bluuebunny/crossref_metadata_2025_split huggingface dataset:
Using Reservoir Simulation To Evaluate Operating Strategies in the Long Beach Unit
Authors: Skinner R. J. , Ames L. C. , Henderson C. P. 
Published: December 2007

Abstract
In 1985 the City of Long Beach initiated a series of reservoir simulation studies within the Long Beach Unit (Unit). The Unit, located in the Wilmington Field, California, is estimated to have contained 3.1 billion barrels of original oil in place. Since the Unit was formed in 1965 approximately 700 million barrels of oil have been recovered. A rapid decline in oil production warranted the need for a detailed study. Of key concern was the known areas of the field that have not been swept efficiently by waterflooding. Evidence from water injection profiles and new well saturations indicated significant reserves were being left behind and that there was potential to improve recovery performance. Reservoir simulation was used as a tool to identify areas of prospective remaining reserves, and to determine an optimum operating strategy to recover those reserves. Because of the large volume of oil in place, only a small percentage increase in recovery would translate to millions of dollars in revenue.
Complexities of Using Neural Network in Well Test Analysis of Faulted Reservoirs
Authors: Juniardi I. R. , Ershaghi Iraj 
Published: December 2007

Abstract
Neural networks models bring a significant dimension to the capability of computer aided approaches for well test analysis. This study shows, however, that when dealing with complex reservoirs, these models need augmentation from an expert system containing two types of information; independent field data and tables containing frequency of occurence of non-related models. A Monte Carlo Simulation method is proposed to provide the augmented statistical informations required for the expert system.
A 3-Dimensional Approach to the Modelling of the Hoadley-Westerose Gas Reservoir/Surface Pipeline Network
Authors: Sorensen Frank , Little L. C. 
Published: December 2007

ABSTRACT
This paper presents the preparation of a model of the Hoadley-Westerose gas reservoir and surface pipeline network using a single phase 3-Dimensional reservoir / single phase network simulator. The 3-D reservoir description was preferable to the alternative tank type approach based on the dual permeability nature of the reservoir and the desire to calculate lease line migration. In spite of the complex reservoir description, the 3-D history match was not difficult to obtain, and computing times were very acceptable. The resulting model was found to be a reasonable representation of the network, even with the approximations which were required to treat the network as a single phase system. A previous multiphase model of the network did not provide a better match of the system.
Inflow Performance and Production Forecasting of Horizontal Wells With Multiple Hydraulic Fractures in Low-Permeability Gas Reservoirs
Authors: Guo Genliang , Evans R. D. 
Published: December 2007

ABSTRACT
The applications of horizontal well technology coupled with hydraulic fracturing in the development of low permeability gas reservoirs are investigated.
Analytical single phase and multiphase pseudo-steady state inflow performance equations for a horizontal wellbore intersecting multiple hydraulic fractures are presented. The effects of permeability anisotropy, wellbore location eccentricity, and fracture characteristics are considered. The phenomena of non-Darcy flow is also accounted for in the inflow equation associated with the flow of gas phase. These solutions provide a basis for the productivity evaluation and production forecasting of horizontal wells with multiple hydraulic fractures.
A new analytical method for predicting the future production performance of gas reservoirs is derived. The method is based on material balance analyses in which explicit pressure expressions as functions of cumulative production data and gas properties are derived for various types of gas reservoirs. Detailed production forecasting procedures are developed by using the derived pressure functions and appropriate inflow performance equations. The new production forecasting method has been further implemented on a computer. As a result, the future production performance of a gas reservoir can be easily predicted for any given scheme of horizontal drilling coupled with hydraulic fracturing, and combinations of reservoir rock and fluid properties.
With an economic evaluation, the new method may be used in the initial screening of horizontal drilling and hydraulic fracturing prospects in low permeability gas reservoirs. It may also be used in daily production operations and reservoir management. A hypothetical case study is presented which demonstrates the applicability of the new inflow performance equations and production forecasting method in the recovery optimization of a low permeability gas reservoir by combining horizontal drilling and hydraulic fracturing technology.
Numerical Solutions for Pressure Transient Analysis
Authors: Warren G. M. 
Published: December 2007

