bluuebunny/crossref_metadata_2025 huggingface dataset:
Field Application of Clean Completion Fluids
Authors: Sollee S. S. , Elson T. D. , Lerma M. K.
Published: December 2007

Chevron U.S.A.'s Western Region has recently utilized clean completion fluids in several new wells. This paper describes fluid changeover and monitoring techniques used in these wells. The success of the procedures is supported by fluid analysis (total suspended solids and particle size distribution) and well performance results.

Techniques for changing over from drilling mud to completion brine before perforating will be discussed. In offshore areas, drilling mud is displaced with several hole volumes of seawater followed by a flush containing a surface active agent to remove mud or debris attached to casing or workstring walls. Completion brine is then circulated and filtered until well returns are clear. Onshore, a high viscosity pill is used to displace the drilling mud followed by the surfactant and the filtered completion fluid.

Turbidity of completion fluids has been correlated to total suspended solids (TSS) to allow fluid quality monitoring at the wellsite. TSS has also been measured directly on location. All on-site sampling and monitoring is followed by laboratory analysis which includes determination of particle size distribution. This has allowed evaluation of equipment and techniques used in the changeover programs.

In this study, most of the wells were changed over to completion fluid containing less than 100 mg/l TSS with 90% of the particles smaller than 10 microns. Productivity of these wells has either met or exceeded expectations. Pressure buildup surveys have typically shown no skin damage.
Perforation Performance in the Kuparuk River Field
Authors: Bihn G. C. , Brown S. A.
Published: December 2007

Tubing conveyed casing guns used for under-balanced perforating of the Kuparuk River sandstone in the CPF-1 area failed to result in improved productivity when compared to casing guns fired in an overbalanced completion system. Observed well productivities were similar regardless of which perforating method was used; this finding is presumably a result of the near-equivalent surge differential existing across the sandface at the time of initial-production. Slightly higher productivities obtained when using casing guns in an overbalanced completion system is explained by possible deviations from reported penetrations of the charges supplied by the perforating companies. A third group, through-tubing guns, yielded slightly lower well productivities when compared with the other perforators investigated.

Most perforating gun performance studies have been evaluated in laboratories under API specifications. This study evaluated the field performance of different guns and perforating techniques in the Kuparuk River Field (CPF-1 area). Actual pressure transient analyses from over 50 wells were used for the comparison.
Numerical Simulation of MWD Pressure Pulse Transmission
Authors: Chen S. J. , Aumann J. T.
Published: December 2007

Dynamic hydraulic pressure pulse transmission is currently used by many Measurement While Drilling telemetry systems. A theoretical model which simulates this pulse is required to develop high data rate communications systems. In this paper, a numerical solution of the equations that govern unsteady fluid flow is developed. The boundary conditions are adjusted for the surface and downhole equipment. The program outputs pressure and flow pulse predictions at any point of interest. Finally, calculated results are compared to experimental data and exhibit good correlation.
Development of a Surface Drillstring Vibration Measurement System
Authors: Besaisow A. A. , Jan Y. M. , Schuh F. J.
Published: December 2007

This paper describes the phase I development of an Advanced Drillstring Analysis and Measurement System (ADAMS). The system analyzes axial, torsional and lateral surface response of drillstrings to detect various drilling phenomena. This capability will be used to reduce drillstring failures and improve drilling efficiency. Of particular importance, is the ability to detect casing/ drillstring interaction, general tubular failures and formation properties. Detection of these properties will be investigated using mechanical wave information available at the surface.

The system was successful in detecting and analyzing various drillstring phenomena in a shallow test well and in a 2300' well at Rockwall, Texas. The phenomena detected using surface wave information included drillstring/casing interaction, downhole vibration phenomena, downhole motor RFM, and stuck pipe location. Also, overall vibration signatures changed when different formations were being drilled. Further study in deeper wells is needed to determine whether this system will accomplish its objectives at required depths.
The Oil and Gas Resource Potential and Economics of the Gulf Shelf and Slope
Authors: Vidas E. H. , Manger K. C. , Woods T. J.
Published: December 2007

This paper evaluates the remaining new field oil and gas resource potential and economics of the western and central Gulf of Mexico shelf and slope. The study area is divided into four water depth intervals; 0–40 meters, 40–200 meters, 200–1000 meters and 1000–2000 meters. Resource base estimates for the two shelf intervals are developed using a statistical curve fitting technique relying on field-by-field discovery data through 1980. The resource base estimates for the two slope intervals are developed by analogy to more explored areas. The discovery process is modeled for each water depth interval using a modified Arps Roberts equation. This equation describes the expected number of fields in each of 20 size classes that will be discovered per unit of exploration (e.g., 100 wildcat wells).

