bluuebunny/crossref_metadata_2025 huggingface dataset:
Probabilistic Reserves! Here at Last?
Authors: Capen E. C.
Published: December 2007

Recently, the SPE and WPC modified earlier definitions of reserves for the industry. Through much lobbying about improving the definitions more, the committees pretty much held on to the past.

Many hold the belief that for the first time the definitions allow for the use of probabilistic reserves though they do not require this methodology. Not true. Reserves estimates have always been probabilistic whether or not the definition recognized that fact. The weasel words chosen such as reasonably certain, with high confidence, more likely than not, and possible all lay tribute to the concept of probability. These words and phrases by design take the place of numerical probabilities so that estimators would not have to actually use the mathematics of probability and statistics. On the other hand, the use of the word "proved" suggests that to some, probability was not such a big deal. When remaining proved reserves can increase by factors of 10 or more over a few year period, we must admit that the uncertainties associated with reserve estimates are not so trivial after all.

One particularly sticky problem in the past was how to combine well reserves estimates to get reservoir reserves or field reserves—not that most people recognized this as a problem. People simply added them together as intuition would dictate. Incorrect. Ending up with less than proved reserves, by definition, constitutes a rare event. There has to be little chance that the field would be any smaller.

The sum of 5 rare events (proved reserves from 5 wells) is much more rare than any one of the contributing elements. So what started out as reasonably certain becomes extremely certain. This latter phrase no longer fits the definition of proved. With this error promulgating throughout districts, regions, companies, and the world, we end up with nonsensical numbers. Whatever methodology one uses, he must both start and end up with something about which he feels reasonable certain. Probabilistic methods provide easy solutions.

First, estimators must recognize that the Central Limit Theorem works overtime in our industry. It ensurs that the distribution of remaining reserves is always lognormal and includes provision for probable and possible reserves. Time to quit debating this issue. Second, having created a lognormal distribution for zones, wells, or whatever building block they use, they can combine them into reservoirs, fields, and company reserves. The mean of the sums is the sum of the means always, and most always, the variance of the sum is the sum of the variances. The effort need not require the labor of Monte Carlo Analyses. A spreadsheet analysis does-it quickly.

Choosing probabilistic methods gives us the possibility of reporting more proved reserves. The deterministic method biases the results to the low side. Using probabilities, a company's proved reserves could increase by 25% to 50%.
Utilizing Discounted Government Take Analysis for Comparison of International Oil and Gas E&P Fiscal Regimes
Authors: Rapp William J. , Litvak Boris L. , Kokolis George P. , Wang Ben
Published: December 2007

The concept of fiGovernment Takefl is often used to compare International Exploration and Production (E&P) fiscal regimes for potential investments in oil and gas projects. fiGovernment Takefl is commonly defined as the percentage of all payments to Governments, over the life of a project, as a portion of the cash flows that remain after all project capital investment and operating costs have been paid. Examples of payments to Governments are: income taxes, royalties, profit petroleum share, bonus payments, value-added taxes, excise taxes, excess profits taxes, remittance taxes, state oil company carries, import duties, etc.

Virtually all Oil and Gas Companies use discounted cash flow analysis in project decision making. Likewise, when utilizing the concept of fi Government Take fi in comparing projects in different fiscal regimes, it is important to consider the opportunity cost of capital as it applies to the payments made to Governments, as well as the project™s revenues and costs. Since the timing of payments to Governments can vary widely depending on the structure of fiscal regimes, it is important to include the effect of this timing in the calculation of fiContractor Takefl. Payments to Governments can occur at the front end of a project (i.e. front-end loaded); for example-signature bonuses, import duties or value-added taxes, or they can occur later in a project™s life, such as is usually the case with profit Œ based taxes. If this variability of timing of the payments to Governments is not considered, two identical projects which are in different fiscal regimes may have identical Government Takes over the life of the projects, and yet the present values of those payments, discounted at an appropriate opportunity cost-of-capital, may be very different.

In order to avoid these potential distortions in comparison, it is suggested to utilize the concept of fiDiscounted Government Takefl to compare different international E&P fiscal regimes.

This paper will illustrate the utility of this concept by comparing the economics of several generic E&P projects in different International Oil and Gas E&P fiscal regimes based on fiGovernment Takefl and fiDiscounted Government Takefl. It will be shown that there can be significant differences between fi Discounted Government Takefl and fiGovernment Takefl, and that as a result, the relative attractiveness of countries™ fiscal regimes can be quite different when ranked based on using the more economically sound fi Discounted Government Takefl than when comparison is made on fi Government Takefl.

