Reserve Evaluation for Enhance Oil Recovery Purposes

Using Dynamic Reserve Evaluation Model (DREM)

Robert Amin1 and Chawarwan Hussen2 1, 2 Curtin University of Technology,

Woodside Research Facility, GPO Box U 1987

Perth West Australia 6845

Abstract

The challenge for hydrocarbon reserve evaluation is the estimation of current and future recoverable reserves as well as considerations of technical and commercial prospects in the reserves valuation and management processes. In terms of reserve evaluation, there are several estimation methods that have been proposed to determine the quantities of oil initially in place (OIIP) and estimate the operating conditions required for production based on a reliance of the reservoirs natural potential. Unfortunately these approaches do not deal with the Enhance Oil Recovery process which will add additional recoverable energy to the reservoir.

The objective of this paper is to re-classify reserves and resources that are subject to Enhance Oil Recovery and Improved Oil Recovery in terms of recoverable, commercial or potential reserves from known accumulation or from an undiscovered reservoir. This re-classification process would add them again into the categorizations of proven reserves, such as proven producible reserves, or proven un-producible reserves.

This paper will also illustrate the economical considerations for making decisions on whether the reserves and resources should be re-classified or wait for the development of market viability, technology advances, or removal of other constraints to the development, such as technical, environmental and political. For these circumstance, the concept of enhance oil recovery will be function of economic analysis from forecasting economic conditions, reserve management and the reporting of reserves. Moreover, a comprehensive reference of enhance oil recovery based on a dynamic reserve evaluation model will identify and characterize current potential and future recoverability of reserves to be classified as reserve classifications.

Introduction

It is not adequate to simply deploy data and applications to create a digital oilfield and evaluate its reserves. To create a true representing data oilfield and realize the next step, that of production, information and software means need to be integrated with core exploration and production operational processes to enhance the value across the entire chain.

Over the last 250 years of industrial economic history, it is a generally-accepted proposition that innovation is the principal engine of the economic development and a primary means of wealth creation of company or country. More recently it is also generally accepted that a knowledge-based economy will continue to be the prevailing mode in the current century. Hence, the production, distribution and use of knowledge in various forms account for a major portion of the oil enhance recovery and the gross productivity of a country. Industries economic strength no longer depends as heavily as before on low-cost labor, or/and cheap raw materials, but on a continually operating innovation system.

As is the case for all enhanced oil recovery processes, during primary production of crude oil, the natural reservoir pressure is reduced. Secondary oil production results from the injection into the reservoir of water or gas and this procedure sweeps oil towards the production wells. Once the water has reached the production wells, the water-to-oil ratio begins to increase until oil production is no longer economically viable. The oil in place at the start of the injection process is reflected by the product of porosity and initial oil saturation which is considered as a key economic parameter as it has a direct impact on the incremental and cumulative injected air/produced oil ratios. At this point, as much as two thirds of the original oil-in-place may remain in the reservoir rock pores, and it is this residual oil which is the target of all tertiary or enhanced oil recovery (EOR) methods.

Several methods of Enhanced Oil Recovery are based on the idea of sweep efficiency increase by plugging the swept highly permeable areas with high viscosity fluid or with adsorbed chemical such as thermal, chemical, miscible, and microbial methods. The estimation of primary oil reserves is the evaluations of the properties are subject to production motivation techniques. The current standardized methods in reserve estimation such as volumetric method, decline curve analysis, material balance equation, analogy method and so on, do not add new energy, but estimate possibility of operating condition to cause production to occur by relaying on natural reservoir energy. On the other hand, enhance oil recovery offers considerable potential benefit of reserves to squeeze out extra barrels due to reduce the viscosity of oil to easy flow or to push oil out of the pores of the rock. Enhance oil recovery also is a development stage of those reserves that can be anticipated to be potentially recoverable from discovered or/and undiscovered accumulation or those reserves are already being produced, for the reason of reclassify those reserves to be added again to the categories of proven reserves as proven producible reserves or proven un-producible reserves. For these circumstances, enhance oil recovery technique is considered as a function of any economic analysis through forecasting economic conditions, reserve management and reporting. The motivation of eventual production sooner rather than later could have important economic benefits and can result in additional reserve being recognized where economic conditions alone would suggest that the reserve should be abandoned or not.

