Phase Envelope 

According to Wikipedia, a phase envelope is a type of chart used to show conditions of pressure, temperature, volume etc at which thermodynamically distinct phases occur and coexist at equilibrium. Figure 1.8 depicts a phase envelope or pressure temperature (PT) phase diagram of a particular fluid system. It comprises of two curves (bubble point and dew point curves) which encloses an area representing the pressure and temperature combinations for which both gas and liquid phases exist; called the two-phase region. The curves or quality lines converging at the critical

point within the two-phase envelope indicate the percentage of liquid at any given pressure and temperature of the total hydrocarbon volume of the reservoir. Furthermore, on the phase envelope, we can place the various types of reservoirs depending on the location of the initial reservoir temperature and pressure with respect to the two-phase. Above the bubble-point curve in Fig. 1.8, we have a single liquid phase called an undersaturated reservoir while at a point beyond the dew point curve; a single gas phase occurs which may be a wet or dry gas reservoir. The various terms on the phase envelope are defined below. 1.4.3.1 Bubble-Point Curve The bubble-point curve is defined as the line separating the liquid-phase region from the two-phase region and above which a single liquid phase exists as shown in Fig. 1.8. Note, if there is gas, it will be dissolved in the liquid. 1.4.3.2 Dew-Point Curve The dew-point curve is defined as the line separating the vapor-phase region from the two-phase region and above which vapor phase exists as shown in Fig. 1.8. 1.4.3.3 Cricondentherm The Cricondentherm (Tct) is defined as the temperature above which there is no existence of two-phase irrespective of the pressure or it can be defined as the maximum temperature above which a single gas phase exist and no liquid can be formed regardless of pressure (Fig. 1.8). The pressure corresponding to cricondentherm is known as the cricondentherm pressure (Pct)

1.4.3.4 Cricondenbar The cricondenbar (Pcb) is defined as the pressure above which there is no existence of two-phase irrespective of the temperature or it can be defined as the maximum pressure above which a single liquid phase exists and no gas can be formed regardless of temperature (Fig. 1.8). The temperature corresponding to cricondenbar is known as the cricondenbar temperature (Tcb). 1.4.3.5 Critical Point The critical point is the point where the bubble point curve, dew point curve and the quality lines converge (Fig. 1.8). At this point, one cannot distinguish between the liquid and gas properties. Hence it is referred to as the state of pressure and 12 1 Introduction temperature at which all intensive properties of the gas and liquid phases are equal. The corresponding pressure and temperature at the critical point are referred to as the critical pressure (Pc) and critical temperature (Tc) of the mixture. 1.4.3.6 Quality Lines These are dash lines enclosed by the bubble-point curve and the dew-point curve. They converge at the critical point. They also describe the pressure and temperature conditions for equal volumes of liquids as shown in Fig. 1.8.

1.4.3.7 Phase Envelope (Two-Phase Region) This is the area enclosed by the bubble-point curve and the dew-point curve, wherein gas and liquid coexist in equilibrium; it is the region where we have the quality lines (Fig. 1.8). That is the region of greater than zero percent (0%) liquid and less than hundred percent (100%) on the phase envelope. 1.4.4 Oil Reservoirs A reservoir can be classified as oil reservoir if the temperature of the reservoir is less than the critical temperature of the reservoir fluid. It can be further classified as a black oil or volatile oil depending on the gravity of the stock tank liquid usually the API of the crude. Also, it can be classified as undersaturated or saturated reservoir based on the location of the initial reservoir pressure. 1.4.4.1 Undersaturated and Saturated Reservoir The fluid in the reservoir is a complex mixture of hydrocarbon molecules and as pressure and temperature reduces; that is the flow of hydrocarbon fluid from the reservoir condition to the surface separator, phase changes occur. Considering an undersaturated and a saturated reservoir as shown in Fig. 1.9 it can be seen that at the initial pressure, the reservoir is represented as a single liquid phase. As the pressure drops from the initial condition to the wellbore as a result of fluids production; the fluid remains as a single phase liquid at the wellbore. Therefore, a reservoir whose temperature is greater than the bubble point pressure is referred to as an "undersaturated reservoir". As the pressure reduces further until it reaches the bubble point pressure (saturated pressure) where the first bubble of gas is evolved from the hydrocarbon mixture, the fluid still remains in a single liquid phase. Below the bubble point pressure, there is a two-phase region and with further reduction in pressure, the fluid is produced up the tubing and the amount of gas evolved increases until it reaches the separator. Thus,

