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1 Introduction

Oil and gas are essential sources of energy in the modern world. They are found

in subsurface reservoirs in many challenging environments. Modern reservoir man-

agement relies on asset management teams composed of people from a variety of

scientific and engineering backgrounds to produce oil and gas. The purpose of this

book is to introduce people with diverse technical backgrounds to reservoir manage-

ment. The book is a reference to topics that are often encountered by members of

multidisciplinary reservoir asset management teams and professionals with an inter-

est in managing subsurface resources. These topics are encountered in many

applications, including oil and gas production, coalbed methane production, uncon-

ventional hydrocarbon production, geothermal energy production, and greenhouse

gas sequestration. This chapter presents an overview of reservoir management.

1.1 Life Cycle of a Reservoir

The analysis of the costs associated with the development of an energy source

should take into account the initial capital expenditures and annual operating

expenses for the life of the system. This analysis is life cycle analysis, and the costs

are life cycle costs. Life cycle costing requires the analysis of all direct and indirect

costs associated with the system for the entire expected life of the system. In the

case of a reservoir, the life cycle begins when the field becomes an exploration

prospect, and it does not end until the field is properly abandoned.

The first well in the field is the discovery well. Reservoir boundaries are established

by seismic surveys and delineation wells. Delineation wells are originally drilled to

define the size of the reservoir, but they can also be used for production or injection

later in the life of the reservoir. The production life of the reservoir begins when fluid

is withdrawn from the reservoir. Production can begin immediately after the discovery

well is drilled or years later after several delineation wells have been drilled. The

number of wells used to develop the field, the location of the wells, and their flow

characteristics are among the many issues that must be addressed by reservoir

management.

1.1.1 History of Drilling Methods

The first method of drilling for oil in the modern era was introduced by Edwin

Drake in the 1850s and is known as cable-tool drilling. In this method, a rope

connected to a wood beam had a drill bit attached to the end. The beam was raised

Integrated Reservoir Asset Management. DOI: 10.1016/B978-0-12-382088-4.00001-3

Copyright # 2010 Elsevier Inc. All rights reserved.

and lowered, which lifted and dropped the bit and dug a hole into the ground. Cable-

tool drilling does not work in soft-rock formations, where the sides of the hole might

collapse. Cable-tool drilling has been largely replaced by rotary drilling.

Developed in France in the 1860s, rotary drilling was first used in the United

States in the 1880s because it could drill into the soft-rock formations of the

Corsicana oil field in Texas. Rotary drilling uses a rotating drill bit with nozzles

for shooting out drilling mud to penetrate into the earth. Drilling mud is designed

to carry rock cuttings away from the bit and lift them up the wellbore to the surface.

Rotary drilling gained great popularity after Captain Anthony F. Lucas drilled the

Lucas 1 well at Spindletop, near Beaumont, Texas. The Lucas 1 well was a discov-

ery well and a “gusher.” Gas and oil flowed up the well and engulfed the drilling

derrick. Instead of flowing at the expected 50 barrels of oil per day, the well pro-

duced up to 75,000 barrels per day. The Lucas gusher began the Texas oil boom

(Yergin, 1992, pp. 83–85). Since then, rotary drilling has become the primary means

of drilling.

Once a hole has been drilled, it is necessary to “complete” the well. A well is

completed when it is prepared for production. The first well of the modern era

was completed in 1808 when two American brothers, David and Joseph Ruffner,

used wooden casings to prevent low-concentration saltwater from diluting the

high-concentration saltwater they were extracting from deeper in their saltwater well

(Van Dyke, 1997).

It is sometimes necessary to provide energy to extract oil from reservoirs.

Oil can be lifted using pumps or by injecting gas into the wellstream to increase

the buoyancy of the gas-oil mixture. The earliest pumps used the same wooden

beams that were used for cable-tool drilling. Oil companies developed central

pumping power in the 1880s. Central pumping power used a prime mover—a power

source—to pump several wells. In the 1920s, demand for the replacement of on-site

rigs led to the use of a beam pumping system for pumping wells. A beam pumping

system is a self-contained unit that is mounted at the surface of each well and

operates a pump in the hole. More modern techniques include gas-lift and electric

submersible pumps.