ABSTRACT
New research into wellbore modeling and grid generation techniques, has made feasible pressure transient analysis (PTA) based on a numerically simulated solution. This paper first briefly reviews the development, including determination of the gridding and time step control algorithms, and then discusses some of the technical advantages offered by a numerical model as compared to standard analytic solutions. The focus of the paper is on several field case studies. The cases presented involve partial penetration and non-Darcy flow turbulence. Since general analytic solutions for these problems are not available, this paper presents new numerical solutions for these types of problems. For example, isolation of mechanical skin from partial penetration and turbulence effects, as demonstrated in this paper, is an ongoing and critical problem with respect to evaluating the need for reperforation and/or stimulation treatments.
Preliminary findings from ongoing multiple phase PTA research, including modeling production below the bubble point and gas-water coning will also be presented.
The results demonstrate that a simulation approach offers a revolutionary new and completely general solution to evaluating wellbore and reservoir problems that are either very difficult or not currently possible to solve analytically. Proper and practical evaluation of well tests with a numerical approach cam lead directly to bottom line profit making decisions.
Analysis of Kansas Hugoton Infill Drilling: Part III—1993 Update and Infill Well Case Histories
Authors: McCoy T. F. , Reese D. E. , Fetkovich M. J. , Needham R. B. , Freeman B. E. 
Published: December 2007

Abstract
The purpose of this paper is to update our original Kansas Hugoton infill drilling studies. This paper examines the performance of the first 1513 infill wells placed on production through September 1992 and presents a number of infill well case histories. Official deliverability tests, production histories and completion data are used to evaluate infill well performance. The case histories review the performance of the older infill wells which shows the greatest potential of finding additional gas-in-place (GIP). These results indicate the infill wells have not found any additional GIP.
Material Balance Modelling and Performance Prediction of a Composite Gas Reservoir
Authors: Arthur J. E. , Chhina H. S. , Temeng K. O. 
Published: December 2007

Abstract
Gas reservoirs producing under pressure support sometimes exhibit a nonlinear relationship between cumulative production and (P/Z). A corollary effect is that the apparent gas volume in place increases with time and exhibits a sensitivity to changes in withdrawal rate. The nonlinear behavior may be attributed to dual porosity effects or aquifer support, which are both accounted for in the model. Without an aquifer being present, the nonlinear behavior may be a result of adsorption, natural fractures or an extremely tight gas-bearing region adjacent to a main reservoir. Proper modelling of such a system is crucial in determining ultimate recovery, and in choosing an appropriate development scheme.
In this paper we present results of a material balance mode! developed to study a dolomite, dual porosity gas reservoir in Alberta. The study was done to explain the better than expected performance of the reservoir, and to forecast future reservoir performance. The material balance model consisted of a main ‘productive’ tank in pressure communication with a low permeability, gas bearing matrix. Gas influx from the outer low permeability matrix results from pressure drop in the reservoir, and provides pressure and material support. Tubing, compressor and pipeline effects were analytically modelled and coupled with the material balance and deliverability models.
A single coupled analytical equation has been developed to account for reservoir, wellbore and surface facilities (compression, surface line) simultaneously.
An excellent history match was obtained with the model by properly adjusting the sizes and properties of the reservoir and matrix. Long-term performance was predicted under various schemes and constraints, including the effects of additional wells and compression. The results show that gas influx from matrix and ultimate recovery are very sensitive to withdrawal rate, and late-time performance of the system is observed to be influx-dominated. The impact of these results on future operating decisions is shown to be significant and is discussed in detail in the paper.
Deep Coal Seams: An Overlooked Source for Long-Term Natural Gas Supplies
Authors: Kuuskraa V. A. , Wyman R. E. 
Published: December 2007

Abstract
Recently, considerable attention has been focused on the long term potential of natural gas. Studies have included resources that range from conventional gas in Stratigraphie traps to unconventional gas locked in hydrates. However, these studies have overlooked one large and potentially productive gas resource — the methane stored in deep coal seams.
Currently, the conventional wisdom is that coals below 5.0 feet will be extremely low in permeability and thus unproductive. This viewpoint stems from the early laboratory based tests of confining pressure (depth) versus permeability and from the initial field tests in the deeper portions of the Piceance Basin, U.S.A.
Recent basin studies show that the resource potential in deep coal basins is considerable, both in the U.S. and worldwide. For example, in the U.S. the bulk of the 84 Tcf of coalbed methane contained in the Piceance Basin is in deep coals, below 5.0 feet. Even larger amounts of gas exist in deep coal seams in Alberta, Canada and other deep coal basins of the world. Also, comparisons of laboratory based permeability tests on coal with field results indicate that the lab tests may be unduly pessimistic. While the evidence that deep coals can be economically productive is limited, some data is now available and discussed in this paper. For example:An experimental completion of a Cretaceous age coal seam at 10,0 feet in the Deep Basin of Alberta, showed that deep coals contain substantial methane, that gas can be produced from such depths, but that the well completions are very challenging.A recently drilled 6,000 foot deep well at Piny on Ridge (Northern Piceance Basin) had an initial gas flow of nearly a million cubic feet per day.
The purpose of this paper is to examine the resource and production potential of deep coal seams and thus add this resource to the list of long-term sources of natural gas.
Ultrasound Logging in Cased Boreholes Pipe Wear
Authors: Bettis F. E. , Crane L. R. , Schwanitz B. J. , Cook M. R. 
Published: December 2007