Enhance Oil Recovery

Resources define as recoverable quantity of OIIP potentially or commercially associated with proved reserves such as nonconventional or conventional proved reserves of crude oil discovered. According to nonconventional resources, the accumulated OIIP of oil sand might classify as proven reserves regarding the percentage of recovery factor established from current and future known discovery of the reservoir. While for oil shales, they are quantified in different place, and most of them would be classified as contingent or prospective resources because they are not yet considered to be commercially recoverable.

Physically, it is impossible to recover and produce the entire accumulated oil initial in place, but the industry is leaving behind as much as portion of oil will discover in fields and the fields will be abandoned for whatever reason in the late stages of depletion. After abandonment stage, a long term goal of estimated portion oil discovered in the fields could be produced regarding to conventional oils and nonconventional extra-heavy oils. Thus, enhance oil recovery technique is the only alternative for this achievement.

The primary phase of oil production from a reservoir depends on its existing natural energy source which may be one of several. Solution gas drive can be extensive natural drive mechanism in the majority of reservoirs and can provide a recovery of OOIP. This primary process is normally used to increase the recovery at the early stage in the life of the reservoir by secondary recovery or improved oil recovery (IOR) processes can be consisting of stranded gas reinjection and water-flooding. Roughly one-third of the world's reservoirs have natural water drives.

When secondary recovery processes are implemented from the start of production-as is now standard practice with new oil fields-or later on during the primary phase, the process will refer to as "pressure maintenance." Although recovery rates of theoretically possible values will be very rare. Tertiary or EOR methods are applied at the end of the secondary phase. They can be thermal, miscible, or chemical processes that attempt to sweep out as much as possible of the remaining oil. The technique that almost present or existing in everywhere for flooding medium or light oil can be CO techniques.

The 30-year history of this technology in the US and other countries indicates that it is possible

to recover an additional portion after water-flooding based on review of EOR processes and their

limits in regard to oil viscosity, permeability, and depth of the reservoirs. Moreover, not all EOR

techniques are applicable to all reservoirs and oil types. As a result considerable numbers of

reservoirs, especially in medium and small fields that account for 50% of world production, have

been left without the application of secondary recovery processes.

Re-classifying the Oil Reserve Base and Estimating Uncertainty

Within a broad context, the applicability of the assortment of EOR technologies depends on two factors: the API gravity of the oils and the depth of the reservoirs. In reality, the good technical selection parameters are the oil viscosity and the reservoir pressure. These, however, are related empirically to oil gravity and reservoir depth, respectively. World oil reserves were sorted by API gravity and depth. The gravity classifications are: light (> 35 ◦API), medium (26-35 ◦API), heavy (10+ - < 26 ◦API) and extra heavy (≤ 10 ◦API). The greater level for heavy and medium gravity oils can be changed slightly from the official definitions to better reflect limits of successful field EOR projects. The same is true for the depth classifications selected: shallow (< 3,500 feet), intermediate (3,500-10,000 feet) and deep (>10,000 feet). Fig. 1 illustrates the gravity distribution of the world’s total oil resources of 12.8 Tbo. Light and medium gravity oils make up two-thirds of the total resources while heavy and extra heavy oils make up the other third. Fig. 2 shows the depth distribution of the oil resources. Roughly one-third of the total resources are located at shallow depths which as expected matches the volumes of heavy and extra heavy oils. A similar correspondence is observed between medium gravity oils (44%) and reservoirs at intermediate depths (45%), also between light oils (22%) and deep reservoirs (21%). In term of reserves and uncertainty, reserves are those quantities of petroleum which are anticipated to be commercially recovered from known accumulations from a given date forward. In general, the definitions of the three major sub classification for recoverable quantities of petroleum such as reserves, contingent and prospective resources are clarified according to the maturity of project as defined in the context of Guidelines of the Evaluation of Petroleum Reserves and Resources SPE/WPC/AAPG.

Reserves must satisfy four criteria:

• discovered

• recoverable

• commercial

• remaining (as of the evaluation date)

• based on the development project(s) applied In the glossary of used terms in evaluation resources different terms are used to determine acceptable and sensible range of uncertainty of recoverable quantities of hydrocarbon according to proven reserves refer to 1P for estimating quantities of proved reserves, 2P for proved plus probable and 3P for proved plus probable plus possible.