1.1.2 Modern Drilling Methods

Advances in drilling technology are extending the options available for prudently

managing subsurface reservoirs and producing fossil fuels, especially oil and gas.

Modern drilling methods include horizontal wells, multilateral wells, and infill

drilling.

A well is a string of connected, concentric pipes. The path followed by the string

of pipes is called the trajectory of the well. Historically, wells were drilled vertically

into the ground, and the well trajectory was essentially a straight, vertical line.

Today, wells can be drilled so that the well trajectory is curved. A curved wellbore

trajectory is possible because the length of each straight pipe that makes up the well

is small compared to the total well length. The length of a typical section of pipe in

2 Integrated Reservoir Asset Management

a well is 30 to 40 feet. Wells with one or more horizontal trajectories are shown

in Figure 1.1.

A well can begin as a vertical well and then later be modified to a horizontal or

multilateral well. The vertical section of the well is called the main (mother) bore or

trunk. The point where the main bore and a lateral meet is called a junction. When

the vertical segment of the well reaches a specified depth called the kick-off point

(KOP), mechanical wedges (whipstocks) or other downhole tools are used to change

the direction of the drill bit and alter the well path. The beginning of the horizontal

segment is the heel, and the end of the horizontal segment is the toe. The distance,

or reach, of a well from the drilling rig to final bottomhole location can exceed

six miles. Wells with unusually long reach are called extended reach wells.

Wells with more than one hole can be drilled. Each hole is called a lateral or

branch, and the well itself is called a multilateral well. For example, a bilateral well

is a well with two branches. Figure 1.1 shows examples of modern multilateral well

trajectories.

Multilateral wells make it possible to connect multiple well paths to a common

wellbore, and they have many applications. For example, multilateral wells are used

in offshore environments where the number of well slots is limited by the amount of

space available on a platform. They are also used to produce fluids from reservoirs

that have many compartments. A compartment in a reservoir is a volume that is

isolated from other parts of the reservoir by barriers to fluid flow such as sealing

faults.

Horizontal, extended reach, andmultilateral wellbores that follow subsurface form-

ations provide access to more parts of the reservoir from fewer well locations. This

provides a means of minimizing the environmental impact associated with drilling

and production facilities, either on land or at sea. Extended reach wells make it possi-

ble to extract petroleum from beneath environmentally or commercially sensitive

areas by drilling from locations outside of the environmentally sensitive areas.

Extended reach wells make it possible to produce offshore fields from onshore drilling

locations and reduce the environmental impact of drilling by reducing the number of

surface drilling locations.

Reservoir Formation Cross-Section

HorizontalWell

BilateralWell

MultilateralWell

Figure 1.1 Multilateral wells.

Introduction 3

Infill Drilling

Infill drilling is the process of increasing the number of wells in an area by drilling

wells in spaces between existing wells. The increase in well density, or number of

wells per unit area, can improve recovery efficiency by providing fluid extraction

points in parts of the reservoir that have not been produced. Changes to well patterns

and the increase in well density can alter flow patterns in displacement processes

and enable the displacement of in situ fluids by injected fluids. Infill drilling is

especially useful in heterogeneous reservoirs.

Geosteering

Geosteering is the technology that makes it possible to accurately steer the well to

its targeted location and is a prerequisite for successful extended reach drilling.

Microelectronics is used in the drilling assembly to provide information to drill

rig operators at the surface about the location of the drill bit as it bores a hole into

the earth. Operators can modify the trajectory of the well while it is being drilled

based on information from these measurement-while-drilling (MWD) systems.

Geosteering and extended reach drilling can reduce costs associated with the con-

struction of expensive, new offshore platforms by expanding the volume of the res-

ervoir that is directly accessible from a given drilling location. In some cases, wells

drilled from onshore drilling rigs can be used to produce coastal offshore fields that

are within the range of extended reach drilling.

1.1.3 Production Systems

A production system can be thought of as the collection of subsystems illustrated in

Figure 1.2. Fluids are taken from the reservoir using wells, which must be drilled

and completed. The performance of the well depends on the properties of the reser-

voir rock, the interaction between the rock and the fluids in the reservoir, and the

properties of the fluids in the reservoir. Reservoir fluids include the fluids originally

SurfaceFacilities

Well Drillingand

Completion

WellModel

}

ReservoirModel

Figure 1.2 A production system.


contained in the reservoir, as well as fluids that may be introduced as part of the res-

ervoir management program. Well performance also depends on the properties of

the well itself, such as its cross-section, length, trajectory, and type of completion.

