bluuebunny/crossref_metadata_2025 huggingface dataset:
Foamed Gas Lift
Authors: Bernadiner M. G.
Published: December 2007

Gas lift, a broadly applied method for producing oil, consists of gas injection into production wells to reduce the liquid density in the wells and increase the liquid inflow. Gas lift technology requires large gas volumes to be injected. If the reservoir pressure is depleted, the effectiveness of gas lift is dramatically reduced. To increase effectiveness and to extend gas lift applications to producing oil from depleted reservoirs, a foamed gas lift method has been investigated in laboratory and oilfield experiments. The method consists of foaming agent injection into a gas-liquid flow.

A laboratory set-up based on scaling parameters was used to study the productivity of the gas lift well exploiting the drainage area of the well. The laboratory experiments were performed over a wide range of the scaling parameter, describing the reservoir pressure depletion, with and without foaming agent. The results show that foamed gas lift would be efficient, especially if the gas lift well cannot produce without the addition of foaming agent. Analysis of the gas-liquid flow structure inside a vertical tube displayed the conditions of effective application of the foaming agent to improve gas lift technology. Oilfield experiments analyzed with probability theory corroborated that foamed gas lift is a very effective technological method if the reservoir is depleted
Improved Fracturing Techniques Increase Productivity in the AWP (Olmos) Field
Authors: Peard N. S. , Macaluso M. L. , Griffin M. C. , Andreas R. , Callanan M. J.
Published: December 2007

Early fracture treatments in the AWP (Olmos) field utilized over 1,000,000 lbs. of 20/40 mesh Ottawa sand. While production results were good, mechanical problems and economic factors necessitated alternative treatments. Smaller volume schedules were tried, but the resulting production lagged the larger jobs. Recently, treatments designed with resin coated sand (RCS) improved well performance. The stronger RCS maintains better conductivity at lower proppant concentrations with resultant good production response at a lower total cost. As an additional benefit, the curable RCS bonds together to eliminate proppant flowback.
Radial Modeling of In-Situ Gelation in Porous Media
Authors: Todd B. J. , Willhite G. P. , Green D. W.
Published: December 2007

A new radial model of in situ gelation of Polyacrylamide by Cr(III) produced by a redox reaction has been developed based on reaction kinetics describing the crosslinking and aggregation in the gelling solution, coupled with filtration equations governing the deposition of polymer on the porous medium. The gel system is based on the reaction of Cr(VI) with thiourea to produce Cr (III). Gelation occurs when Cr (III) reacts with Polyacrylamide. The radial model is an extension of a linear displacement model (SPE 20215). The linear model was tested against displacement data and matching parameters in the model were determined by regression. These parameters were then used in the radial model to simulate cases of practical importance.

The radial model describes gelation behavior during the period of gel solution injection and the subsequent shut-in period. During the injection phase, a buildup of flow resistance occurs in the presence of radial flow, i.e., a variable shear field. After shut-in, continued reaction of the gelling solution is simulated under conditions of zero shear. These features allow simulation of a complete gelation treatment from the injection phase through the shut-in period. Using this model, ranges of injection rates, pH, and injection and shut-in times are investigated. The pH history of the gel solution was found to be an important variable in the gelation process. If reservoir pH is in the vicinity of 8.0, gelation is retarded and long shut-in periods are required to develop adequate gel properties for permeability modification. The effects of reservoir pH can be offset by increasing the pH and the concentration of the reducing agent in the gel solution.

A simulation of a three-layer system maintained at constant pressure drop was conducted to illustrate the capability of the model. Permeabilities of the three layers varied from 0.035 to 3.5 darcies. For the gel system simulated, all layers became plugged to some extent during the injection phase. Depth of gel penetration was dependent upon the permeability of the interval. In the lowest permeability zone, the affected region was within the range where remedial treatment after gelation might remove the gelled zone. These results suggest that isolation of high permeability zones is required for in-depth permeability modification using the gel system examined in this study.
A Case Study of Plastic Plugbacks on Gravel Packed Wells in the Gulf of Mexico
Authors: Rice R. T.
Published: December 2007

A high success rate of water reduction has been documented in 21 plugback jobs performed on gravel packed wells in the Gulf of Mexico. This electric wireline plugback method was first introduced by Carroll and Bullen1 (SPE 18228) at the 1988 SPE Technical Conference in Houston. The plugback method is unique in that it is performed within gravel pack assemblies and utilizes plastic instead of cement.