In addition, it will be shown that the difference between Government Take and Discounted Government Take can be used to measure the degree of front-end loading of Government Take.
Artificial Neural Network Enhanced Completions Improve Well Economics
Authors: Shelley Robert F. , Grieser William V.
Published: December 2007

Evaluating and optimizing well-completion procedures can be difficult because of a lack of understanding about the reservoir and completion dynamics. In many cases, a well completion is a compromise between optimum reservoir, well, completion, and operational factors. In this paper, we discuss the use of a form of artificial intelligence, the Artificial Neural Network (ANN), as a tool to enhance our ability to improve well economics. ANN models trained on reservoir, well, and completion information can predict well cumulative production with an acceptable degree of accuracy (less than 15% average absolute error).1–4 Sensitivity studies of these networks show that for a given reservoir quality, the completion method can significantly affect the well's production outcome. Case histories are presented in which an ANN sensitivity analysis was used to justify changes in completion/stimulation procedure. These ANN-enhanced completions resulted in improved well economics compared to the standard completion-optimization methods normally used in these fields.

This paper presents case histories in which ANN helped establish well completion priorities that improved well economics. ANN technology has been used in areas where a well-completion experience base exists. The completions analyzed with ANN techniques include the Red Fork formation in Roger Mills and Custer counties in Oklahoma; the Frontier formation in Lincoln County, Wyoming; and the Granite Wash formation in Roberts County, Texas. Specific areas of interest include any quantifiable well, reservoir, or completion characteristic that affects well production (porosity, thickness, pressure, geology parameters, well characteristics, completion/stimulation procedures, etc.). Net present value (NPV) was used for quantifying the economic effect of ANN enhancement on well-completion economics.
Evaluating the Economics of Gas Storage Well Deliverability Enhancement
Authors: Reeves S. R. , Beckman K. L.
Published: December 2007

Maintaining and enhancing the deliverability of gas storage wells has become increasingly critical for gas storage companies to remain competitive in this newly deregulated environment in the U.S. Unfortunately, standard methods to adequately evaluate the economic results of deliverability enhancement activities, and hence optimize them, are currently unavailable. This paper presents two new methods that begin to address the unique economic evaluation requirements of gas storage well deliverability enhancement. The first method is for application when the objective is to minimize the cost of maintaining deliverability, and the second when the objective is to maximize the economic value of a storage asset by upgrading it to shorter-term, higher-value service. Results from this study indicate that new and novel storage well stimulation methods, such as tip-screenout fracturing and fracturing with liquid CO2 and proppant, can provide substantial improvements in the economics of deliverability enhancement over more traditionally used methods. In addition, economic incentives may exist in some cases to upgrade current baseload facilities to shorter-term, higher-value service, although other, non-financial conditions still present barriers to activity in this direction. While the new methods presented in this paper represent an important improvement over current economic evaluation approaches, further advancements in this area are still needed.
Four Criteria for Selecting International Petroleum E&P Investment Opportunities
Authors: Wang B. , Litvak B. L. , Kokolis G. P. , Rapp W. J.
Published: December 2007

This paper presents four criteria suggested for selecting international petroleum E&P investment opportunities. It will be demonstrated how these criteria facilitate economic evaluation of E&P new business development opportunities. The two types of opportunities for which the utility of these criteria will be demonstrated, are exploration and discovered reserve opportunities, which require development, in various different fiscal regimes.

The four criteria presented are Expected Net Present Value (ENV), Risked Present Value Ratio (RPVR), Value-to-Buy-in Ratio (VBR) and Earnings per Gross-Working-Interest Barrel (E/GwiB). Earnings per Net-Working-Interest Barrel (E/NwiB) is not recommended for the screening criterion because of distortions caused by the fact that NWI Reserve calculations can be quite different for different fiscal regimes.

Three XY plots are suggested for use: (1) ENV vs. Risked Net Cost, with a slope of RPVR, (2) ENV vs. Buy-in Cost with a slope of VBR, and (3) Risked Earnings vs. Risked GWI Reserves with a slope of E/GwiB. Some examples will be shown how these plots can be used to evaluate opportunities for investment

A GWI-Barrel-Split method is also demonstrated that facilitates comparison of investment opportunities. This method splits the project BOE price into four per GwiB ratios: F&D/B, Opex/B, Government Take/B and Earnings/B. A plot showing the comparisons of the five ratios provides comprehensive information of project economics.
Waterflood Strategy, Challenges and Innovations
Authors: Kenawy F. A. , Bibars O. A. , Hanafy H. H. , Rezk A. S.
Published: December 2007