The completion of the well establishes the connection between the well and the res-

ervoir. A completion can be as simple as an open-hole completion where fluids are

allowed to drain into the wellbore from consolidated reservoir rock, to completions

that require the use of tubing with holes punched through the walls of the tubing

using perforating guns.

Surface facilities are needed to drill, complete, and operate wells. Drilling rigs

may be moved from one location to another on trucks, ships, or offshore platforms;

or drilling rigs may be permanently installed at specified locations. The facilities

may be located in desert climates in the Middle East, stormy offshore environ-

ments in the North Sea, arctic climates in Alaska and Siberia, and deepwater

environments in the Gulf of Mexico and off the coast of West Africa.

Produced fluids must be recovered, processed, and transported to storage

facilities and eventually to the consumer. Processing can begin at the well site where

the produced wellstream is separated into oil, water, and gas phases. Further pro-

cessing at refineries separates the hydrocarbon fluid into marketable products, such

as gasoline and diesel fuel. Transportation of oil and gas may be by a variety

of means, including pipelines, tanker trucks, double-hulled tankers, and liquefied

natural gas transport ships.

1.2 Reservoir Management

Modern reservoir management is generally defined as a continuous process that

optimizes the interaction between data and decision making during the life

cycle of a field (Saleri, 2002). This definition covers the management of hydrocar-

bon reservoirs and other reservoir systems, including geothermal reservoirs and

reservoirs used for geological sequestration. Geological sequestration is the long-

term storage of greenhouse gases, such as carbon dioxide, in geological formations.

The reservoir management plan should be flexible enough to accommodate techno-

logical advances, changes in economic and environmental factors, and new informa-

tion obtained during the life of the reservoir, and it should be able to address all

relevant operating issues, including governmental regulations.

Many disciplines contribute to the reservoir management process. In the case of a

hydrocarbon reservoir, successful reservoir management requires understanding the

structure of the reservoir, the distribution of fluids within the reservoir, drilling and

maintaining wells that can produce fluids from the reservoir, transport and processing

of produced fluids, refining and marketing the fluids, safely abandoning the reservoir

when it can no longer produce, and mitigating the environmental impact of operations

throughout the life cycle of the reservoir. Properly constituted asset management

teams include personnel with the expertise needed to accomplish all of these

tasks. These people are often specialists in their disciplines. They must be able to

communicate with one another and work together toward a common objective.

Introduction 5

Reservoir management studies are important when significant choices must be

made. The choices can range from “business as usual” to major changes in invest-

ment strategy. For example, decision makers may have to choose between investing

in a new project or investing in an existing project that requires changes in oper-

ations to maximize return on investment. By studying a range of scenarios, decision

makers will have information that can help them decide how to commit limited

resources to activities that can achieve management objectives.

Reservoir flow modeling is the most sophisticated methodology available for

generating production profiles. A production profile presents fluid production as a

function of time. Fluid production can be expressed as flow rates or cumulative pro-

duction. By combining production profiles with hydrocarbon price forecasts, it is

possible to create cash flow projections. The combination of production profile from

flow modeling and price forecast from economic modeling yields economic fore-

casts that can be used to compare the economic value of competing reservoir man-

agement concepts. This is essential information for the management of a reservoir,

and it can be used to determine reservoir reserves. The definition of reserves is

summarized in Table 1.1 (SPE-PRMS, 2007).

The probability distribution associated with the SPE-PRMS reserves definitions

can be illustrated using a normal distribution. We assume that several statistically

independent models of the reservoir have been developed and used to estimate

reserves. In the absence of data to the contrary, a reasonable first approximation

is that each model has been sampled from a normal distribution of reserves. Given

this assumption, an average m and standard derivation s may be calculated to

Table 1.1 SPE/WPC Reserves Definitions

Proved Reserves l Those quantities of petroleum, which by analysis of geoscience and

engineering data, can be estimated with reasonable certainty to be

commercially recoverable, from a given date forward, from known

reservoirs and under defined economic conditions, operating meth-

ods, and government regulations.l There should be at least a 90 percent probability (P90) that the quan-

tities actually recovered will equal or exceed the estimate.