Figure 3: shows that, high degrees of certainty are related to proved reserves to be recovered commercially by using deterministic approaches while, the levels of certainty associated with probable reserves it will be less likely to be recoverable than proved plus probable reserves (2P) additionally, for possible reserves would be less likely than proved plus probable plus possible reserves (3P) to be recoverable. Moreover, it can be seen from figure 4, if probabilistic methods

are used at least 90% of proved reserves (1P), 50% of probable (2P) and 10% (3P) of possible reserves quantities should be recovered (Sircar et al. 2003).

Indeed, a true value of the quantities of hydrocarbon trapped in the ground is constant over a life time of the project but, the reason that make those quantities to be changed afterward belongs to the level of uncertainty that are associated to the accumulated volumes these uncertainties accordance to the maturity of the project can be defined to technical uncertainties while, in the case of economical uncertainty such as prices unquestionable because forecasting of future prices would not be reliable due to future circumstances are being unknown (Ross 2004).

The model definition and use (DREM):

The model provides two main defined criteria of reserves evaluation. Firstly, re-classify reserves as proven, probable and possible reserves. Therefore, the model will identify and characterize current potential and future recoverability volume of reserves to decide shall the reserves reclassify as proven reserve categories or waiting for development of market viability and technology advance or removal of other constraints to the development such as technical, environmental and political. Secondly, the model provides a comprehensive evaluation for estimating reserve volumes according to the reserve is already being reclassified by using dynamic reserve method (DR). However, there have been many recent changes in an attempt to achieve a Global Standard System in order to ensure the public release of accurate, understandable reserve definition and classification. While, this model (DREM) significantly relies on those global standard system of reserve evaluation and classification.

In the first step, the equations below will be used to reclassify reserve based on re-evaluation of

recovery factor (RF). According to this equation re-classification of reserves will be categorized

into three groups:

%% TRFIIRF =

NrCO RFRFIIRF −=2

%

%%% NrRFIIRFTRF +=

)]/()[( NrPaNrNr OIIPOIIPOIIPRF −=

)]/()[(22 NrCONrCO OIIPOIIPOIIPRF −=

1- If TRF% >= 90%, probability the estimated reserve is considered as proven reserve 2- 90 %> TRF% > 50 %, probability that estimated reserve is taken into account as

probable reserve. 3- 50% > TRF% > 10% for Possible reserve the estimated quantity will be recoverable

It will be interesting to notice that the estimated recoverable quantities of reserve and the OIIP for the field to distribute the percentage of recovery factor to be defined as a poor oilfield or/and as a good oilfield for the purpose of re-classify the reserves and add selected field-oils again into the categorization of reserves or/and resource classifications.

For example value of recovery factor:

IIRF> = 50% (Good reserve)

For this circumstance, the reserve will be associated with commercial accumulation that is sufficiently well defined to confirm commerciality.

20 % = < IIRF>50%

The reserve will be illustrated that it has connections with potential accumulation, but the reserve is less confidentially defined than the reserve with 50% RF

Poor Field IIRF< 20%

This sort of reserve requires further data acquisition and evaluation in order to reclassify as the previous reserve and therefore, to be recoverable commercially.

Probability of Reserve Success

A good estimative of risk must consider both sides, geological and commercial factors. The purpose of risk analysis in the exploration phase is to disclose those risky factors that involved in the search of confirmation of the occurrences of hydrocarbon initially in place (HIIP) prior to drilling of a mapped prospect. After that is commercial feasibility of pumping oil and gas out of the ground to the consuming market. In addition, the five main tasks are asked (1) finding the probability of geological risk of the reservoir; (2) estimating the cumulative (HIIP); (3) estimating what can be recoverable; (4) finding commercial profitability; (5) commercially developing and producing what has been found. In this paper these jobs will be taken into account. Over the entire the exploration phase, different classes of geologic reserves require different amounts of data acquired from seismic, drilling, logging, production tests and sampling analysis to reflect the phase of exploration, development and certainty of geological understanding to a specific reservoir.

The probability of reserve success assessment requires an evaluation of those geological factors that are critical to the discovery of recoverable quantities of hydrocarbons. The probability of discovery is a value that is based partly on objective knowledge and historical data, partly on extrapolations and partly on estimator’s subjective judgments of geological parameters.