ABSTRACT
USI* UltraSonic Imager logs are run to evaluate cement, measure casing thickness and present the results as cement acoustic impedance and metal loss percentage.
The USI tool makes a high-resolution casing inspection, which allows identification of casing wear caused by drilling operations. Field examples illustrate the extent of the problem. Factors related to casing wear include drillpipe hard banding, hole deviation and, of major importance, directional dogleg severity. In one of the field examples presented, the operator ran a casing cutter and recovered the logged 7 5/8-in. casing. After recovering the casing, USI log results were compared to surface ultrasonic inspection and to physical measurements.
In another field, after discovering the serious nature of the casing wear that occurred during the drilling of wells below the 9 5/8-in. surface casing point, a number of operational changes to drilling and casing procedures were recommended. These changes were tested in the wells included in the field study. After each change, the results were checked by running the USI tool on the well.
Not All Technology is Necessary for Cost-Effective Cementing
Authors: Terry A. J. 
Published: December 2007

ABSTRACT
From late 1990 through 1991, 43 wells drilled in the Gulf of Thailand were in the Jakrawan/Funan/Gomin fields (JFG). This was a higher pressure environment than had been seen previously, a situation which dramatically increased the frequency of remedial cementing. This paper will outline the resultant changes Unocal made to its cement program.
With multiple thin bed sands through open hole sections of 5000-7000’, 3-dimensional deviations, angles up to 60 degrees, close pore and fracture pressures, torque and drag limits, and 380 °F. static temperatures, effective primary cementing in the Gulf of Thailand is a challenge.
Operators often fail to recognize the importance of slurry placement mechanics such as centralization, circulation, pump rates and casing design. It has been proven that cement placement and mud removal are just as important as slurry property design1. However, it must be recognized that not all solutions are economically feasible and a certain amount of remedial cementing may be acceptable to the operator.
This paper outlines the unique problems faced in performing cementing operations in the Gulf of
Thailand and details the improvements made. This paper describes not only the application and success of cementing technology and concepts, but also rejects certain technology as uneconomical for the operator. Technology not applied due to limiting factors or cost is also discussed.
Deep High Volume Rod Pumping
Authors: Nolen K.B. 
Published: December 2007

Abstract
An investigation was made to determine optimum displacement needed to produce maximum fluid from approximately 8,500 ft. Both computed and actual field test data are given. Also, the load characteristics are compared between conventional crank-balanced, air-balanced and unconventional [Lufkin Mark II] pumping units. In addition, some data are pumping units. In addition, some data are presented on [1] sucker rod shock absorbers, presented on [1] sucker rod shock absorbers, [2] sucker rod electronic inspection, [3] sucker rod make-up and design changes, [4] USI Circle-A rod pump and [5] Delta II dynamometer use and results.

Introduction
Deep unprorated production in Montana, Wyoming and portions of North Dakota offers a challenge to high volume rod pumping. Generally, maximum volumes; of 350 BFPD can be effectively rod pumped from 8,500 ft. Most of these high volume wells are equipped with 5-1/2-in. casing, anchored 2-1/2-in. EUE tubing, 3-tapered rod string [1 in., 7/8 in. and 3/4 in.], 1-1/2-in. or 1-3/4-in. insert pumps and a bean unit with a 120-in. stroke and 456,000 in.-lb gearbox.
This paper presents the latest developments on sizing and selecting new equipment with some information given on limitations and improvements that can be made on existing equipment.

DETERMINATION OF OPTIMUM BEAM PUMPING UNIT SIZE
A study was made using a computer routine similar to the new API approach to determine optimum displacement needed to produce maximum fluid from approximately 8,500 ft. Since sucker rod strength is the limiting factor in high volume beam pumping, the beam unit geometry, stroke length, pumping speed and pump size were analyzed jointly to obtain optimum sucker rod performance. The maximum stress limits of high performance. The maximum stress limits of high strength API Class D rods are shown in Fig. 1. The API Class D rating is based on sucker rod steel having a minimum tensile strength of 115,000 psi or more. Most rod manufacturers rate their Class D rods at 125,000-psi minimum tensile strength or higher. For the purpose of this study, 125,000-Psi minimum yield rods were used without a service factor.
Computer runs were made with 1-1/2-in., 1-3/4-in, 2-in. and 2-1/4-in. bore pumps running at speeds varying from 7 to 13 strokes per minute. Six stroke lengths were analyzed: 100 in., 120 in., 144 in., 168 in., 192 in. and 216 in. A fresh water gradient of 0.433 psi/ft and a pump intake pressure of 100 psi was used.
Recovery of Attic Oil through Horizontal Drilling
Authors: Martins E. J. , Larez N. J. , Maraven S. A. , Lesso W. G. 
Published: December 2007