Probable Reserves l Those additional reserves that analysis of geoscience and engineer-

ing data indicate are less likely to be recovered than proved reserves

but more certain to be recovered than possible reserves.l There should be at least a 50 percent probability (P50) that the quan-


Possible Reserves l Those additional reserves that analysis of geoscience and engineer-

ing data suggest are less likely to be recoverable than probable

reserves.l There should be at least a 10 percent probability (P10) that the quan-



prepare a normal distribution of reserves. For a normal distribution with mean m and

standard deviation s, the SPE-PRMS reserves definitions are

Proved reserves ¼ P90 ¼ m� 1:28sProbable reserves¼ P50 ¼ mPossible reserves ¼ P10 ¼ mþ 1:28s

ð1:2:1Þ

Figure 1.3 shows a normal distribution for a mean of 189 MMSTBO and a stan-

dard deviation of 78 MMSTBO. The SPE-PRMS reserves from this distribution are

Proved reserves ¼ P90 ¼ 88MMSTBO

Probable reserves¼ P50 ¼ 189MMSTBO

Possible reserves ¼ P10 ¼ 289MMSTBO

ð1:2:2Þ

In this case, the normal distribution is used to associate an estimate of the likelihood

of occurrence of any particular prediction case with its corresponding economic fore-

cast. For example, we use Figure 1.3 to see that a reserves estimate of 200 MMSTBO

corresponds to a probability of approximately P43.

1.3 Recovery Efficiency

One of the objectives of reservoir management is to develop a plan for maximizing

recovery efficiency. Recovery efficiency is a measure of the amount of resource

recovered relative to the amount of resource originally in place. It is defined by

comparing initial and final in situ fluid volumes. An estimate of expected recovery

0

1.00

0.90

0.80

0.70

0.60

0.50

0.40

0.30

0.20

0.10

0.00100.0 200.0

Reserves (MMSTBO)

Pro

babi

lity

of A

ttain

ing

Res

erve

s

300.0 400.0

Probability

Figure 1.3 The production system.

Introduction 7

efficiency can be obtained by considering the factors that contribute to the recovery

of a subsurface fluid.

Recovery efficiency is the product of displacement efficiency and volumetric

sweep efficiency. Displacement efficiency ED is a measure of the amount of fluid

in the system that can be mobilized. Volumetric sweep efficiency EVol expresses

the efficiency of fluid recovery in terms of areal sweep efficiency and vertical sweep

efficiency:

EVol ¼ EA � EV ð1:3:1Þ

Areal sweep efficiency EA and vertical sweep efficiency EV measure the degree of

contact between in situ and injected fluids. Areal sweep efficiency is defined as

EA ¼ swept area

total areað1:3:2Þ

and vertical sweep efficiency is defined as

EV ¼ swept net thickness

total net thicknessð1:3:3Þ

Recovery efficiency RE is the product of these efficiencies:

RE ¼ ED � EVol ¼ ED � EA � EV ð1:3:4Þ

Each of the recovery efficiencies is a fraction that varies from 0 to 1. If one or

more of the factors that enter into the calculation of recovery efficiency is small,

recovery efficiency will be small. On the other hand, each of the factors can be rel-

atively large, and the recovery efficiency will still be small because it is a product of

factors that are less than one. In many cases, technology is available for improving

recovery efficiency, but it may not be implemented because it is not economic. The

application of technology and the ultimate recovery of fossil fuels depend on the

economic value of the resource.

1.4 Reservoir Management and Economics

The definition of reservoir management presented previously recognizes the need to

consider the economics of resource development. The economic value of a project is

influenced by many factors, some of which can be measured. An economic measure

that is typically used to evaluate cash flow associated with reservoir management

options is net present value (NPV). The cash flow of an option is the net cash gen-

erated or expended on the option as a function of time. The time value of money is

included in economic analyses by applying a discount rate to adjust the value of

money to the value during a base year. Discount rate is the adjustment factor, and


the resulting cash flow is called the discounted cash flow. The NPV of the cash flow

is the value of the cash flow at a specified discount rate. The discount rate at which

NPV is zero is called the discounted cash flow return on investment (DCFROI) or

internal rate of return (IRR).