Volumetric Technique in Reserve Evaluation This technique is used to estimate hydrocarbon initially in place from estimates of area, thickness, porosity, water saturation and hydrocarbon fluid properties. In addition, theoretical estimates for hydrocarbon recovery are then applied to estimate recoverable hydrocarbons. Therefore, it is utilized prior to sufficient production data to allow an accurate determination of reserves estimations.

a. Oil Initially in place (OIIP)

−=

)(

)1(

tB

SwVOIIP

o

b φ

• Area (A)

• Thickness (h)

• Average reservoir porosity, %

• Average water saturation (Swi)

• Oil formation volume factor (Boi) at initial reservoir pressure (Pi).

b. Oil Initially in place after CO2 injection at initial reservoir pressure ( wiOIIP ).

( )

Bo

SorVbOIIP CO

Φ=

2

• Area (A)

• Thickness (h)

• Average reservoir porosity, %

• Oil saturation after CO2 injection (Sor)%

• Oil formation volume factor (Bo)

c. Oil Initially in Place after volumetric depletion

Applying Dynamic Reserve Evaluation Model:

Different techniques have different applications at different times in the life of a field. For example, the initial stage of exploration may require volumetric estimates based upon analogue due to the lack of existing well information and estimating volumes with Monte Carlo Simulation. In addition, the current practice of the probability of reserve success evaluation at the prospect level involves substantial subjectivity correlation among the identified geological prospects.

TRFOIIPDREM ×=

OIIP : Oil initial in place

TRF : Total Recovery Factor

The Significance of Field Growth and the Role of Enhance Oil Recovery

Reserve growth has now become an important part of estimating total potential reserves of an individual region or country. The scientists are continuing their research for a deeper understanding of the reserve growth phenomenon by evaluating the impact of its various aspects. Some of these aspects include litho-logy, infrastructure, crude oil price, operating environments, government policies, and technology. As the world’s known petroleum reserves continue to decline, there will be more pressure on geologists and engineers in the oil industry to make the reserve estimates more precise through application of the reserve-growth concept. In fact, the concept could be applied even to the undiscovered resources with some qualifications as to the inherent risk. Although the factors (booking reserve and reporting reserve policies) impact reserve growth, the

quantification of their impact is difficult. Therefore, most studies have focused on evaluating the

reserve growth sensitivity to geologic and reservoir engineering parameters. Field growth is the

increase in total proved reserves of an existing field through given period of time.

Therefore, the factors that contribute to economic concept of reserve growth of fields can be

grouped into five categories that are not independent of each other:

1- Improved reserve calculation based on better knowledge of the fields. 2- Improvements in recovery percentage based on new drilling technology (multiple wells,

directed at targets several miles distant, and multiple laterals extending), or application of

enhanced oil recovery (EOR) processes and horizontal well technology. Of all the EOR

processes, thermal recovery and carbon dioxide injection are technically and

economically the most successful processes

3- Delineation of additional oil and gas in-place or discovery of new pools (or reservoirs) or extensions of known pools (or reservoirs) in the existing fields

4- Improvement in reservoir characterization 5- Development of more sophisticated and efficient reservoir simulators and data

processing capabilities. The term reserves, in field (or reserve) growth, refers to the total proved reserves or the estimated ultimate recovery (EUR), which is equal to the sum of remaining proved reserves and cumulative production at the time of reporting. In industry, reservoirs are periodically assessed for the remaining hydrocarbon reserves to optimize reservoir development strategies for better economic returns. These periodic assessments generally result in increased total proved reserves. Potential additions to hydrocarbon (oil and gas) reserves come from two sources, new discoveries and existing fields. During the early phases of development in a petroleum province, new discoveries are the dominant source of reserve additions. Estimation of growth rate of cumulative oil produced for the re-evaluated reserve. By using decline curve analysis, the volume of the re-evaluated reserve from DREM will be calculated for selected given period of the re-evaluated reserve life cycle till approaching from economic limit.