Detailed cost estimates are developed for exploration and production wells, production platforms, processing equipment, etc. The threshold oil and gas prices needed to make field development economic are presented for oil and gas fields in various size classes for each of the water depth intervals. The current and near term economics of exploration and development are shown for each water depth interval. Also the total ultimate recovery from new oil and gas fields that could be added at various future price levels are presented.
Expanding Recoverable Reserves Through Refracturing
Authors: Conway M. W. , McMechan D. E. , McGowen J. M. , Brown D. , Chisholm P. T. , Venditto J. J.
Published: December 2007

With the current unfavorable economic climate caused by uncertain oil prices and a curtailed gas market, restimulation of existing wells to increase production rates and/or economically recoverable reserves has become an alternative to exploration or drilling development wells. Production increases realized from refracturing in several areas have demonstrated that recompletion of certain wells can be one of the best investment opportunities available.

Developments in fracturing technology and interpretation have increased the potential for successful restimulation in an increased number of wells. Because of recent advances in fracturing technology employing more efficient fluids capable of transporting high sand concentrations and modified surface equipment, treatments can be performed that were previously not possible.

Case histories of two oil reservoirs giving the sizes of the initial fracturing treatment and refracturing treatment plus production after each, are presented. Unfortunately, very little information on gas wells is available because of the current economic climate.
Estimated Finding and Developing Costs: Methods, Problems, and Proposals
Authors: Barnhill D. B.
Published: December 2007

The results of alternative methods of estimating finding and developing costs are compared. Better information would be provided if an effort is made to match expenditures and reserves, and if a different gas to oil conversion factor is used. The erratic character of the estimates is demonstrated.
Fracture Stimulation Design and Evaluation
Authors: Warembourg P. A. , Klingensmith E. A. , Hodges J. E. , Erdle J. E.
Published: December 2007

Stimulation treatments have been difficult to design and evaluate because of the numerous variables involved. A successful treatment has too long been defined as "one where the treatment was pumped without problems." A successful treatment should be defined as "one that provides the production predicted by the design process."

The conditions associated with stimulation results and a method to design an optimum treatment with more accurate, predicted results are presented. The method combines both old and new technology associated with well performance testing (pressure transient testing and production systems analysis), pump-in tests to obtain certain critical variables in situ, and compilation of the obtained data to design an economically optimum stimulation that will provide predicted results. The method is used to optimize the design prior to spending any money for stimulation treatments. This optimization allows important economic decisions to be made and a treatment design that is based on those economics. The method also allows the evaluation of post-treatment results.
Recommended Practices Improve Hole Opening and Underreaming in Offshore Wells
Authors: Mefford R. N.
Published: December 2007

Exxon Company, U.S.A. extended application of existing hole opening and underreaming technology and improved tool performance in two recent deep offshore directional wells. These Gulf of Mexico wells experienced an almost 100% increase in tool life even with the added complexity of hole enlargement to directional depths deeper than previously encountered in this offshore region. Earlier straight wells in the area were characterized by short tool life and loss of cutters. Improved hole opening and underreaming practices were major factors in this success.

This paper discusses the general evolution of hole enlarging techniques, examines hole opener and underreamer performance in four recent offshore wells, develops a correlation between specific operating practices and increased drilling performance and recommends guidelines to improve operation of these tools in both straight and directional offshore wells. The analysis includes an investigation of penetration rate, bit hydraulic horsepower, bit weight, rotary speed, cutter type, stabilization, bull nose design and shock sub employment.
Contributions of Observation Well Logging to the Evaluation of Polymer-Augmented Waterflood Pilots
Authors: Grooms G. E. , Schulte R. K.
Published: December 2007

This paper describes how dual induction logs run in fiberglass cased observation wells may be the best and sometimes the only conclusive way of evaluating a polymer augmented waterflood pilot. A case in point is the Shannon Improved Waterflood Pilot at the Naval Petroleum Reserve No. 3 (Teapot Dome), near Casper, Wyoming. Conventional evaluation methods of the pilot have indicated mixed, but generally discouraging performance, while induction logs from four observation wells have shown oil displacement to average 21 percent recovery from the total net pay. This compares with predicted primary recovery of only 5 percent from the same net pay. Induction log data from the observation wells is supplemented with cumulative pilot oil production to indicate that field-scale development of a polymer augmented waterflood may be feasible.
Evaluation of Permeabilities Determined From Repeat Formation Tester Measurements Made in the Prudhoe Bay Field
Authors: Jensen C. L. , Mayson H. J.
Published: December 2007

Methods previously presented in the literature for determining permeabilities from RFT* pretests were applied to an extensive amount of data recorded in 14 cored wells in the Prudhoe Bay Field. Arithmetically averaged core permeabilities in the zones of interest were validated by comparison with pressure build-up data. The foot by foot core data was then used to achieve an adequate vertical resolution for meaningful comparisons with RFT results.