This paper is a case study on actual field results for the 21 jobs performed by Tenneco/Chevron since the introduction of this method.
Fluid Mechanical Analysis for Control of Gravel Pack Jobs
Authors: Harestad K. , Saasen A. , Sterri N.
Published: December 2007

This paper presents an analysis of the pump pressure while pumping gravel pack slurry down into the well. Five field cases from the Troll field in the North Sea are evaluated. The rheological behaviour of the prepad and gravel pack slurries have been investigated. The pump pressures have been simulated by fluid mechanical analysis and are compared with measured values.
The Prediction of Operating Conditions to Constrain Sand Production from a Gas Well
Authors: Wang Zhihua , Peden J. M. , Damasena E. S. H.
Published: December 2007

This paper presents an analytical model for predicting the sanding tendency of a gas well. The onset of sand production in a cased well may result from the failure of the perforation tunnel to withstand both the in-situ stress and the flow/production induced stresses. The failure conditions of a cylindrical perforation tunnel subject to single phase gas flow in a friable sandstone formation, have been studied using elastoplastic stress analysis. The failure criterion employed in this paper is the critical equivalent plastic strain, which is the maximum plastic strain that can be sustained without failure and consequent sand production.

The effects of various production conditions have been evaluated by considering the pore pressure distribution associated with the production of gas. The results demonstrate that the flow of gas in the perforation tunnel tends to increase the instability, however compared to standard Darcy flow conditions, the inclusion of the non-Darcy flow effect due to high production rate, will significantly increase the instability. The effect on stability of the tunnel geometry, rock deformation and strength have been studied to assist in the evaluation of the influence of perforation geometry, in terms of shot density and phasing, on sand instability. The results show that an optimum perforation geometry requires a compromise between the productivity ratio and cavity stability.

The results obtained by running the model against a North Sea gas reservoir demonstrate that the model is a useful tool for designing sand free production completions or alternatively assessing the sensitivity of the sanding tendency to operational parameters.
Cement Expansion: A Laboratory Investigation
Authors: Moran L. K. , Murray T. R. , Moyer W. R.
Published: December 2007

A cement which expands (or at least does not contract) under down-hole conditions can prevent microannular flow and can make bond log interpretation easier.

A comprehensive laboratory investigation of cement expansion using the most common cement expansion additives, calcium sulfate and sodium sulfate, was performed. Four API classes of cement were investigated from 75° to 200°F at pressures from atmospheric to 5000 psi. The slurries were cured in air, water, oil, and 100 percent humidity environments. The cements were mixed with three water contents. The expansion measurements were taken for ten days. The expansion measurements were of the type which measure the exterior dimensions of a cement sample as it cures.

The various curing environments are meant to simulate the curing environments experienced downhole. For instance, wells drilled with oil base mud would leave the wellbore area inundated with oil and thus the cement would be exposed to oil and not water during the curing period.

Several new additives for cement expansion have recently been introduced from the cementing service companies. Now that a thorough background study on existing materials has been completed, new materials can be more easily evaluated.
Effective Uses of Information Systems
Authors: Raleigh J.T. , Baca A. , Hingorani G.
Published: December 2007

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

This paper was prepared for the 43rd Annual Fall Meeting of the Society of Petroleum Engineers of AIME, to be held in Houston, Tex., Sept. 29-Oct. 2, 1968. 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.

This paper presents a user's view of some applications and pitfalls of an operational information system. This system was initiated in 1960 by the Gas Supply Division of an interstate gas pipeline company to calculate and maintain dedicated gas reserves by well. This basic file included identification data, dedicated lease interest as well as reservoir parameters. From this small beginning, the data parameters. From this small beginning, the data file concept has mushroomed and now includes six separate files with data from contract information and price of gas to well test scheduling.

As these files were developed, many programs were written to utilize the data stored programs were written to utilize the data stored in them. Two of these programs are discussed in some detail. These are an individual well by well, availability project to determine total contracted supply with respect to market requirements. The second project is a macroscopic management oriented tool to investigate alternative supply operation plans depending on varying market requirements and purchase contract negotiations and timing. This program has a number of levels of output. In addition to programs, a number of retrieval routines are run on request to provide up-to-date information on the most important data items.

Immediate plans require program development in order to tie the large detailed computerized data base into management information requirements. Future plans are to make the information systems available to all potential users in the company such as the Gas Control function. Remote access devices will use massive data banks to permit operating control from widely scattered field stations through a central executive control system.

An information system has been developed and applied to important engineering and management problems. problems.
Determination of Formation Temperature From Flow Tests: A New Solution
Authors: Kashikar S. V. , Arnold F. C.
Published: December 2007

Determination of accurate formation temperature is needed for drilling fluid and cement slurry design, determination of geo thermal gradients and geo thermal reservoir evaluation. Almost all known methods to determine the formation temperature are based on shut-in temperature recordings. All these methods require long shut-in periods and result in estimates which are lower than the true reservoir temperature.