1.4.5 Types of Reservoir Fluids 1.4.5.1 Black Oil Reservoir Figure 1.10 represents a black oil system which is made up of heavy hydrocarbons and non-volatile hydrocarbons. It is characterized by a dark or deep color liquid having initial gas-oil ratios of 500 scf/stb or less, oil gravity between 30 and 40 API. The pressure and temperature conditions existing in the separator indicate a high percentage of about 85% of liquid produced. The oil remains undersaturated within the region above the bubble point pressure, this means that the oil could dissolve more gas if present in the hydrocarbon mixture. At the bubble point pressure, the reservoir is said to be saturated and this implies that the oil contains the maximum amount of dissolved gas and cannot hold any more gas. Further reduction in pressure causes some shrinkage in the volume of oil as it moves from the reservoir (two-phase region) to the surface (separator). Therefore, black oil is often called low shrinkage crude oil or ordinary oil. 1.4.5.2 Volatile Oil Reservoir A volatile oil reservoir is one whose reservoir temperature is below the critical point or critical temperature of the fluid as shown in Fig. 1.11. It contains relatively low

liquid content as it approaches the critical temperature, as compared to black oil reservoir that is far away from the critical point; a volatile oil reservoir is made up of fewer heavy hydrocarbon molecules and more intermediate components (ethane through hexane) than black oils. Volatile oils are generally characterized with Temperature 100% Liquid (Twf Pwf) (Tr, Pr) Volatile oil reservoir Critical point (Tsep, Psep) Separator 0% Liquid 80% Dew point curve Bubble point curve Production path Fluid path in the reservoir Pressure Fig. 1.11 Volatile oil reservoir Temperature 100% Liquid (Twf Pwf) (Tr, Pr) Black oil reservor Critical point (Tsep, Psep) Separator 0% Liquid 80% Dew point curve Bubble point curve Production path Fluid path in the reservoir Pressure Fig. 1.10 Black oil reservoir 1.4 Reservoir Engineering 15 stock tank gravity between 40 and 50 API, with a lighter color (brown, orange, or green) than black oil. In the case of volatile oil, 65% of the reservoir fluid is liquid at the separator condition. This means that relatively large volume of gas is evolved from the hydrocarbon mixture leaving a smaller portion as liquid. It is a high shrinkage oil as compared to black oil. 1.4.5.3 Condensate (Retrograde Gas) A condensate reservoir fluid is a gas at the initial reservoir pressure. It occurs as shown in Fig. 1.12 when the temperature of the reservoir lies between the critical temperature and cricondentherm of the reservoir fluid. It contains lighter hydrocarbons and fewer heavier hydrocarbons than volatile oil, its oil gravity is above 40 API and up to 60 API (i.e. between 40 and 60 API), the gas-oil ratio increases with time due to the liquid dropout, and the loss of heavy components in the liquid whose GOR is up to 70,000 scf/stb, it has about 5–10% liquid at the surface depending on the reservoir. The reservoir fluid is water-white or slightly colored oil at the stock tank. In Fig. 1.12, at the initial condition, the reservoir is in a single gas phase and as the pressure drops, the fluid goes through the dew point which then condenses large volumes of liquid as it passes through the two phase region in the reservoir. Consequently, as the reservoir further depletes and the pressure drops, liquid condenses from the gas to form a free liquid inside the reservoir.

In the production of a gas condensate field, gas is mostly produced with some liquid dropout as the pressure drops below dew point pressure; occurring mostly in the separator and can still be produced in the wellbore which ultimately leads to a restriction in the flow of gas. The temperature and pressure may change once the reservoir fluids enter into the wellbore, thereby causing liquid dropout within the wellbore. Thus, if the gas having the larger fraction does not have enough energy to lift the dropout liquid to the surface, a fallback in the wellbore occurs or liquid loading. If this is continuous, the percentage of the liquid will increase and may eventually restrict the gas production. This challenge can be adequately handled with artificial lift technologies such as gas lift. Table 1.1 shows the comparison of blackoil, volatile and condensate reservoir fluid properties