Comparisons indicate that corrected RFT data are consistently lower than corresponding core data. RFT- and core-derived permeabilities agree more closely when data is obtained from low-permeability sands. Trends between the two types of derived permeabilities exist for a few wells. However, these trends are different from well to well, and it is not possible to develop a usable field-wide correlation between RFT and core permeabilities.

The study cites reasons for the differences between RFT- and core-derived permeabilities. These differences are attributed to relative permeability effects, uncertainties in fluid saturations, well-specific skin damage, reservoir anisotropy, and uncertainties in drawdown fluid flow equations for the RFT measurements. In conclusion, RFT permeabilities cannot be used to determine true reservoir permeabilities.
Development and Application of a Downhole Chemical Injection Pump for Use in ESP Applications
Authors: Cramer R. W. , Bearden J. L.
Published: December 2007

The effective chemical treatment of wells producing with artifical lift equipment, such as Electric Submersible Pumps (ESP's), is both difficult and expensive. Frequently, chemical treatments must be injected low in the well to protect the casing, the perforations, and the artifical lift equipment. Until recently, chemical treatments were placed by batch method or through coil tubing from the surface. This article describes the development, hardware configurations, and the applications, of a novel Downhole Chemical Injection Pump being utilized with electric submersible pumps. This paper reveiws the use of the pump in the Rangely Weber Sand Unit, discusses the possible applications, and compares the economics of this system to surface treatment and coil tubing treatment methods.
Low-Volume Continuous Inhibition Technique, at Nominal Expense, for High Wellbore Temperature, CO2, and Mildly Sour Gas Producers
Authors: Weeks S. G. , Hausier R. H.
Published: December 2007

The cost of corrosion control, or lack of effective control, can be a major factor in the ultimate economics of corrosive gas production. While corrosion attributed to most hostile well environments can be controlled by either batch or continuous inhibition; in many applications, related costs or production requirements may be prohibitive. Extensive testing, including surface monitoring and well bore calipers, has now verified that a simple low-volume continuous downhole inhibition technique can be an effective, low cost means of controlling corrosion attributed to CO2 and mildly-sour gas.

Excessive corrosion rates can be encountered, in the presence of a water phase and regions of high velocity, at CO2 partial pressures as low as 3.5–4.0 psi(1). The damage may be further aggravated by traces of H2S and brine quality. Corrosion control under far more hostile conditions – with BHT's up to 425°F and wellhead partial pressures exceeding 1,000 psi – has been accomplished by scheduled batch treatments. However, as reservoir pressures decline, this technique may present operational problems; and may not be cost effective. Successful low-volume continuous downhole inhibition was thought to be dependent on two major factors: (1) availability of small bore injection tubing, and (2) necessity of liquid phase inhibitor carrier fluid under downhole conditions. Field data, obtained over a four-year period, show conclusively that neither condition is imperative; thus, opening the way for low cost treatment of marginal wells. Data is presented to reflect as much as a 10-fold reduction in corrosion rates where holes are perforated through the tubing, immediately above the production packer, and corrosion inhibitor subsequently pumped down the tubing-casing annulus. An approximate equal volume of inhibitor is injected into the tubing via these holes, for distribution continuously over a like period of time, as pumped during previous batch treatments.
Formulation of a Cost-Effective Chemical Treatment Program
Authors: Mowery C. L.
Published: December 2007

Paraffin and scale deposition in wells at Conoco's Chittim lease has consistently hampered operations. Numerous chemicals were laboratory and field tested to determine the two most cost-effective chemicals for paraffin and scale treatment. These were a paraffin solvent and a sulfamic acid system, respectively. Gross lease revenue has increased substantially with the use of the two chemicals in a fieldwide treatment program.
Drilling to the Wolfcamp, Strawn, and Fusselman Formations, Glasscock County, Texas: A Case History
Authors: Laumbach J. T. , Whiteman D. L.
Published: December 2007

This paper presents a case history of the methods used by Exxon Co., U.S.A. to drill the St. Lawrence Field in Glasscock County, Texas. Lightweight oil base mud was used to combat salt and lost circulation, while brine water weighted with hematite was used to drill an abnormally pressured section. Two-stage and tack-and-squeeze cementing were used to place cement across lost circulation zones. The lightweight oil base mud was technically successful, yet proved uneconomical. In contrast, the hematite was cost effective as a weighting material. The tack-and-squeeze method proved to be the most successful method of cementing.
Foam Fracturing Utilizing Delayed Crosslinked Gels
Authors: Craighead M. S. , Hossaini M. , Freeman E. R.
Published: December 2007

Recent developments in foamed fluids have improved fracturing success on several formations within the North Texas, East Texas, Oklahoma, and Bakersfield, California areas. Laboratory results indicate the foaming of a delayed cross-linking gel increases apparent viscosities, as well as sand transport and fluid loss properties beyond those of foamed linear gels.