V(t0) : start Volume, STB

V(tn) : finish volume, STB

tn − t0 : number of years

Petroleum Reserve Bankability

In the second step, this method will be applied to evaluate the reclassified reserve economically as a purpose of estimating the return on the investment over given period of time as a function of re-evaluation of recoverable volume. The equations of this model are summarized by depending on the following factors such as, current price of oil reserves, development price of oil reserve, growth rate of cumulative oil produced. Therefore, petroleum reserve bankability consists of two equations which are illustrated below:

GRDpCpBPGR ×−= )(

GrBP : Booking price $ in term of growth rate

( )( )

1

1

−

=

−totn

toV

tnVGR

Cp : Current price $

Dp : Development price $

GR : Growth rate of cumulative oil produce for the reclassified reserve%.

While formula of booking price in term of money is written as;

GRmoney BPDpCpBP ×−= )(

moneyBP : Booking price in term of money

Cp : Current price $

Dp : Development price $

GRBP : Booking price in term of growth rate $

Conclusion

The work presented in this paper demonstrated that the use of Dynamic Reserve Evaluation Model for EOR offers the prospect of distinct and considerable economic benefits. In addition, there were two purposes first of all, was to reclassify reserves after enhance oil recovery and add the reserve back into the category by using (DREM). The second purpose was to estimate the return on the investment as a function of re-evaluation recoverable volume by relying on petroleum reserve bankability equation. Attempt has been made to estimate the development of technical and commercial prospects, largely because an essential component in the perfection of the new model is a clear understanding of where and how it is to be deployed. Without such information from the traditional methodologies, the model seems roughly useless to guess at the time and effort needed for any part of these developments unless specific reservoir and production problems are defined. Only then will it be possible to relate the perceived problems to existing knowledge and to take a view as to the work required to evaluate and reclassify reserves.

Total 12.8 Tboo Total 12.8 Tbo

Xheavy (≤ 10 API) Heavy (< 26 API ) Shallow (<3,500 feet) Medium (26 - 35 API) Light (>35 API) Deep (>10,000 feet) Intermediate (3,500 - 10,000 feet)

- Reserve defi

2.8 Tbo;

22% Light

5.6; 44%

Medium

1.4;

3.0; 23%

XHeavy

2.7 Tbo;

21% Deep

5.7; 45%

Intermediate

4.4; 43%

Shallow

Figure 2: World Oil Resources by Depth, trillion barrels 2006

Source: (Laherrere 1997)

Figure 1: World Oil Resources by API Gravity, trillion barrels 2006

Source: (Laherrere 1997)

Figure4: Probabilistic Method

Source: Petroleum Resource Management System 2007

Figure3: Deterministic Method

Source: Petroleum Resource Management System 2007

References Amarnath , A 1999, ‘Enhance oil recovery scoping study’, EPRI Project Management

Report. Retrieved January 20, 2009, fromwww.energy.ca.gov/process/pubs/electrotech_opps_tr113836.pdf Brown, M, Moses, V, Robinson, J & Springham, D 1985, ‘Microbial enhanced oil recovery: progress and prospect’, Base Becking Geobiological Research Laboratories Commonwealth

Scientific and Industrial Research Organization, vol. 3, issue. 2. Retrieved August 23, 2008, from www.informapharmascience.com/doi/ref/10.3109/07388558509150783.

Sandrea, I & Sndrea, R 2007, ‘ Global oil reserves – recovery factors leave vast target for EOR technologies’, Oil and Gas Journal. Retrieved April 16, 2008 from www.its.com.ve/publications/Global%20Oil_%20EOR%20Challenge.pdf Laherrere, J 1997, ‘ Distribution and evaluation of recovery factor’, paper presented at Oil

Reserves Conference in Paris November 11, 1997 by International Energy Agency. Retrieved May 29, 2008, from http://dieoff.org/page183.pdf

Verma, M 2000, The significance of field growth and the role of enhanced oil recovery: U.S. Geological Survey Fact Sheet FS-115-00, 4 p. Retrieved January 17, 2009, from http://pubs.usgs.gov/fs/fs-0115-00/

Schmoker, J.W., 2000, Reserve growth effects on estimates of oil and natural gas resources: U.S. Geological Survey Fact Sheet FS-119-00, 2 p. Retrieved March 18, 2009 http://pubs.usgs.gov/fs/fs119-00/ Verma, M 2007, ‘The reality of reserve growth’, USGS Science for a Changing World. Retrieved January 22, 2009, from http://www.geoexpro.com/sfiles/4/12/9/file/realityofreserve34_35.pdf