A new method has been developed that utilizes temperature recordings from short time flow tests to accurately determine formation temperatures, The temperature distribution prior to production was obtained by solving the diffusivity equation for conductive heat transfer during the circulation period. This provided the initial condition for solving the continuity equation for convective heat transfer during production by the method of characteristics. The application of the above solution is shown with a field example.
A Management System for Gas-Gathering Systems
Authors: Butler T. G. , Hedges R. C. , Gonsalves L. , Bowlin N. S.
Published: December 2007

Computing technology is applied to improve procedures for managing a gas gathering system by providing information, reports, and analysis to support decision making. The system includes handheld computer terminals, a plant office personal computer, and an interface to upload and download information from a company gas measurement database.

Handheld computer terminals are used in acquiring meter calibration, gas measurement, and physical change data to eliminate paper as the primary means of data transfer. At the end of the work day all data collected is uploaded to a personal computer database in the plant office. The information is easily accessible for analysis and report generation.

A communications datalink is used to transfer information between the plant office PC and the company orifice meter database. When information is downloaded to the plant office PC, volume and pressure trending of sections of the pipeline can be displayed to assist in determining pipeline efficiency. In addition, a more timely and efficient method of updating the orifice meter database is performed by uploading information directly from the PC. Data related to physical changes normally recorded when charts are integrated is now recorded on the day that the orifice meter is actually changed.

Benefits derived from using this system are quickly realized. Manually produced reports are replaced with automatically generated reports. More efficient use is made of field and office personnel. Supervisors more effectively monitor the gathering system since quick access to data and report generation assist them in controlling production and determining problems within the pipeline.
Operational Techniques to Improve the Performance of In-Situ Combustion in Heavy-Oil and Oil-Sand Reservoirs
Authors: Hallam R. J.
Published: December 2007

When the in-situ combustion process is used in heavy oil and oil sand reservoirs the frontal displacement is not propagated in a uniform manner due to channeling. To improve the performance, the operating strategies have to be modified in order to control or use the channeling as an advantage. The operational procedures used in these strategies include pressure cycling, injection rate control, the use of oxygen, fracturing and production well stimulations. These procedures can, however, serve different purposes in heavy oil and oil sand reservoirs. In this paper, the procedures are reviewed and the recovery mechanisms are discussed. Field and laboratory results are presented to explain the recovery mechanisms associated with each procedure.
Waterflooding a Sandstone Reservoir With a Mobile Gas Saturation: Sooner Unit Field Case History
Authors: Hayworth W. R.
Published: December 2007

The Sooner Unit produces a volatile crude oil from a low permeability Cretaceous sandstone reservoir. Primary production resulted in a gas saturation estimated to exceed 20% of pore volume.

Modelling studies, analysis of similar reservoirs, and Sooner Unit production history have demonstrated a need to repressure the reservoir prior to displacement under "steady state" conditions. The principal benefit to displacement at high pressure is derived from the ability to manage gas saturation and reservoir voidage and prevent early water breakthrough. The effect of reduced oil viscosity and lower mobility ratio at high pressure is of minor significance.

Repressurization of the reservoir has been accelerated recently by the initiation of gas injection.
Logging and Perforating of Horizontal Wells: An Innovative Approach
Authors: Hall D. J. , Walker J. L. , Schmelzl E. G. , Haêne T. B.
Published: December 2007

This paper describes a system designed by Pan Canadian Petroleum Ltd., Jet Research Centre Inc., Halliburton Logging Services and Halliburton Services Ltd. to perforate a horizontal well in East Central Alberta. This system is unique in that it allows circulation to the bottom of the tool string throughout the logging and perforating operations (ie. before and after detonation). Foam was used as the circulation fluid to remove sand from the horizontal section and allow the logging and perforating tools to be run. These tools were attached to reeled tubing with electric line inside to facilitate running in the horizontal section with energized fluid.
Geologic Controls on Reservoir Properties of Frontier Formation Low-Permeability Gas Reservoirs, Moxa Arch, Wyoming
Authors: Dutton S. P. , Hamlin H. S.
Published: December 2007