A detailed explanation of a 1,100 foot high pressure single pass pipe viscometer and fluid loss apparatus is provided. Results suggest foam cross-linked gels follow power law fluid behavior, possessing 44% higher viscosities than conventional foams. Fluid loss testing also shows a 40% reduction in leakoff beyond conventional foams. Dynamic proppant support for foams is not perfect according to parallel plate observation. Fall rates for conventional foams while affected by foam quality are two orders of magnitude greater than foam cross-linked fluids. Resulting proppant profiles are believed to be superior to conventional foams due to virtually infinite static proppant support.

More than 100 treatments have been completed using a delayed cross-linking foam. A review of local formation characteristics and treatment conditions are di scussed regarding the success of a cross-linked versus conventional linear gel foam.
Preflush Analysis of the Glenn Pool Surfactant Flood Expansion Project
Authors: Angert P. F. , Leventhal S. H.
Published: December 2007

A history match of the chloride concentration of produced brine during the preflush phase of the Glenn Pool Surfactant Flood Expansion Project was obtained. Valuable insight into the performance of the surfactant flood was achieved by utilizing a modified version of a general purpose Black Oil Simulator (BOS), capable of tracking chloride concentrations throughout a reservoir. The success of the preflush in removing divalent ions and in establishing optimal salinity within the reservoir prior to injection of the surfactant is inferred. Also the volumetric sweep efficiency of the reservoir pattern studied is determined along with the effect of vertical crossflow on the volumetric sweep efficiency.
New Quick-Setting Cement Solves Shallow Gas Migration Problems and Reduces WOC Time
Authors: Sepos D. J. , Cart B. W.
Published: December 2007

Natural gas migration behind surface casing, from the shallow Devonian shales, has caused many problems for operators in northeast Ohio, northwest Pennsylvania and western New York. Foremost are the problems of rig and well fires during drilling and workover, along with natural gas contamination of shallow fresh-water zones that many persons in rural areas depend on as their sole source of potable water. The problem of gas migration became so severe in northeast Ohio, in January 1985, that the Ohio Department of Natural Resources declared a moratorium on drilling within a limited area of Lake and Ashtabula Counties until a solution could be found.

Three important slurry characteristics had to be addressed in preventing this gas migration: rapid strength development at low temperature, expansion of the set cement, and a short transition time. The transition period is the time it takes the cement to go from a pumpable slurry to a set solid material. A quick-setting cement system was developed capable of satisfying the previously mentioned requirements. At 60°F (15.6°C), approximately 500 psi (3,447 kPa) of compressive strength is obtained in two hours. Transition time from a fluid to a solid is a minimal three to four minutes. This cement also has excellent linear expansion at low temperature.

The use of this quick-setting cement has so successfully controlled gas migration that the Ohio Department of Natural Resources has allowed the resumption of drilling in the affected area. Even where gas migration is not a problem, operators have found that quick-setting cement can substantially reduce WOC time on shallow surface strings set under low-temperature conditions. This paper will further examine the technology associated with this new product, and review case histories where it has been used.
A Systematic Approach for Economic Development of the Devonian Shale Gas Resources
Authors: Ameri S. , Aminian K. , Miller J. A. , Doricich D. , Yost A. B.
Published: December 2007

The unconventional reservoirs in the Devonian Shales are considered to be the most underdeveloped and potentially the most productive source of natural gas in the Appalachian Basin. The identification of high potential areas for exploration and development of Devonian Shale formations with respect to economic production of natural gas is becoming increasingly difficult. During the past two years, the gas produced from the Devonian Shale horizons has encountered additional difficulties in remaining competitive due to the declining demand and gas supply surplus. For Devonian Shale resources to remain competitive and regain the market, it is necessary to reduce the cost of exploration, drilling and production. It must further be recognized that the development of the Devonian Shale gas resources is limited not only by existing engineering technology but also by the identification of prospective areas where the technology can be successfully applied. It is, therefore, essential that target areas for shale development be selected based upon sound exploration rationales.