Figure 1.4 shows a typical plot of NPV as a function of time. The early time part

of the figure shows a negative NPV and indicates that the project is operating at a

loss. The loss is usually associated with initial capital investments and operating

expenses that are incurred before the project begins to generate revenue. The reduc-

tion in loss and eventual growth in positive NPV is due to the generation of revenue

in excess of expenses. The point in time on the graph where the NPV is zero after

the project has begun is the discounted payout time. Discounted payout time in Fig-

ure 1.4 is approximately four years.

Table 1.2 presents the definitions of several commonly used economic measures.

DCFROI and discounted payout time are measures of the economic viability of a

Cash Flow

−4.00

−2.00

0.00

2.00

4.00

6.00

8.00

10.00

12.00

14.00

16.00

0 1 2 3 4 5 6 7 8 9 10

Time (years)

NP

V (

$ m

illio

ns)

Base Case

Figure 1.4 Typical cash flow.

Table 1.2 Definitions of Selected Economic Measures

Economic Measure Definition

Discount Rate Factor to adjust the value of money to a base year

Net Present Value (NPV) Value of cash flow at a specified discount rate

DCFROI or IRR Discount rate at which NPV ¼ 0

Discounted Payout Time Time when NPV ¼ 0

Profit-to-Investment (PI)

Ratio

Undiscounted cash flow without capital investment divided by

total investment

Introduction 9

project. Another measure is the profit-to-investment (PI) ratio, which is a measure of

profitability. It is defined as the total undiscounted cash flow without capital invest-

ment divided by total investment. Unlike the DCFROI, the PI ratio does not take

into account the time value of money. Useful plots include a plot of NPV versus

time and a plot of NPV versus discount rate.

The preceding ideas are quantified as follows. NPV is the difference between the

present value of revenue R and the present value of expenses E; thus,

NPV ¼ R� E ð1:4:1Þ

If we define DE(k) as the expenses incurred during a time period k, then E may be

written as

E ¼XN�Q

k¼0

DEðkÞ1þ i0

Q

� �kð1:4:2Þ

where i0 is the annual inflation rate, N is the number of years of the expenditure

schedule, and Q is the number of times interest is compounded each year. A similar

expression is written for revenue R:

R ¼XN�Q

k¼0

DR kð Þ1þ i

Q

� �kð1:4:3Þ

where DR(k) is the revenue obtained during time period k, and i is the annual inter-

est or discount rate. Equations (1.4.2) and (1.4.3) include the assumptions that i andi0 are constants over the life of the project, but i and i0 are not necessarily equal.

These assumptions let us compute the present value of money expended relative

to a given inflation rate i0 and compare the result to the present value of revenue

associated with a specified interest or discount rate i.Net present value takes into account the time value of money. NPV for an oil

and/or gas reservoir may be calculated for a specific discount rate using the

equation

NPV ¼XN

n¼1

PonQon þ PgnQgn � CAPEXn � OPEXn � TAXn

1þ rð Þn ð1:4:4Þ

where

N ¼ Number of years

Pon ¼ Oil price during year nQon ¼ Oil production during year nPgn ¼ Gas price during year nQgn ¼ Gas production during year n


CAPEXn ¼ Capital expenses during year nOPEXn ¼ Operating expenses during year nTAXn ¼ Taxes during year n

r ¼ Discount rate

In many cases, resource managers have little influence on taxes and prices.

On the other hand, most resource managers can exert considerable influence on

production performance and expenses. Several strategies may be used to affect

NPV. Some strategies include accelerating production, increasing recovery, and lower-

ing operating costs. One reservoir management challenge is to optimize economic

measures like NPV.

Revenue stream forecasts are used to prepare both short- and long-term budgets.

They provide the production volumes needed in the NPV calculation. For this rea-

son, the asset management team may be expected to generate flow predictions using

a combination of reservoir parameters that yield a range of recoveries. Uncertainty

analysis is a useful process for determining the likelihood that any one set of

parameters will be realized and estimating the probability distribution of reserves.