More than twenty four years ago, Gupco (Gulf of Suez Petroleum Company) initiated the first waterflood project in Egypt for the giant El Morgan oil field. With continuing waterflooding experience, Gupco has applied this improved recovery method for other fields. Currently Gupco operates 14 different waterflood reservoirs. These reservoirs have produced a cumulative oil representing 40% of their original oil-in-place. On average, the projected waterflood recovery factor is 54% of OOIP. Due to non-uniform lithology and non-uniform pattern of existing well locations in most reservoirs, peripheral waterflood was found to be the most suitable and economic waterflood pattern at project startup. Peripheral waterflooding has the advantage that it minimizes the number of injection wells by converting the watered-out producers. As the Gupco reservoirs become more mature, the line-drive pattern (peripheral + up-dip injection) was found to be more effective. Since most of the Gupco's reservoirs are currently in the mature stage, good managing and close monitoring for each waterflood project is extremely important. This paper presents Gupco strategy in managing the different waterflood projects to maximize both the oil production rate and oil recovery in optimum manners. This is being achieved through several common and familiar waterflood issues including: a) pressure maintenance, b) in-fill drilling, c) zonal injection improvement, d) injection pattern modification, e) injection below formation parting pressure, f) workovers for production and injection wells, g) continuous data collection, and h) water quality monitoring. The paper also shows how Gupco is addressing the waterflood side effects of scale buildup, reservoir souring and facilities corrosion. In addition, the paper discusses some of the innovative techniques that Gupco has used to maximize waterflood recovery and enable waterflooding of marginal fields. Examples for these techniques are gas-cap water barrier injection, heavy oil waterflooding, coiled-tube water injection lines, slim-tube dual completions, and satellite waterflooding for pilot and marginal fields waterflooding.
Design and Analysis of Interference Tests
Authors: Lescarboura J.A. , Walther H.C. , Wilson P.L.
Published: December 2007

Interference tests can show when wells are in the same reservoir and give areal average values for formation transmissibility, kh/ µ, and formation storage, Î¦hct. When combined with single-well buildup/fall-off tests, interference tests can also identify various reservoir heterogeneities. Even though straightforward interference tests a Fe simpler to run than pulse tests, they have been neglected in recent years due to misconceptions about test-time requirements. While characterizing reservoirs for tertiary recovery pilots, we have developed methods to design, run, and analyze interference tests. These techniques are covered in detail. Special problems such as wellbore storage effects, reservoir layering, barrier effects, etc., are discussed. The main conclusions are that interference tests can be performed with greater ease and in about one-third the time of equivalent pulse tests when the same gauges are used. Accuracy of results is comparable.

Introduction

For interference testing, a rate change in a source well causes a reservoir pressure transient that is measured in a shut-in observation well or wells. When the rate change is cyclic, the test is called a pulse test. Interference tests can show if wells are in the same reservoir and give areal average values for the formation transmissibility, kh/ µ, and formation storage, Î¦hct. Combined with conventional single-well tests, interference tests can also identify reservoir layering, determine fracture orientation, and locate barriers. While characterizing reservoirs for tertiary recovery pilots, we have seen examples of all these cases. In doing this work, methods were developed to design, run, and analyze interference tests, and these techniques are the subject of this paper.
Cost Effective Design of Corrosion Inhibitor Squeeze Treatments for Water Supply Wells
Authors: Kokal Sunil , Raju Kris , Biedermann Allen
Published: December 2007

Water for pressure maintenance in oil producing reservoirs is often obtained from wells that are drilled in water aquifers. Aquifer brine is corrosive and leads to the corrosion of well tubing, manifolds and water injection system. Downhole squeeze treatments with corrosion inhibitors provide an effective means of controlling the corrosion problem in supply wells and injection system. Filming amine type corrosion inhibitors are "squeezed" into the aquifer and the chemical returned with the produced water provides the necessary protection.

This paper presents an analysis and design study of corrosion inhibitor squeeze treatments for aquifer water supply wells. Laboratory and field data are presented for optimizing chemical usage and squeeze strategies. Corefloods conducted at reservoir conditions show that adsorption/desorption is the dominant mechanism of corrosion inhibitor retention and release from the formation. Squeeze treatments were simulated in the laboratory to determine the effect of important variables on squeeze life. These variables included the amount and concentration of inhibitor, volume of formation to contact, amount of overflush and the shut-in time. Laboratory testing and field trials have insured corrosion control at reduced operational costs. This has been attributed to the teamwork between laboratory personnel and operation engineers. Recommendations are made for optimizing future squeeze treatments.
Decision Tree Analysis and Risk Modeling To Appraise Investments on Major Oil Field Projects
Authors: Gatta S. R.
Published: December 2007

A deterministic approach is customarily employed in planning and budgeting process. More often than not, the experience shows that the targets (e.g. capital expenditure and completion time) are not achieved. A better view, however, of all the underlying uncertain parameters would have a significant effect on the decision makers' success as risk takers and ultimately therefore on the corporate profits.