One economic means of exploiting the Devonian Shale is through multiple completion in conjunction with shallow gas-bearing formations which are stratigraphically located above the shale horizons. The overall objective of this study is to delineate, assess and evaluate areas which are potential candidates for multiple completion in the Devonian Shale formations as well as shallower gas-bearing horizons (such as Big Injun, Weir, Berea, and Big Lime) in West Virginia. The reservoir parameters such as porosity, gas saturation, net formation thickness, open flow potential, and production data have been collected and analyzed to identify and evaluate high potential areas for the mentioned formations. The qualitative and quantitative interpretations of data and assessment of areas for future development have been enhanced by computer generated maps. These maps provide interregional comparison as well as a guide for future optimization of stimulation treatments. The identification of potential areas amenable to multiple completion has been achieved by superimposition of the generated maps of Devonian Shale and other gas-bearing horizons.
Analysis of Eastern Devonian Gas Shales Production Data
Authors: Lee W. J. , Gatens J. M.
Published: December 2007

Production from over 500 Devonian Shale wells has been analyzed. Permeability-thickness, k̄h, determined from potential test and production data has been found to correlate with well performance. Empirical performance equations, production type curves, and a dual-porosity model with automatic history-matching scheme were developed for the Devonian Shale.
Application of an Analytical Model To History Match Devonian Shales Production Data
Authors: Gatens J. M. , Lee W. J. , Rahim Z.
Published: December 2007

This paper describes an analytical dualporosity reservoir model which includes transient flow in the matrix and in the fractures. The model uses an automatic scheme to history match Devonian Shale production data efficiently. A good match provides a reasonably unique estimate of permeability-thickness product and an accurate performance prediction.
Effect of Fracturing Fluid and Its Cleanup on Well Performance
Authors: Soliman M. Y. , Hunt J. L.
Published: December 2007

After a gas well is hydraulically fractured, the relative permeability of the reservoir to gas may be reduced when fracturing fluid invades the pay zone. This phenomenon reduces the well's potential productivity and is more pronounced in low permeability gas reservoirs. Efficient clean-up for this fracturing fluid is thus essential in gas reservoirs. As the first step toward this objective, this paper will study the effect of fracturing fluid clean-up using a numerical simulator for gas-water fractured reservoirs.

This study proves that (1) the dimensionless fracture conductivity FCD, (2) dimensionless fracture length,xf/xe, and (3) the formation capillary pressure, Pc, affect the rate and pattern of the clean-up process. It also shows that the pattern of clean-up can cause misinterpretation of post-frac pressure analysis tests. A better understanding of the clean-up pattern promotes correct analysis of pressure tests.

This paper also shows that the optimum fracture conductivity necessary to clean up the formation may be much higher than that necessary to produce the reservoir. Thus, the fracture parameters, especially for tight gas reservoirs, should be designed so a fracturing treatment will yield enough conductivity for efficient clean-up of fracturing fluid.

Pressure build-up data are simulated and the resulting synthetic data are analyzed to study the effect of clean-up on the calculation of reservoir and fracture parameters.
Exploration in Bengal Basin India – An Overview
Authors: Raman K S , Kumar Sukhdarshan , Neogi B B
Published: December 2007

Detailed synthesis of results of exploration enables us to delineate the basin configuration, stratigraphy and tectonic framework of Bengal basin. The Basin has an area of 89000 square kilometers and a fill of 10-15 km thick sediments. A number of hydrocarbon indications have been registered but without any commercial discovery. On the basis of available seismic and well data the following five types of plays have been delineated, namely: Pre-Trappean prospectsPalaeocene/Cretaceous pinchout prospectsReef prospectsOligocene pinchout prospectsMiocene/Pliocene deltaic prospects

Subsidence history, geothermal and geochemical data indicate not only maturation of source-prone formations but also possible 'live-basin' conditions below a depth of 2900 m. Present paper gives a brief account of exploration efforts put in and possible source rock, maturation and entrapment conditions along with types of plays in Bengal basin.
Identification of Bypassed Oil Using Gamma-Ray Spectrometry Tool in Old Wells
Authors: Mohamad Ak Yasmin , Snijder G L
Published: December 2007

The Seria field was discovered in 1929 and the present development concentrates on infill drainage and secondary recovery. The field consists of a number of faulted blocks and stacked reservoirs.

At the end of 1984, 196 wells out of a total of 750 were closed in for poor production and are candidates for recompletion on poorly drained or undrained reservoirs or for abandonment.

Cased hole logs, the Thermal Decay Time (TDT) and the Gamma-ray Spectrometry Tool (GST), have been used to investigate the fluid content behind casing in old closed-in wells prior to abandoning the existing completion. The TDT is used to identify gas bearing intervals, to optimise the GST logging, and the GST is used to identify unproduced oil.

Zones identified hydrocarbon bearing from the original open hole electrical logs and confirmed oil bearing with the GST have been successfully completed.