The Upper Cretaceous Frontier Formation, a low-permeability gas reservoir in southwestern Wyoming, comprises marine and nonmarine fades deposited in a fluvial-deltaic depositional system. Reservoir quality of Frontier sandstones is determined in part by detrital clay content, which is related to original depositional environment, and in part by subsequent diagenetic modifications during burial. In this study, regional thickness and continuity of Frontier sandstones were mapped along the Moxa Arch from the La Barge Platform to the Utah border, using more than 700 well logs and cores from 10 wells. Many of the Frontier sandstones (First, Third, and Fourth Frontier intervals) are discontinuous and occur only at the northern end of the Moxa Arch where the formation is up to 1,500 ft (460 m) thick. The Second Frontier interval, however, is present along the entire Moxa Arch and contains the most prolific Frontier gas reservoirs. Clean sandstone is variably developed within the Second Frontier and commonly lies in laterally continuous marine shoreface fades and discontinuous fluvial channel-fill fades. Clean sandstone geometries are inherited from the depositional environment. Unstressed permeability to air averages 0.83 md in 47 upper-shoreface sandstones, 0.12 md in 232 lower-shoref ace sandstones, and 0.39 md in 120 fluvial channel-fill sandstones.

According to pétrographie examination of 151 thin sections, Frontier sandstones are fine- to medium-grained litharenites and sublitharenites having an average composition of 65% quartz, 4% feldspar, and 31% rock fragments. Clean sandstones contain an average of 1.8% primary intergranular porosity and 4.6% secondary porosity formed by dissolution of feldspar, chert, and mudstone clasts. Microporosity, estimated as the difference between porosimeter and thin-section porosity, averages 6%. Calcite, quartz, mixed-layer illite-smectite, illite, chlorite, and kaolinite are the most abundant cements. Authigenic mixed-layer clays consist of about 80% illite layers, suggesting that clays may be only moderately sensitive to fresh water. Low permeability in Frontier sandstones is caused by (1) loss of porosity due to compaction, (2) occlusion of pores by cements, particularly caldte and quartz, and (3) lining of primary pores by fibrous illite-smectite.
Friction Pressure Correlation for CO2 Foam Fluids
Authors: Tan H. C. S. , McGowen J. M.
Published: December 2007

An empirical correlation for predicting tubular friction pressure for CO2-energized fluids has been derived from both field and laboratory data. This correlation takes into account the effect of crosslinking behavior of the liquid phase on friction pressure. Therefore, it can be used for treatments where CO2-energized fluids are used in conjunction with delayed or rapid crosslinked fluids. The correlation was incorporated into a real time computer program used to calculate bottomhole treating pressure on-site during fracturing treatments with CO2-energized fluids. Several case histories were used to evaluate the correlation. The results presented in this paper have shown significant improvement in predicting the friction pressure for CO2-energized fluids as compared to existing correlations being used in the oil industry.
The Effects of Microfractures on Directional Permeability in Tight Gas Sands
Authors: Hyman L. A. , Malek D. J. , Admire C. A. , Walls J. D.
Published: December 2007

The objectives of this study were to reveal the existence of microfractures in tight gas sands and to investigate their effects on directional permeability. The knowledge of the orientation of microfractures and their impact on directional permeability could influence various reservoir engineering applications involved in developing tight gas sands. This study has been accomplished by analyzing and comparing the results of directional permeability measurements to acoustic velocity anisotropy and pétrographie analyses.

Both natural and stress relaxation (induced) microfractures were observed in all three tight gas formations analyzed: Cotton Valley, Travis Peak and the Frontier Formations. This study indicates that compressional velocity measurements and thin section analyses should be integrated to define the orientation of the microfractures. Induced microfractures appear to close under confining stress and consequently, permeability anisotropy measured at in-situ pressure has been interpreted to not be influenced by induced microfractures. The influence of natural microfractures on permeability anisotropy in tight gas sands was observed to be dependent on the degree and type of cementation and the pore network.
A Study of the Factors Influencing Well Productivity of the "J" and Codell Reservoirs
Authors: Donovan W. S.
Published: December 2007

A statistical study of "J" and Codell wells in the Denver-Julesburg (D-J) Basin was undertaken to determine which parameters influence well productivity. The parameters reviewed were open hole logging parameters and operational parameters. Parameters such as zone thickness, porosity, water saturation, shale indicators and the size of the hydraulic fracture treatment were reviewed. These parameters were chosen because they: 1) may be related to well productivity; 2) are easily obtainable from public sources; and 3) are related to theoretical hydraulic fracture models.

A non-linear multi-variate regression analysis was used in this study. The variables used in the regression analysis can be related to the variables in the "uniform flux fracture" model.

The results of the regression analysis can be used; 1) to determine which parameters are most correlative to well productivity, 2) to determine the relative magnitude of the parameters's influence and 3) the degree of certainty of the correlation.