The paper presents decision theoretic approach applied to appraise investments on a major oilfield project. The occurrence of different outcomes taking place over the planning horizon is a function of the (i) decisions preceding the event and (ii) chance phenomena concerning the individual physical and economic parameters. A decision tree is diagrammed to satisfy the feasible alternatives whether caused by options deliberately exercised or events naturally occurring. Thus, there is scope to test economic or other consequences before committing resources.

Risk modeling to evaluate the uncertainties in the resource availability, success/failure rates, capital constraints, oil market and the general economic environment is a complimentary part of the decision model incorporating the decision tree. Monte Carlo simulation technique is applied in the implementation of the decision model.

With proper definition of independent stochastic variables by their probability distribution functions, it has been possible to derive the risk evaluated economic yardsticks for each set of decision parameters thereby enabling the decision maker choose the optimum course of action keeping the financial and market risks in perspective. The real life example reported in the paper illustrates the major aspects of the recommended approach: (a) updating the decision tree and the model parameters based on the additional information gained during the actual implementation of the decision model, and (b) aiding the management decision making process to evaluate the consequences of exercising different options before committing the resources.
Bubble Point Pressure and Oil Formation Volume Factor Correlations
Authors: Al-Shammasi A. A.
Published: December 2007

This paper evaluates published correlations and neural network models for bubble point pressure and oil formation volume factor for accuracy and flexibility to represent hydrocarbon mixtures from different geographical locations worldwide. The study presents a new correlation for bubble point pressure based on global data with improvement in performance over published correlations. It also presents new neural network models and compares their performance to numerical correlations.

The evaluation examines the performance of correlations with original published coefficients and with coefficients calculated based on global data, data from a specific geographical locations, and data for a limited oil gravity range. The evaluation of each coefficient class includes geographical and oil gravity grouping analysis. The results show that the classification of correlation models as most accurate for a specific geographical area is invalid to be used for these two fluid properties. Statistical and trend performance analysis shows that some of the correlations are violating the physical behavior of hydrocarbon fluid properties. Published neural network models are missing major model parameters to reproduce. New developed models performed better, but suffer from stability and trend problems.
A New Stream-Tube Model for Waterflooding Performance in 5-Spot Patterns
Authors: El-Khatib Noaman A. F.
Published: December 2007

A new mathematical model is developed for waterflooding performance calculation in 5-spot pattern reservoirs using stream tubes. The method is based on estimating the location of the displacement front in any stream tubes relative to the location in any other tube at the same real time. Areal sweep efficiency, fractional oil recovery, fractional water flow and the injectivity ratio are calculated as functions of thetotal injected P.V. of the displacing fluid. The effect of mobility ratio on the performance is investigated. Comparison is also made between the performance obtained assuming piston-like displacement and that assuming Buckley-Leverett frontal advance theory.
Start-up of Peripheral Water Injection
Authors: Davis D. W. , Habib H. H.
Published: December 2007

Peripheral water injection began into the pressure depleted Wafra Ratawi Oolite reservoir during July, 1998. Sixteen water injection wells are currently being utilized to inject 44,000 BWPD using low pressure charge pumps from the hydrocyclone and filtration skid. Design rate under high pressure injection is 200,000 BWPD using twenty-six injection wells. The water injection facility design, injector well location criteria, and reservoir performance data obtained from injectivity tests and spinner surveys are documented. Initial comparison between reservoir simulator predicted water injection rates versus actual injection rates provide some useful insight into the future success of the project. Recommendations regarding future operation of the injection facility and injection wells are highlighted.
Vertical Gas-Oil Displacements in Low Permeability Long Core at Different Rates and Pressure below MMP
Authors: Soroush H. , Saidi A. M.
Published: December 2007

The aims of this laboratory experiment were: 1-To show the potential of a high oil recovery from one md permeability reservoirs by lean gas injection below MMP. 2-To be able to evaluate the dynamic behavior of immiscible displacements, and solution gas drive processes using commercial compositional simulation models. 3-To demonstrate that the sharp increase in recovery from a pressure of about 3500psi in the VGD displacement, is partly due to the thinning of the adsorbed film and thus the shrinkage of pendular rings as well as the possibility that the displacing phase starts wetting the rock surface.