New operational and interpretation techniques have been developed and are presented in this paper together with some field results.
Son of Crossplot Fights Back
Authors: Cooke-Yarborough Piers
Published: December 2007

In 50-75% of reservoirs, porosity and lithology can be successfully determined by well log analysis using crossplot techniques. This method is particularly useful when the reservoir is a shaly sand or carbonate sequence. In complex lithologies, with an abundance of accessory minerals, the technique can produce erroneous results if applied without modifications to the standard model. The method is not intrinsically flexible and needs adaptation whenever the formation differs markedly from a sandstone/carbonate/shale model. Use of crossplots and iterative analytical solutions derived from two porosity logs sometimes gives unsatisfactory results in hydrocarbon-bearing complex lithologies.

With modifications, the crossplotting technique can describe 90% of South-East Asia's reservoirs. A more flexible approach and an improved presentation format for results is presented. Two or more shale indicators are chosen and calibrated with the resulting shale volume being a weighted avearge of the indicators. Porosity information from all porosity devices is displayed. A quality curve is shown, demonstrating how well the answers fit the chosen model. Lithology definition is achieved by the study of slowness ratio from the long-spaced sonic device, photoelectric effect from the litho-density tool, apparent grain density from crossplot data and electro facies analysis.

Moveable hydrocarbons and permeability in clastic reservoirs are indicated by the nuclear magnetism log, wireline formation tester, electromagnetic propagation tool, core analysis and the resistivity invasion profile. For carbonate reservoirs, fracture indicators are displayed.
Engineering Evaluation for Development of A Heavy Oil Reservoir in An Offshore Environment
Authors: Horne Jerrold S
Published: December 2007

An engineering evaluation was conducted to determine development feasibility of a heavy oil prospect located in the UK sector of the North Sea in 348 ft of water. The reservoir is located at approximately 3,000 ft. The matrix is highly unconsolidated and contains crude oil with a viscosity of 132 cps at reservoir conditions. In addition, the oil column is underlain and in direct contact with a large water zone.

The paper presents a procedure to evaluate a potential offshore field. The procedure uses reservoir, drilling, and operations engineering technology in developing a screening technique to determine how to proceed with evaluating the development.

Simulation was used to evaluate reservoir performance under depletion drive, natural influx, and water flood. Thermal and non-thermal enhanced oil recovery (EOR) methods were evaluated using analytical techniques. Results of the simulation and analytical techniques are presented. Results of sensitivity studies to determine the effect of aquifer strength, vertical communication, and production rate on ultimate recovery of the high viscosity oil are also presented. The impact of horizontal wellbores on ultimate recovery was determined by simulation. The effect of vertical location of the wellbore within the reservoir and wellbore length were modelled and results are presented.

Work required on the directional drilling and well test programs for the exploratory wells to evaluate the shallow, unconsolidated reservoir are discussed. The technique of drilling the proposed multiple drainhole wells is reviewed.

Production Systems Optimisation (PSO) was used to evaluate factors not normally considered in reservoir simulation. PSO is an analytical tool to calculate pressure losses as a function of rate from the reservoir to the stock tank. The objective of the analysis is to economically design the most efficient production system over the life of the well. Formulas used in the technique which are applicable to other fields are presented in the paper. The effect of pipe diameter, gravel pack permeability, and screen diameter on production rates are discussed. The effect of water production is also included.
The Revamp of Two 20-Year Old Drilling Platforms
Authors: En Lee Yin , Fullbrook Roger
Published: December 2007

The Ampa-1 and 2 platform complexes, installed in the mid 60s in 75 ft. water depth, were the first major offshore developments in the S.W. Ampa Field, 8 miles offshore Brunei.

In order to continue production and allow further development of the offshore South West Ampa oilfield reserves the original drilling and production platforms of the Ampa 1 and 2 Production complexes required replacement or major repairs because of general deterioration.

This paper describes the Ampa 1 and 2 Revamp project and the conclusions drawn from its successful completion with special emphasis on the technical achievements and safety precautions.
Implementation of the Malaysian Peninsular Gas Utilisation (PGU) Project
Authors: Salleh Hashim
Published: December 2007

The paper will discuss the philosophy and strategy in the implementation of the first stage of the Malaysian Peninsular Gas Utilisation Project. The focus will be on project management, technology transfer, local participation and the lessons from the experience. The project is implemented in three stages. Stage I, which involves the processing and delivery of gas within Terengganu is now completed. Stage II, which involves the piping of gas to the power stations in Port Kelang and Port Dickson and southward to Singapore is under initial implementation. Stage III, delivery to the north, will be implemented later.
Start-Up Experiences : North Rankin ‘A’ Platform
Authors: Glass Peter W
Published: December 2007

The North Rankin 'A' Platform has been in operation since May 1994 following an eighteen month period of Hook-up and Commissioning. This paper provides a summary of the organisation and activities associated with Hook-up, Commissioning and Start-up of the Platform Facilities and provides a number of examples of lessons.learnt from the Start-up process. Furthermore, significant ongoing problems and where relevant, their solutions are also highlighted.
A Correlation for the Viscosity of Light Normal Paraffin Hydrocarbon Systems
Authors: Gonzalez Mario H. , Bukacek Richard F.
Published: December 2007

This paper was prepared for the 41st Annual Fall Meeting of the Society of Petroleum Engineers of AIME, to held in Dallas, Tex., Oct. 2–5, 1966. 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 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.