Reservoir management must consider how much money will be available to pay

for wells, compressors, pipelines, platforms, processing facilities, and any other

items that are needed to implement the plan represented by the model. The revenue

stream is used to pay taxes, capital expenses, and operating expenses. The economic

performance of the project depends on the relationship between revenue and

expenses. Several economic criteria may be considered in the evaluation of a proj-

ect, such as NPV, internal rate of return, and profit-to-investment ratio. The selec-

tion of economic criteria is typically a management function. Once the criteria are

defined, they can be applied to a range of possible operating strategies. The

strategies should include assessment of both tangible and intangible factors. A com-

parative analysis of different operating strategies gives decision-making bodies

valuable information for making informed decisions.

1.5 Reservoir Management and the Environment

The impact of a project on the environment must be considered when developing a

reservoir management strategy. Environmental studies should consider such topics

as pollution evaluation and prevention, and habitat preservation in both onshore and

offshore environments. An environmental impact analysis provides a baseline on

existing environmental conditions and provides an estimate of the impact of future

operations on the environment. Forecasts of environmental impact typically require

risk assessment, with the goal of identifying an acceptable risk for implementing a

project (Wilson and Frederick, 1999). Computer flowmodels are often used to prepare

forecasts as well as guide remedial work to reclaim the environment.

A well-managed field should be compatible with both the surface and subsurface

environment. Failure to adequately consider environmental issues can lead to tangi-

ble and intangible losses. Tangible losses have more readily quantifiable economic

Introduction 11

consequences. For example, if potable water is contaminated, the cost to remediate

can adversely affect project economics. Intangible losses are more difficult to quan-

tify, but they can include loss of public support for an economically attractive proj-

ect. For example, the poor public image of the oil industry in the United States has

contributed to political opposition to oil industry development of land regulated

by the federal government. In some cases, the intangible loss can take the form

of active opposition to an otherwise economically viable project. In many parts of

the world, it is necessary to provide an environmental impact statement as part

of the reservoir management plan.

Environmental issues must always be considered in the development of a reser-

voir management strategy. For example, the Louisiana Offshore Oil Production

(LOOP) facility is designed to keep the transfer of hydrocarbons between pipelines

and tankers away from sensitive coastal areas. Periodic water sampling of surface

and produced waters can ensure that freshwater sources are not contaminated. In

addition, periodic testing for the excavation or production of naturally occurring

radioactive materials helps ensure environmental compliance.

The advantages of operating a field with prudent consideration of environmental

issues can pay economic dividends. In addition to improved public relations, sensi-

tivity to environmental issues can minimize adverse environmental effects that may

require costly remediation and financial penalties. Remediation often takes the form

of cleanup, such as the cleanup required after the oil spill from the Exxon Valdezoil tanker in Alaska. Technologies are being developed to improve our ability to

clean up environmental pollutants. For example, bioremediation uses living

microorganisms or their enzymes to accelerate the rate of degradation of environ-

mental pollutants (Westlake, 1999).

It becomes a question of business ethics whether a practice that is legal but can

lead to an adverse environmental consequence should nonetheless be pursued

because a cost-benefit analysis showed that economic benefits exceeded economic

liabilities. Typically, arguments to pursue an environmentally undesirable practice

based on cost-benefit analyses do not adequately account for intangible costs. For

example, the decision by Shell to dispose of the Brent Spar platform by sinking it

in the Atlantic Ocean led to public outrage in Europe in 1995. Reversing the deci-

sion and disassembling the platform for use as a quay in Norway resolved

the resulting public relations problem, but the damage had been done. The failure

to anticipate the public’s reaction reinforced a lack of public confidence in the

oil and gas industry, and it helped motivate government action to regulate the

decommissioning of offshore platforms in northwestern Europe (Wilkinson, 1997;

Offshore Staff, 1998).

1.5.1 Sustainable Development

The concept of sustainable development was introduced in 1987 in a report prepared

by the United Nations’ World Commission on Environment and Development

(Brundtland, 1987). The commission, known as the Brundtland Commission, after

chairwoman Gro Harlem Brundtland of Norway, said that societies should adopt a


policy of sustainable development that allows them to meet their present needs

while preserving the ability of future generations to meet their own needs. The three

components of sustainable development are economic prosperity, social equity, and

environmental protection.

Sustainable development is intended to preserve the rights of future generations.

It is possible to argue that future generations have no legal rights to current natural

resources and are not entitled to any. From this perspective, each generation must do

the best it can with available resources. On the other hand, many societies are

choosing to adopt the value of preserving natural resources for future generations.