The MMP of a reservoir oil with a bubble point pressure of 4200psi and a lean injection gas was found to be 4400-4500psi at a temperature of 237°F, using the slim tube method with a recovery of close to 92%. Experiments were performed on a 159.5cm long reservoir rock sample with an average permeability of one md and 16.5% porosity, with the same oil and gas, at an injection rate of 1 to 10 cc/hour with a recovery of respectively from about 74% to 62%. The effluent GOR and gas compositions were measured during the experiments. An experiment with 10% connate water saturation at a gas injection rate of 5cc/hour gave a similar oil recovery to that without connate water. These injection rates are several times larger than the gravity stable rate for this low permeability sample. This means that in a low permeability conventional reservoirs, gas injection at a higher rate than the gravity stable rate could still produce over 60% of the oil in place. In case of fractured reservoirs with a small threshold height, the recovery factor would be closer to the upper values since the displacement takes place under gravity stable rate.

A natural depletion run at 60psi pressure drop per hour was also made, with oil recovery of respectively 22 and 25.6% at 1000psi and atmospheric final pressures.

The analytical methods of calculating gravity drainage performance discussed in literature are critically reviewed. are Comments were made on the approaches, boundary conditions, the behavior of one phase and two-phase flow regimes, required conditions to form dimensionless groups, the effect of threshold height on production rate, the use of threshold pressure in calculating the pressure gradient in a block, etc. in solving the gravity drainage performance.
Barik 3D reshoot: tailormade acquisition for multiple objectives
Authors: Hoetz H. G. , Duyndam B. P. M.
Published: December 2007

The Barik anticline, situated in the southern part of the Ghaba saltbasin (Central Oman) harbours hydrocarbons at several levels. A large gas-condensate accumulation at a depth of 4.2 km lies beneath a mature oilfield at 2.5 km. The former is currently being developed in conjunction with the nearby Saih Rawl field for Oman's LNG project.

To improve the structural definition of the Barik field, a new seismic survey was designed to image these multiple levels. Advantage was taken of a recently introduced orthogonal acquisition geometry that allows 3D surveys for deep targets to be acquired more cost effectively. Proper imaging of the shallow oil target however, required local adjustment to the basic orthogonal geometry by adding infill lines. Additionally, the objective of firming up several exploration leads around the adjacent Al Ghubar saltdome, was also included in the design.

The tailor-made 900 km2 survey was acquired in the first half of 1998 with processing taking most of the second half. Data quality, in particular for the deeper targets, is superior compared to the previous survey. The improved structural interpretation already allowed to pick gas development wells in areas which were poorly imaged on previous data.
Creating a Positive HSE Culture in Order to Implement Operational Integrity Assurance System
Authors: Kerrigan John
Published: December 2007

BPAmoco have a system called Operations Integrity Assurance System (OIAS) that operations must fulfill to comply and deliver BPAmoco's Health Safety and Environmental Policy. OIAS consists of thirteen elements and associated "management expectations" and provides a "framework" within the Health Safety and Environmental Management System (HSEMS) for Policy delivery.

Audit is one of the tools used to assess the level of compliance and to improve, but more particularly BPAmoco are addressing behavioral issues within its HSEMS and audit program in order to create a more positive Health Safety and Environmental (HSE) culture within the organization.

Traditionally HSE Audits have tended to focus on equipment and procedural deficiencies without really addressing people issues adequately. It should be remembered that probably 98% of accidents are caused by people, and hence managers should do less inspection (hardware) and more systematic auditing through dialogue and listening to people in the workplace. This will lead to improved HSE culture and more effective implementation of the HSEMS and more importantly lead to improved HSE performance.

This paper describes BP's Operational Integrity Assurance System (OIAS) and the behavioral audit tool currently being used to improve the HSE culture and OIAS implementation. BPAmoco see future improvement in HSE performance linked to an overall safety program of which behavior modification in the workplace is crucial. The paper also describes how this systematic auditing approach can be used not just at operational work-sites but in project design offices.
Performance of Al Rayyan Field under Aquifer Pressure Support
Authors: Burno R. T. , Tucker R. D. , Noman R. , Abdulla I. A.
Published: December 2007

This paper will present a case study of production performance and analysis of A1 Rayyan, an offshore carbonate oil field, producing under strong natural aquifer pressure support. The field currently produces from six horizontal wells in the Arab A and C formations located in offshore Qatar. This field has been on production for two years as part of an early production & appraisal phase. Production is through the use of coiled tubing conveyed ESP, where the power cables are inside the coiled tubing. This protects the power cables from corrosive fluids and is known to be the world's first use of such a technique. Utilization of this ESP technology will also be briefly discussed in this paper.