The application of regression analysis determined which log characteristics are correlative with well productivity, quantified the influence of each parameter and quantify the degree of uncertainty. Regression analysis can be applied to reservoirs which are not amenable to conventional analysis.
An Analysis of Gas Kick Removal From the Marine Riser
Authors: Santos O. L. A. , Lima H. R. de Paula , Bourgoyne A. T.
Published: December 2007

This paper presents an analysis of the dynamic pressures imposed on the marine riser and diverter line during the gas removal from a riser-diverter system. The occurrence of formation gas in the riser may lead to a drilling accident known as "riser blowout" that can cause the collapse of the riser pipe in addition to the inherent risk of fire.

This analysis makes use of a numerical simulator, detailed in this study, that models the pressure and flow rate behavior in the riser-diverter system. The simulator is based on the numerical solution of a system of flow equations for a two-phase mixture moving upward in the riser-drill pipe annulus. The model accounts for the acceleration of the drilling fluid flowing ahead the two-phase mixture and the sonic flow at the diverter line exit.

In this paper, the approach of circulating a fluid through the lower portion of the marine riser to displace the gas up and inside the riser and diverter system is extensively investigated. Through a sensitivity analysis, the effects of pertinent parameters – especially the circulation rate – on the pressures generated inside the riser-diverter system during the gas removal process are discussed. Non-circulation situations are also studied.
The Design and Application of High-Yield Strength, Sour Service Casing In High Pressure High Temperature North Sea Wells
Authors: Marshall D. W. , Robertson I. R.
Published: December 2007

Enterprise Oil pic currently is involved as operator for a number of high temperature, high pressure wells in the Central North Sea to depths in excess of 17,000 ft (5200m). A crucial factor in the successful design and drilling of such wells is the casing design particularly in light of the severe requirements of the UK Department of Energy.

This paper examines how the casing design for such wells has been optimised by Enterprise Oil by the use of 110,000 psi (758MPa) minimum internal yield strength, sour service casing. In addition, the specifications for the manufacture and inspection of such casing are reviewed and a discussion on the limitations of the existing NACE guidelines presented.
Important Aspects of Well Control for Horizontal Drilling Including Deepwater Situations
Authors: Santos O. L. A.
Published: December 2007

The drilling of horizontal wells to improve oil and gas recovery and productivity has quickly become one of the most important and promising technology of the oil industry. This is reflected by the considerable number of technical papers published on this subject. Although these papers have been covered a great deal of aspects of horizontal drilling, one important subject remains almost unexplored: the well pressure control.

The scope of this paper is to show important facets of the well control for horizontal wells, especially for deepwater ones, and to highlight some design and operational aspects to make the horizontal drilling safer. One important point analyzed in this paper was the pressure behavior inside a horizontal wellbore during a gas kick removal process. For this analysis, a numerical simulator of a gas kick based on the unsteady state flow of a two-phase mixture (gas and mud) has been developed and used to predict pressure at any point of the wellbore-choke line system. It has also been used to compute and to analyze the kick tolerance during the gas kick circulation process.

Some other relevant points of the well control operation for horizontal wells that differ from those for vertical wells were also investigated.They include:swabbing effect when tripping out of the hole,shut-in pressures and pit gain,drillpipe pressure schedule during the kick removal process,and mud density design.
Relief Well Contingency Drilling Plans for Remote Areas
Authors: Pidcock G. A. , Fowler D. R.
Published: December 2007

This paper reviews the rationale and content of relief well plans for remote areas. As with many industry related contingency plans there is an increasing need to ensure these plans are well organized, practical and efficient for an unlikely event such as a blowout. This report highlights one such plan developed for floating drilling operations in the Canadian Beaufort Sea. This remote area presents many technical, logistical and seasonal constrains that require special consideration.
Laboratory and Field Testing of an Ultra-High-Pressure, Jet-Assisted Drilling System
Authors: Kolle J. J. , Otta R. , Stang D. L.
Published: December 2007

Small-scale laboratory tests of an ultrahigh-pressure jet-assisted drilling system have been carried out in a pressure drilling test stand. Increases in the penetration rate are greatest in permeable rock and are proportional to the hydraulic pressure. The results of field tests with the drilling system are consistent with those obtained in the laboratory.
DD&A: Its Impact and Influence on Investment Decisions
Authors: Campbell J. M.
Published: December 2007

This paper gives a review of some basic accounting concepts designed to provide an engineer sufficient background to understand DD&A – depreciation, depletion and amortization, and its impact on a company's financials. Examples are provided to

demonstrate how different investments generate different amounts of DD&A expense and how this, in turn, affects a company's cash flow and net income. DD&A and its effect on a company's financial books is often a mysterious and misunderstood area for engineers. However, many engineers find themselves in management positions where they need to understand DD&A and how it affects net income – an obvious financial index on which stockholders and analysts focus. Should investment decisions be driven by DD&A considerations? The answer is "maybe" – it depends on the situation.
Parametric Estimating of Oil and Gas Production Facilities Capital Costs Worldwide
Authors: Karlik C. W.
Published: December 2007

A methodology for a parametric approach to estimating facilities costs worldwide for new ventures is presented. Screening estimates then can be made with minimal data and in a timely manner.