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.

A graphical correlation of the viscosity data for normal paraffin hydrocarbons and their mixtures based on a pseudo-molecular weight is presented. The correlation reproduces experimental viscosity data for pure component, binary, and multi-component normal paraffin hydrocarbon systems with a standard deviation of +-5 per cent. The formula used to calculate the pseudo-molecular weight is presented together with a graphical representation of the correlation and tables of the smoothed values given by it.

Introduction

The existing data on the viscosity of hydrocarbon mixtures at high pressures are scarce and there exists a need for methods to enable estimation of the viscosity of these mixtures under the conditions of their production and processing. This paper presents a g graphical correlation for the viscosity of single and multi-component hydrocarbon systems. Special attention has been paid to that range of molecular weight in which the naturally occurring multi-component systems fall. The correlation represents a simple method of predicting the viscosity from a knowledge of the temperature, pressure and composition of the hydrocarbon system involved.

Background

The viscosity of hydrocarbons at pressure near atmospheric has been extensively studied over a wide range of temperatures. Less work has been devoted to the study of the pressure effect on viscosity, particularly because of the experimental difficulties involved. The scarcity of the available data and the infinite number of possible mixtures, either naturally occurring or man-made, have prompted several authors to investigate the use of theoretically or empirically derived correlations to generalize the existing data. The basis for these efforts have been either the assumption of simple molecular models, or selective use of the available data on a limited number of systems. The kinetic theory approach advanced by Enskog has been the most widely used theoretical basis for correlations. Discussions on the subject, together with proposed equations following this approach have been given by Colburn, Drew, and Worthington, Lype, Gardner, and Woolley, Scott and Brickwedde.
Modeling 4D Seismology
Authors: McDonald J. A. , Gardner G. H. F. , Tatalovic R.
Published: December 2007

The 3D (or areal) seismic technique has become more widely used as an exploration tool in the oil industry. Originally the technique was devised because it was recognized that geological features are, in the main, three-dimensional. The conventional planar CDP method could generate generalized regional information but out-of-plane data are not correctly imaged.

It soon became apparent that the 3D method could provide a means of mapping the areal extent of acoustic discontinuities in the subsurface. In addition it was seen that if the areal seismic data could be tied to data from at least one well in the area in the form of a VSP, not only the area but the volume of the discontinuity could be determined. It is therefore evident that 4D seismology (measurements in the x,y,z and t directions) can provide a very suitable and economical tool for determining the extent of a hydrocarbon accumulation prior to enhanced oil recovery.

The main problem with applying the techniques of 4D seismology to the real world is that the results can only be checked with the drill; a very expensive procedure. In addition the resolving power of the surface seismic method in measuring the simplest stratigraphic traps is barely understood. Therefore, the Seismic Acoustics Laboratory of the AGL at the University of Houston has initiated a research program in which 4D seismology techniques are being modeled physically. The aim is to provide the industry with some measure of the tool as an aid to enhanced oil recovery projects.

This paper will show some of the first measurements of the resolving power of the areal seismic method and how the resolving power can be affected by the geometry of the data collection and by the nature of the wave propogation in the media surrounding the hydrocarbon accumulation.
Causes of Problems and Losses in Petroleum Loans
Authors: Ryan Robert S.
Published: December 2007

This paper was prepared for the 41st Annual Fall Meeting of the Society of Petroleum Engineers of AIME, to held in Dallas, Tex., Oct. 2–5, 1966. 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 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.

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 objective of this paper is to learn more about why problems occur in oil and gas loans and what steps may be indicated to prevent or minimize future problems.

A survey, to which 30 institutions active in oil lending replied, furnished data and causes for 134 problem oil loans, Eighty-four of the oil loads cited are problems because of slow repayment and fifty of the cited loans have involved (or will involve) some degree of loss. A computer technique was developed to analyze the data and the resulting information about causes of problems in petroleum loans has not been hitherto available or previously published.