During this early production period a number of pressure surveys were carried out to monitor performance of the two reservoirs. The paper will discuss examples of some typical pressure buildups analyzed on the horizontal wells producing at high water cuts and under strong natural aquifer support. Average pressure calculated from the buildup surveys indicate strong pressure support in the Arab C where reservoir pressure has remained close to the initial conditions even after two years of production. Such strong pressure support in the Arab formation has rarely been reported in this area before, and therefore provides an interesting case history. In the Arab A reservoir however, pressure has declined and water injection is currently under consideration. Material balance was used to estimate oil in place, aquifer size and investigate the sensitivity of aquifer parameters. Simulation studies have also been carried out to investigate pressure performance of the reservoirs and associated aquifers, bur are not reported in this paper.

An interference test carried out with one source and two observation wells is also discussed. Due to the high permeability, pressure buildup tests have shown distinct recognizable early and late time radial and linear flow regimes detectable in the log-log plots. Difficulty of conducting buildup surveys with ESP inside the tubing is also discussed. Specialized plots were used to calculate reservoir properties and then estimate average reservoir pressures.
Preliminary Studies on Using Artificial Neural Networks to Predict Sedimentary Facies of the Permo-Carboniferous Glacigenic Al Khlata Formation, Oman
Authors: Schoenicke Olaf , Al-Alawi Saleh M. , Al-Bemani Ali S. , Kalam Mohammed Z. , Le Varlet Xavier
Published: December 2007

Artificial Neural Network (ANN) models have become increasingly significant in predicting various reservoir-engineering parameters. Their ability to generalize and infer subtle, unknown relationships from the input data makes them predestined for geological facies determinations from wireline log data.

Initiated by the need for a robust and automated facies identification tool in the very heterogeneous Permo-Carboniferous glacigenic Al Khlata Formation of south Oman, the present study is directed towards an improved definition of sedimentary facies and facies associations from wireline logs, which can be used as direct input to 3D modeling.

A total of eleven (11) sedimentary facies were described from conventional and borehole image log data in the Rima field of south Oman. The core- and partially outcrop-calibrated sedimentary facies form the basis of a facies interpretation technique using two ANN models: The first model uses quantitative analysis of conventional wireline log data (density, neutron, gamma ray and photoelectric effect). The second model uses a combination of qualitative information of the internal organization of the formations (‘image morphology’ - provided by high-resolution electrical borehole image data) and the quantitative data of model 1.

Preliminary results show that the first model can predict a set of six ‘wireline facies’ with an accuracy of 93%. The second model, which is presently being trained with ‘image morphology’ information derived from FMI*/FMS* data, will allow for the prediction of all pre-defined 11 sedimentary facies and facies associations.

Once fully trained this interpretation technique requires a minimum of interactive intervention by the analyst. The highly robust output can directly be used as input for 3D modeling of reservoir architecture and ultimately in 4D dynamic simulations, which will lead to optimized field development strategies for the Al Khlata Formation, one of the most prolific fields in south Oman.
Performance and Operations Review of the Major Multi-Reservoir, Bell Creek Field, Montana
Authors: Burt R.A. , Haddenhorst F.A. , Hartford J.C.
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

This paper was prepared for the Rocky Mountain Regional Meeting of the Society of Petroleum Engineers of AIME, to be held in Denver, Colo., April 7–9, 1975. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made. provided agreement to give proper credit is made. Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

The Bell Creek Field consists of six Muddy Sand reservoirs unitized as six units. A line drive water flood from the west edge of each reservoir has been in operation since 1970. oil production in November 1974 was 26,000 BPD. Cumulative production to December 1974 was 66.9 million barrels of oil. Tertiary recovery by a micellar process is under active consideration.

Introduction

The Bell Creek Field is located sixty miles north of Gillette, Wyoming, in Townships 8 and 9 South, Range 53, 54 and 55 East, Powder River and Carter Counties, Montana, as shown on Figure 1. The field is fifteen miles long and three and one-half miles wide, and consists of six secondary recovery units encompassing 17,000 productive acres, containing 305 active producing and injection wells. The current 26,000 BOPD rate accounts for nearly one-third of the oil production in the State of Montana.

HISTORY

The field was discovered June 4, 1967, by Exeter Drilling on a farm-out from Samuel Gary. The discovery well, 33-1 Federal-McCarrel, located in the NE1/4NE1/4 of Section 33, Township 8 south, Range 54 East, was completed for an initial pumping potential of 230 BOPD from perforations at 4524 to 4537 feet.