Development of a parametric approach consists of four phases: (1) The identification of sources of data and the gathering of that data; (2) Sorting of data; (3) The mathematical analysis of that data to quantify relationships that are intuitive; and (4) Reporting and updating of results periodically.

Observations include a review of how "estimates of estimates" produce an effective means of determining the future cost of new venture facilities. Parameters considered in providing estimates include, but are not limited to, recoverable reserves, peak production rates, location (onshore or offshore), terrain, water depth, distance to infrastructure, etc. Expert systems/actual costs also generate databases for this methodology.

At the same time, awareness of when certain parameters are not significant in determining capital costs is discussed. Elaboration on how precision does not equal accuracy is presented; many parameters are needlessly considered in new venture economic assessments.

The major results of this effort are the ability to estimate facilities costs, thus addressing multiple scenarios for future oil and gas development and the capacity to efficiently screen estimates related to new venture opportunities.
Price Effects on Developmental Well Completions, Reserve Additions, and Oil Production in West Texas
Authors: Holtz M. H. , Beike D. K.
Published: December 2007

Ninety-seven percent of the oil reserve additions in West Texas during the 1980's are attributable to development and redevelopment of existing reservoirs. This reserve growth occurred during a large fluctuation in deregulated oil prices. Therefore, the 1980's provide a time period in which models can be developed to determine the effects of deregulated oil prices on reserve growth and thus the oil supply from West Texas.

In 1981, price deregulation within the United States resulted in an oil market in which the West Texas oil supply became sensitive to world oil price. The economic factors controlling West Texas oil supply varied widely during the subsequent decade. Average annual oil price ranged from $10.40 to $33.80 (1982 $). Average well-drilling costs ranged from $29.12 to $74.40 (1982 $) per foot. At the same time, inflation ranged from 5 to 12 percent, while the annual average real prime interest rate ranged from 4.6 to 10.6 percent. These economic factors were the basis for investment decisions that resulted in 35,600 development well completions, 4,452 million stock-tankbarrels(MMSTB) of developmental reserve additions, and 4,689 MMSTB of oil production during the 1980's in West Texas.

During the 1980's, oil price controlled the number of development well completions, the amount of developmental reserve additions, and oil production in West Texas. The oil price increases of the early 1980's resulted in increased reserve additions after an initial time lag; that is, annual reserve additions declined for the first two years of the decade, and increased in 1983. The number of development wells completed and the amount of oil production also display a time lag. In contrast, drilling costs and drilling rig utilization rose immediately after this price increase. In the second half of the 1980's with the sharply decreasing price in 1986, an immediate and concomitant decline in rig utilization, development well completions, and reserve additions occurred. Between 1985 and 1986, annual reserve additions declined from 744 to 174 MMSTB (nearly 75 percent) before recovering to approximately 540 MMSTB in the latter part of the decade. Thus, there was a time lag in the response of oil supply parameters to price increases but not to sharp price decreases. This time lag is related to supply and demand mechanisms controlling a deregulated oil price. It also provides insight into the assessment of how future oil price variations will affect the West Texas oil supply.
An Approach to Assessing Risk in Coalbed Methane Prospect Evaluation
Authors: Vanorsdale C. R.
Published: December 2007

The economic evaluation of drilling prospects requires assessing the degree of risk involved and its impact on reserve estimates. In developed areas, risk can be determined in a fairly straightforward manner. In remote wildcat areas, risk can almost never be adequately identified or quantified. Between these extremes lie complex reservoirs -- reservoirs so heterogeneous that each well drilled could exhibit production characteristics unlike those of its neighbors.

This paper illustrates the use of a risk assessment methodology in a case study of Fruitland coal prospects in the San Juan Basin of New Mexico. This approach could be applied to coalbed methane prospects or any unconventional or highly heterogeneous reservoir with appropriate modification. The utility of this approach is made apparent in a graphical analysis that relates reserves, rate of return and payout time for managerial or financial presentation. This graphical technique and the underlying risk assessment were used to aid a conservative management team in evaluating participation in a multi-well coalbed project.
Innovative Technologies Reduce Cost of Offshore Marginal Field Developments in Northwestern Europe
Authors: Giannesini J-F. , Champion D. , Badour D.
Published: December 2007

This paper examines the characteristics of as yet undeveloped North Sea discoveries and shows that a significant number of fields will be able to benefit from the development of new production systems integrating, in particular, the advantages of horizontal drilling and multi-phase production. A detailed analysis of the northwestern Europe offshore discoveries shows that, by the end of this century and the beginning of the next one, North Sea operators will have to focus on increasingly small accumulations located in medium water depths and generally not too far from existing installations.