National parks are examples of natural resources that are being preserved.

1.5.2 Global Climate Change

One environmental concern that is facing society currently is global climate change.

Measurements of ambient air temperature show a global warming effect that corre-

sponds to an increase in the average temperature of the earth’s atmosphere. The

increase in atmospheric temperature has been linked to the combustion of fossil

fuels (Wigley et al., 1996).

When a carbon-based fuel burns, carbon can react with oxygen and nitrogen in

the atmosphere to produce carbon dioxide (CO2), carbon monoxide, and nitrogen

oxides (often abbreviated as NOx). The combustion by-products, including water

vapor, are emitted into the atmosphere in gaseous form. Some of the gaseous

byproducts are called greenhouse gases because they contribute to the greenhouse

effect, illustrated in Figure 1.5 (Fanchi, 2004). Some of the incident solar radiation

from the Sun is absorbed by the earth, some is reflected into space, and some is

captured by greenhouse gases in the atmosphere and reradiated as infrared radia-

tion (heat). The reradiated energy would escape the earth as reflected sunlight if

Atmosphere

IncidentSolar

Radiation

Reflected

“Greenhouse”Gas Absorbs and

Reemits IR

InfraredRadiation

Earth’sSurface

Sun

Figure 1.5 The greenhouse effect.

Introduction 13

greenhouse gases were not present in the atmosphere. Greenhouse gases include car-

bon dioxide, methane, and nitrous oxide, as well as other gases such as volatile

organic compounds and hydrofluorocarbons.

Carbon dioxide (CO2) is approximately 83 percent of the greenhouse gases emit-

ted by the United States as a percent of the mass of carbon or carbon equivalent.

Wigley and colleagues (1996) projected ambient CO2 concentration through the

twenty-first century. Pre-industrial atmospheric CO2 concentration was approxi-

mately 288 parts per million, and the current atmospheric CO2 concentration is

340 parts per million. The concentration of CO2 that would establish an accept-

able energy balance is considered to be 550 parts per million. To achieve the

acceptable concentration of CO2 through the next century, societies would have to

reduce the volume of greenhouse gases entering the atmosphere.

Many scientists attribute global climate change to the greenhouse effect. The

Kyoto Protocol is an international treaty that was negotiated in Kyoto, Japan, in

1997 to establish limits on the amount of greenhouse gases a country can emit into

the atmosphere. The Kyoto Protocol has not been accepted worldwide. Some

countries believe the greenhouse gas emission limits are too low and would

adversely impact national and world economies without solving the problem of

global warming. Another criticism of the Kyoto Protocol is that it does not apply

to all nations. For example, China is exempt from greenhouse gas emission

limitations in the Kyoto Protocol even though it has one of the world’s fastest-

growing economies and the world’s largest population.

Concern about global climate change has motivated a change in the definition of

pollution. For example, it used to be an acceptable practice to release natural gas

into the atmosphere by flaring the gas. This practice is now prohibited in many parts

of the world as an undesirable practice because natural gas is a greenhouse gas. One

proposed method for reducing the climatic greenhouse effect is to collect and store

carbon dioxide in geologic formations as part of a process known as CO2 sequestra-

tion. The sequestration of CO2 in subsurface formations is a gas storage process that

must satisfy the three primary objectives in designing and operating natural gas stor-

age reservoirs: verification of injected gas volume, monitoring of injected gas

migration, and determination of gas injectivity. The goal of geologic carbon seques-

tration and similar programs is to provide economically competitive and environ-

mentally safe options to offset all of the projected growth in baseline emissions of

greenhouse gases.

CS.1 Valley Fill Case Study: Introduction

The primary purpose of the Valley Fill case study from a pedagogical perspective is to showhow to apply reservoir management concepts using a realistic example. The incised valleymodel is useful for describing reservoirs in both mature and frontier basins around theworld (e.g., Bowen et al., 1993; Peijs-van Hilten et al., 1998). Each chapter presents infor-mation that is integrated into the reservoir management example. The reservoir of interestis an oil reservoir that has been producing for a year. Wells in the field are shown inFigure CS.1A.


Exercises

1-1. List several questions you would want to have answered if you were trying to decide

how to manage the Valley Fill reservoir.