The Montana oil and Gas Commission designated forty-acre spacing for Bell Creek which resulted in drilling and completion of 405 oil wells and 10 gas wells. The average depth of a Bell Creek well is 4500 feet.
Difficulties of Relating IR T1 Maps to Pore Size Distributions
Authors: Al-Mugheiry Mohammed Adil , Issa Bashar , Mansfield P.
Published: December 2007

The measurement of longitudinal relaxation time (T1) by inversion recovery (IR) method or in short IR T1 mapping is a relatively simple and straight forward method for obtaining information related to the void space of saturated porous materials like sandstones. The way in which this information is to be interpreted, however, requires a more careful judgment.

The T1 distribution of water phantom reveals that there is a spread in T1 values due to intrinsic NMR noise caused by the imaging system. A similar effect will also cause T1 distributions of porous materials to be broadened in addition to the expected broadening due to void size variation or localized domains of different microscopic structures. Thus, the spread due to noise complicates the interpretation of T1 maps of these materials.

The spin-lattice data presented in the form of population distributions are believed to be an indirect reflection of the distributions of average pore sizes. For 3.0 mm and 1.0 mm glass bead packs, the relative distribution peak value of 2.6:1 was found to be broadly in line with the expected ratio of 3:1 assuming spherical pores and constant surface relaxation strength.

In the case of rocks, however, the lack of information about expected pore sizes and surface relaxivity pose a real difficulty as to how to interpret the data. The calculated values are believed to be broadly overestimated though may still indicate a genuine distinction in relative peak average values related to void spaces in these materials.
Design, Execution and Evaluation of a Novel Coiled Tubing Acid Stimulation Operation - A Case History
Authors: van der List E. J. F. , Quintero L. F.
Published: December 2007

A novel coiled tubing acid stimulation technique was successfully implemented in a horizontal well in Oman. Prior to stimulation the well was producing approximately 850 bopd with 2% watercut, from the Natih limestone reservoir. The open hole section had not been previously stimulated and it was fair to assume that there was near borehole formation damage due to overbalanced drilling and/or mud cake buildup. System analysis of the well suggested that the producing tunnel length was being severely affected by this skin and that removing such damage would increment the effective tunnel length almost twofold. As a consequence, the potential productivity index would increase by 78%. The objective of the stimulation job was to remove the drilling damage and allow the horizontal wellbore to flow to its full capacity The recommend acid system was a combination of a silt removal formulation (MSR) and Temporary Crosslinked Diverter (TCD). The treatment was done in 15 stages, covering 250 ft. per stage. A four month continuous production analysis shows an increase in PI from 1.6 to 3.2 and an oil rate of 1585 bopd (a 82% increase).

This paper should serve as a guideline into what tools and techniques can be used for complete design and execution of a stimulation operation. Also shown is an evaluation tool, which is vital to both service and operating Companies. To the former it shows where success is achieved enabling the company to focus attention and increase activity. To the latter it provides a quick economic view that should always be a part of the operator's decision making.

Following the well A coiled tubing acid stimulation, the challenge of performing a similar operation in a dual lateral was undertaken. This resulted in the application of the described techniques and use of a novel technique, using tracer material and a temporary chemical plug that proved to be successful.
A Review of Different Methods in Initializing and History Matching a Reservoir Model with Tilted Oil-Water-Contact
Authors: Hsueh P. T. , Pham T. R. , Bu-Hulaigah E. H.
Published: December 2007

Initializing a reservoir simulation model with a tilted oil-water-contact requires a special consideration in terms of capillary pressure curves selection and an understanding of reservoir fluid distribution. The paper discusses four different methods used, and presents the advantages and disadvantages of each method. Some of these methods will reveal that it is not enough to initialize a reservoir model, check for original oil-in-place then proceed with the history matching process. Inappropriate use of capillary pressure curves may cause errors in pressure and saturation calculations. The errors are often masked by changes made to reservoir parameters towards achieving a history match. A simple, quick procedure is outlined to identify these errors and to correct them before history matching efforts begin.
The Effect of Hyrolysis of Polyacrylamide on Solution viscosity, Polymer Retention and Flow Resistance Properties
Authors: Martin F.D.
Published: December 2007

Many excellent articles have reported various aspects of the nature of hydrolyzed polyacrylamide flow in porous media. The polyacrylamide flow in porous media. The degree of mobility reduction is proportional to:the viscosity of the polymer solution which is greatly affected by the presence of dissolved ions in the water, andthe reduction in reservoir permeability to water caused by flow of the polymer solution.