Those for which the distance to an existing or scheduled installation is less than about 15 km could be candidates for satellite development as it is now conceived. However, production from the discoveries located farther away than conventional tie-in distances will require new production systems to be used.

The different economic simulations described in this paper show that, for most of the fields considered, conventional development is not well suited because it is economically risky, even if new techniques such as horizontal drilling are used to bring about an appreciable improvement in their cost effectiveness.

New development methods will thus have to be created. For example, by combining a light floating support with a multi-phase pumping system and horizontal wells, the study case we have used shows that the technical cost of the oil can be reduced by 25%, while the internal rate of return can be multiplied fourfold compared to conventional development.

In the years to come, systems of this type will enable North Sea operators to considerably widen the fields of application of satellite development and thus make production from numerous fields that have been neglected in the past economically cost effective.
A Comparative Evaluation of Evolving Nigerian Petroleum Development Policies
Authors: Chukwu P. O. , Ikoku C. U.
Published: December 2007

This paper examines how the desires of the Nigerian government as expressed in the Petroleum Development policies have acted as incentives or disincentives to further investment in oil field development in the face of uncertain economic environmental conditions and reserve sizes.

An economic analysis package was used in evaluating past and present fiscal and contractual policies. The Net Present Values (NPV) of large, medium and small hypothetic fields were computed for the principal environments of oil exploitation (onshore and offshore) in the Niger Delta. This was done for various policy combinations to determine the sensitivity of the policy based profitability to oil price, production cost, delay in field development and production, operating companies share of profit and discount rates. The results were analysed and the attractiveness of policy packages to new investors were compared and ranked.

It concludes that Government policies have evolved to diminish the profitability of investors from oil exploitation. The present policies would require incentives to attract new investors unless production costs are reduced, oil prices rise and medium to large fields are the most likely to be discovered. New entrants that have to "carry" government operate under the worst policies are not likely to be attracted under existing situations.
The Option between Exploration or Reserve Purchasing: The Argentine Case
Authors: Fidalgo S. J.
Published: December 2007

An oil company that wants to increase its reserves has a first decision to make: the way to do it. Is it better to invest in exploration than to acquire reserves that have been already proved by rival companies? The market has been inclined to both options alternatively.

The 80's found the companies with a high cash flow as a consequence of the oil shocks that characterized the previous years. That circumstance as much as the expectations of a lower increase in prices in the medium range, favoured the purchases of reserves. Now, the situation seems to be reverted. This paper tries to find out what are the determinants that make an enterprise decide whether purchasing or exploring is better.

A good oportunity to analize these variables is given by the facts in which Argentina was involved between 1989–1990.

After several years of nonexistent growth in the oil industry, in 1985 Argentine administration announced a large exploration program for private companies. Most exploration agreements were signed in 1989.

On the other hand, YPF, the state petroleum company, auctioned to international buyers 38 oil fields. The purchase ended in July 1990. In view of this, some companies chose exploration while others decided in favour of investment in YPF fields.

After theoretical treatment of the elements that are the basis on which exploration and purchase is evaluated, this was confronted with the variables that the managers of those companies projected in order to prove its use in reality.
Risk Analysis Implications for U.K. North Sea Exploration and Development
Authors: Antia D. D. J.
Published: December 2007

The integration of parametric and nonparametric Monte Carlo risk analysis techniques with:- EDNP (Expected Discounted Net Profit) AnalysisAdvanced Tax Analysis TechniquesTailored Product DesignAppropriate cost and production structures.

can be used to rapidly:- Screen acreage and geological playsDefine the risk-return relationships associated with future explorationDetermine the optimum values for interest swaps, sale, purchase, farmin/farmouts, and work program bidsScreen different development optionsDetermine commercial success risks and economic return varianceDetermine the impact of significant oil/gas price changes on the relative profitability and risk-return relationships of different areas of the North Sea.