An analysis of the data shows the dominant causes for problem oil loans were:

Reserve estimates were too high Rate of production was forecast too high One Held loans (Lack of Diversification) Operators' financial failure Operators' failure to perform

Reserve errors, rate errors, and one held loans all seem to rank equally as dominant causes of problems. Reserve errors and production forecast errors are clearly engineering reasons and stand out throughout the survey findings. Other cause factors such as proration forecasts, market prices, and gas sales level aid not show up as significant causes of the problems reported on the survey.

The survey findings show that small lending institutions have had somewhat higher, loss experience than larger institutions. There also appears to be a relationship of higher loss experience with increasing size of the lenders' oil loan portfolio.

The paper discusses reasons for the results revealed by the survey findings and makes recommendations of methods to achieve more rigorous engineering analysis to prevent or minimize future problems.

Introduction

This paper is an outgrowth of a study which was prepared for the Graduate School of Credit and Financial Management at Stanford University.
Selection of Nonionic Surfactants for Minimized Adsorption and Maximized Solubilization
Authors: Lewis S. J. , Verkruyse L. A. , Salter S. J.
Published: December 2007

Adsorption values for mono-isomerically pure nonionic surfactants are shown here to depend upon the phase properties of the surfactant in aqueous solution. When the experimental conditions are referenced to the temperature at which the solution being employed phase separates, the adsorption values over a range of temperature, brine salinities and surfactant concentrations are observed to follow a consistent trend. This correlation is observed to be consistent for six surfactant molecules, over a range of solubility balance, both with and without aromatic rings. The observations reported here indicate that for applications requiring a particular optimal temperature, large linear ethoxylated alcohols are preferred to either smaller molecules or phenolic species.
Wilmington Field Steam Operations
Authors: Teberg J.A.
Published: December 2007

This paper was prepared for the 41st Annual Fall Meeting of the Society of Petroleum Engineers of AIME, to held in Dallas, Tex., Oct. 2–5, 1966. 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 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.

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.

Cyclic steam injection into wells producing low gravity oil has proven to be the most important stimulation method used in the Tidelands area of the Wilmington Field since waterflood. Substantial oil rate increases and very favorable economics are resulting from the steam injection program.

Oil rate increases of five to ten times are very common and may be sustained at three to four times the level of former production. Peak production rates, both gross and net, often exceed new well rates. Large lease areas as well as producing wells are rejuvenated by cyclic steaming.

Experience has indicated that oil can be recovered at or below per barrel cost when compared with pre-steam production rates. Therefore, production operations benefit from steam stimulation by the combination of rapid pay-out, low per barrel operating cost after pay-out and much less time for oil recovery. The timing for re-cycling is a very important factor in order to operate at minimum cost for oil recovery.

Cyclic steam injection was started in the Tidelands area in the Wilmington Field in February 1965. The initial injection site on Pier B included fourteen wells producing from the Tar zone, Fault Block V. This area was considered to be the most ideally suited for steaming because of the low gravity oil (12 deg to 159 API), low water cuts, high structural locations and favorable reservoir characteristics as well as a convenient surface location. Since the start of the project more then sixty wells have been steamed in the Tidelands.

Production after steaming may decline rapidly, however, the rate normally levels out considerably above the pre-steam production rate. Results obtained by re-steaming are definitely encouraging and show that the oil rate may be returned to the level stimulated by a previous steam cycle with a slower decline rate and greater economic benefits.

Effective stimulation by steaming is attributed to the lowering of viscosity of the oil by heat and to well bore clean-up. The effects of well bore clean-up appear to be the most important contribution to success, at least for the first cycle.
Well Stimulation by CO2 in the Heavy Oil Field of Camurlu in Turkey
Authors: Bardon C. P. , Karaoguz D. , Tholance M.
Published: December 2007

The Camurlu oil field, operated by the Turkish Petroleum Corporation (T.P.A.O) in Southeast Turkey, contains roughly 60 millions m3 (380 MMbbl) of a low gravity oil (10–12° API) in the "Alt Si nan" formation.

The poor quality of the oil, the heterogeneity of the reservoir and the presence of a large gas cap are responsible for the low primary recovery estimated at less than 1%.

The "Mus" formation, located beneath the oil-bearing reservoir, contains a CO2-rich natural gas (73%).

In 1983, these facts have led TPAO and the Institut Français du Pétrole to evaluate the stimulation of oil production wells with the CO2-rich gas using the Huff n'Puff technique. Two production wells, located as far as possible from the gas cap were selected at first.

The tests which started in 1984, consisted in the injection of a limited amount of CO2 (11 MMscf) followed by a short soaking time and a subsequent back-production. Early oil production figures showed a more than 5 fold increase over figures obtained prior CO2 injection.

This paper presents the results obtained on the two wells selected for the pilot test. Up to now two cycles of injection-production in each well have been performed.

Finally, the planned extension of the project to other wells is presented.