1-2. Suppose displacement efficiency is 27 percent, areal sweep efficiency is 60 percent, and

vertical sweep efficiency is 75 percent. Estimate recovery efficiency.

1-3. We want to drill a 5,000-foot-deep vertical well. We know from previous experience in the

area that the drill bit will be effective for 36 hours before it has to be replaced. The average

drill bit will penetrate 20 feet of rock in the area for each hour of drilling. Again, based on

previous experience, we expect the average trip to replace the drill bit to take about 8 hours.

A “trip” is the act of withdrawing the drill pipe, replacing the drill bit, and then returning the

new drill bit to the bottom of the hole. Given this information, estimate how long it will take

to drill the 5,000-foot-deep vertical well. Hint: Prepare a table like the following.

Incremental Time

(hrs)

Incremental

Depth (ft)

Cumulative Time

(hrs)

Cumulative

Depth (ft)

1-4. Complete the following table and estimate the proved, the probable, and the possible

reserves. Assume the reserves are normally distributed.Hint:Reserves¼OOIP�Recovery

Factor.

Model OOIP (MMSTB) Recovery Factor Reserves (MMSTB)

1 700 0.42

2 650 0.39

3 900 0.45

4 450 0.25

5 725 0.43

¤

● 8 ¤

●

●

2 10

1

Protective well Dry hole

● ¤ ●¤ 4 11 6 ¤

7 ● 12

3 ¤

¤

●9 5

Figure CS.1A Well locations in an area that is 6,000 feet long by 3,000 feet wide.

Introduction 15

1-5. Any reader interested in participating in the Valley Fill case study should complete Exer-

cises 1-5 through 1-8.

A three-dimensional, three-phase reservoir simulator (IFLO) is included with this

book. Prepare a folder on your hard drive for running IFLO using the following

procedure.l Make a directory on your computer called RMSE/VALLEY.l Go to the website http://www.bh.com/companions/0750675225 and copy the zip file

to RMSE/VALLEY.l Extract all of the files to RMSE/VALLEY.l Some of the files may be labeled “Read Only” when you copy the files to RMSE/

VALLEY. To remove this restriction, select the file(s) and change the properties

of the file(s) by removing the check symbol adjacent to the “Read Only” attribute.

What is the size of the executable file IFLO.EXE in megabytes (MB)?

1-6. Several example data files are provided with IFLO. Make a list of the data files (files

with the extension “DAT”). Unless stated otherwise, all exercises assume that IFLO

and its data files reside in the RMSE/VALLEY directory.

1-7. The program IFLO runs the file called “ITEMP.DAT”. To run a new data file, such as

NEWDATA.DAT, copy NEWDATA.DAT to ITEMP.DAT. In this exercise, copy

VFILL1_HM.DAT to ITEMP.DAT, and run IFLO by double clicking on the IFLO.

EXE file on your hard drive. Select option “Y” to write the run output to files. When

the program ends, it will print “STOP”. Close the IFLO window. You do not need to

save any changes. Open run output file ITEMP.ROF, and find the line reading “MAX

# OF AUTHORIZED GRID BLOCKS”. How many grid blocks are you authorized to

use with the simulator provided with this book?

1-8. The program 3DVIEW may be used to view the reservoir structure associated with IFLO

data files. 3DVIEW is a visualization program that reads IFLO output files with the

extension “ARR”. To view a reservoir structure, proceed as follows:l Use your file manager to open your folder containing the IFLO files. Unless stated

otherwise, all mouse clicks use the left mouse button.

a. Start 3DVIEW (double click on the application entitled 3DVIEW.EXE).

b. Click on the button “File”.

c. Click on “Open Array File”.

d. Click on “ITEMP.ARR” in the file list.

e. Click on “OK”.l At this point you should see a structure in the middle of the screen. The structure is

an oil-filled channel sand. To see the channel, use the left mouse button to select

Model/Select Active Attribute/SO. This displays oil saturation in the channel.l To view different perspectives of the structure, hold the left mouse button down and

move the mouse. With practice, you can learn to control the orientation of the struc-

ture on the screen.l The grid block display may be able to be smoothed by selecting Project/Smooth

Model Display.

To exit 3DVIEW, click on the “File” button and then click “Exit”.


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