In the UK North Sea, a Monte Carlo EDNP analysis has been used to demonstrate how the technique can be used to rapidly:- Assess exploration acreageIdentify exploration risk-return relationships and identify under exploited playsAssess the impact of changing cost structures on a field's net returnAssess the relative worth of production units, fields, and acreage for acquisition and divestment.
Natural Gas Reserve Additions: Recent Trends and Future Potential in the Lower 48 States
Authors: Finley R. J. , Fisher W. J.
Published: December 2007

The mature lower 48 states continue to yield substantial quantities of natural gas. Onshore reserve additions are dominated by reserve growth, indicating the increasing efficiency of conversion of infield resources to reserves. Total natural gas reserve additions for the 1980's will nearly equal the additions of the best decades of the 1950's and 1960's. Although significantly more wells were required in the 1980's, total additions have been stable for the last two decades at about 1.2 Bcf (34.0 MMcm) per well, and in 1986-88, additions averaged 2.1 Bcf (28.3 MMcm) per well. Disaggregation of 11 years (1979-89) of data for onshore less Appalachian (seven major producing states), Appalachian, and offshore areas shows that average onshore nonassociated gas per reserve growth completion has doubled from 1979-85 (0.9Bcf [25.5 MMcm]) to 1986-89 (2.2 Bcf [62.3 MMcm]). Appalachian region reserve growth has increased in these same periods from 0.07 to 0.13 Bcf/completion (2.0 to 3.7 MMcm/completion), but overall additions are not in proportion to the one-quarter of onshore reserve growth drilling in that region. Onshore reserve growth (adjustments, net revisions, extensions, and new reservoirs in old fields) has increased from an average 81 percent of production in 1979-85 to 92 percent in 1986-89.

Onshore net revisions became positive in 1983 and have steadily increased over seven years, the greatest gains occurring in 1986-89 even after discounting major positive revisions in Kansas in 1986 and in New Mexico in 1988. This discounting actually took place in 1989 data for western New Mexico (-2.133 Tcf [-60.4 Bcm]), but otherwise net revisions for major onshore producing states remained strong at +2.733 Tcf (+77.4 Bcm), or 98 percent of the 1988 level. Net revisions per onshore development completion reached 0.8 Bcf (22.7 MMcm) in 1986-89 from one-fifth or less of that level in 1979-85. It is these net positive revisions that probably most closely reflect recompletion and infill drilling of bypassed gas zones and incompletely drained compartments as mechanisms for extended nonassociated gas reserve growth based on depositional heterogeneity. The resource associated with this development is nearly 120 Tcf (3.40 Tcm) in the lower 48 states, about one-half of which (56 Tcf [1.59 Tcm]) is judged accessible at a wellhead price of <$3.24/Mcf (1989$). Near-term supply-demand balance resulting in annual average wellhead prices of $2.25 to $2.50/Mcf (1990$) and realization that a substantial resource remains accessible, although in smaller increments, would allow continued efficiencies in extraction to meet market requirements into the 1990's.
Competitive Bidding for Oil and Gas Production Assets: How the Pie is Divided
Authors: Lohrenz J.
Published: December 2007

Competitive bidders for oil and gas production assets seek to divide shares of "pies" of unknown value that each asset represents. Unlike with real pies, however, bidders' strategies can easily imply an expected negative share and the seller can reap more than 100% of the unknown asset values.
Environmental Control of Drilling Mud Discharge Through Dewatering in Cold Weather Climates: Effect of Ambient Temperature
Authors: Wojtanowicz A. K. , Ye Yawen
Published: December 2007

The paper presents results of an experimental study into the effect of drilling mud temperature upon the dewatering performance. Three temperature ranges were considered: from flowline temperature to room temperature, from room temperature to freezing point, and the freeze (-4°F)/thaw (54°F) cycle. The tested drilling fluids included unweighted and weighted fresh water muds and a weighted salt water mud.

A sealed laboratory batch reactor was used in the experiments to prevent rapid vaporization of separated water at temperatures above 140°F. Also, ice or ice-salt baths were utilized for deep freezing. The dewaterability (net water removal) was measured with a bench-top plate press under constant expression pressure 30 psi.

The freeze/thaw treatment greatly enhanced dewaterability by releasing 34-39% by volume of the mud water. Mechanical dewatering followed; it required half the chemicals and released an additional 36-43% of water. The process proved to be very effective, reducing waste mud volume by 64-72%. It also seemed to be well-suited for the Arctic with its natural freeze/thaw cycles.

The results of experiments at temperatures above 70°F showed that there is little advantage to dewatering hot drilling mud diverted from active system. A 10% increase of water removal was observed above 140°F.

The experiments at temperatures below 70°F showed that in cold weather climates the waste drilling mud diverted from active system should be dewatered when its temperature is still above 40°F. Otherwise, more chemicals will be needed for separation enhancement or the dewatering process will become entirely ineffective.