Penetration of a low mobility polymer slug Penetration of a low mobility polymer slug into a reservoir is limited in part by the adsorption of the polymer onto the rock surfaces or entrapment of the polymer in restricted flow channels. However, the behavior of "partially hydrolyzed" polyacrylamide can depend on both the nature polyacrylamide can depend on both the nature and extent of hydrolysis of the polymer molecule.

Reported in this paper are laboratory investigations of the viscosity and adsorption characteristics of polyacrylamide hydrolyzed to varying degrees with potassium hydroxide. Hydrolysis of polyacrylamide will increase both the measured and relative viscosity in both fresh water and NaCl brines. However, these polymers are sensitive to divalent ions. The higher the percent hydrolysis, the more polyacrylamides are affected by the divalent ions and at the 35% hydrolysis level may begin to precipitate. With fresh injection waters, the higher hydrolyzed polyacrylamides (25–35%) produce the most viscous polyacrylamides (25–35%) produce the most viscous solutions. In high calcium brines, a 15% or lower percent hydrolyzed polyacrylamide can produce greater solution viscosity. produce greater solution viscosity. Sandpack flow tests indicate that the adsorption of polyacrylamide in porous media decreases with increasing hydrolysis. Resistance factor curves display the effects of viscosity and polymer retention on mobility reduction properties. Information outlined in this paper is helpful in showing specific differences in hydrolyzed polyacrylamides that are a function of the degree of hydrolysis and are important in selecting the right polymer for a particular field application. polymer for a particular field application

Introduction

The energy crisis has stimulated additional activity in all aspects of oilfield operations.
Kick Detection and Well Control Training
Authors: Letbetter S.C.
Published: December 2007

As we are all aware, drilling activity is on the upswing, with a current average of over 1,600 rigs in operation in the United States, compared with 975 in 1971. A National Petroleum Council study projects 33,000 well completions and the drilling of 172 million ft of hole in 1975, despite shortages of tubular goods, pumps and other equipment. As a result of the continued increase in drilling activity, especially in foreign operations, the drilling industry is experiencing acute shortages of experienced, qualified personnel and is having to face the resultant problem of training new personnel.

INTRODUCTION

Traditionally, technical instruction, such as that needed in well control training, has been conducted by several methods: study of printed material, classroom activities, and actual on-the-job training. Even in situations where on-the-job training is feasible, as on a drilling rig, the trainee receives only limited instruction, since making hole and reaching contract depth quickly is the ultimate goal of drillers. The trainee learns normal, routine operations and seldom, if ever, experiences the abnormal condition of a kicking well and the control problems associate with it.

Even with the best of planning, the drilling of wells will always carry a potential blowout hazard, and some will probably occur. However, a carefully planned, continuing program to make crew members aware of the potential hazards of blowouts and exactly what is expected of them in an emergency situation should prevent most blowouts.

Recognizing this fact, Shell management began searching for a way to reduce the length of on-the-job training through simulations of control problems without waiting for training during actual control situations. The result of the search for an experience accelerator is training on an actual test well and an electrical well control simulator.
Geothermal Projects and Estimates Through 1985 and the Year 2000
Authors: Glass W.A.
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

This paper was prepared for the Oklahoma City SPE Regional Meeting, to be held in Oklahoma City, Okla., March 24–25, 1975. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made. provided agreement to give proper credit is made. Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

Production of geothermal energy in the U.S.A. to date is 410 MWe. On an "accelerated program", this is to increase to 20,000 MWe by the year 2000. The geothermal projects that will contribute to this growth include dry steam fields, hot brines, moderate temperature/low salinity fluids, geopressured reservoirs, hot dry rock, and magmatic deposits.

Introduction

The contribution of geothermal energy to the total current U.S. energy needs is 410 MWe. This is approximately equivalent to a daily oil production of 16,400 bbls. per day. This amount of energy is less than .1% of the U.S. daily oil consumption.

The Federal Energy Administration (FEA) was asked to compile a report on what can be done in all energy fields for the U.S. to become energy self-sufficient by the year 1985 with projections to the year 2000. The FEA asked the National Science Foundation (NSF) to compile a portion of this Project Independence Report concerning Geothermal Energy.

Geothermal energy production is very small at present and will not progress at sufficient speed without being accelerated on a large scale to be a significant part of "Project Independence" by 1985 and 2000.

The nest projections were made on business-as-usual condition. This would mean that private industry would continue its current pace using present guidelines, procedures, and practices. The projections were finally procedures, and practices. The projections were finally estimated on an accelerated program. This means that a Federal research program would assist private industry in solving the problems that currently inhibit or restrict their current exploration efforts.