Abstract
The production of moderate-sized oil reservoirs, wedged up against major faults, frequently leaves residual hydrocarbons towards the top of the trapping mechanism involved. The beds are usually dipping at a high angle. Recovery of this attic oil in geologically complex reservoirs with conventional vertical or directional wells is, in general, not cost effective because of the reduced vertical column of oil in place and the ease of water coning. This situation exists in several Bloque I, Lake Maracaibo, Venezuela reservoirs that have produced oil over the past 40 years. A horizontal drainhole was planned, drilled and produced in one of these attic sections parallel to a large fault to recover a higher percentage of the remaining reserves. The location was identified using 3D seismic and confirmed with reservoir modeling and historical data. In addition, a pilot was drilled near the heel of the well to confirm the sand location. The first attempt to land a horizontal drainhole missed the sand due to the complexity of the geologic structure. A timely assessment of geologic and geometric data yielded a new model of the sand location, This, coupled with geo-steering techniques, allowed a second drainhole to successfully follow the sand in oil for more than 1100 ft. The well was completed with 7″ casing having a slotted section along the dra¡nhole. Initial tests showed 2400 BOPD. This was an eight-fold increase as compared to several vertical wells in the same reservoir.
The project was an overall success. Costs and time spent in drilling and completion were within expectations. This paper will show that coordination of the project through an integrated team consisting of the operator’s and the various contractor’s personnel was key in producing this result. Based on the first six month’s production performance, the well has paid for itself, and it will allow recovery of most of the remaining reserves in a cost effective manner. The experience gained on this well is serving as the basis for other horizontal projects in Lake Maracaibo and other parts of Venezuela.
Applications of a Systems Dynamics Weather Downtime Mobil for Drilling
Authors: Mamerow Steve , Brooker M. W. , Brett J. F. 
Published: December 2007

Abstract
In 1989, Amoco Production Company, as part of a worldwide continuous improvement effort by the drilling department, began tracking unscheduled events during drilling operations. It was readily apparent that downtime due to adverse weather conditions was contributing heavily to unscheduled events offshore, especially in the North Sea and Pacific Rim.1 When the weather downtime percentages were repeated in 1991, after the problem had been identified and publicized internally, drilling management determined that these weather problems were symptomatic of larger problems that encompassed much more than the drilling department and exploratory well schedule.
To study this problem a multi-disciplinary team consisting of two geologists, a geophysicist, a negotiator, three engineers, and a business process facilitator, was formed within the Worldwide Exploration Business Group. One of the team’s final products was a Weather Downtime Model. Using detailed weather data and site specific drilling information, the model can predict potential weather downtime problems (Appendix 1 contains a complete model description). Using hindcasts, in 1992, the team tested the model in a real-time situation(Danish sections Northsea). It also used the model to highlight potential problems as this concession was being developed. This paper describes the work of this multidesciplinary team and its actual use of the Weather Downtime Model.
Teamwork: The Economics Work
Authors: Sneider R. M. 
Published: December 2007

Abstract
Is an E & P company organized as synergistic teams more profitable and effective than one organized with a traditional heirarchy? One large oil company decided to find out the answer. They formed a small "synergistic" company to compete on exactly equal basis with one of their traditional E & P divisions. During five years of competition, the small company (35 employees) found about twice the reserves at about half the finding cost of the large division (175 employees).
New Frontiers in Like Kind Exchange for the Oil and Gas Industry
Authors: Brown T. A. , Brown D. A. 
Published: December 2007

Abstract
As an increasing number of companies divest of non-strategic property and acquire properties that contribute to their operating efficiency, tax-deferred exchanging is becoming a significant strategy. The roots of current tax law regarding Like-Kind Exchanges go back to the early 1920’s but have changed significantly as the tax law has been modified and case law developed in intervening years. Recent regulations have made exchanges much easier and less expensive to administer and broadened the scope of what qualifies as an exchange. Final Like-Kind Exchange tax regulations regarding deferred exchanges were issued in 1991 and 1992. In particular, the introduction of the Qualified Intermediary allows exchanging to be an ongoing corporate strategy rather than a highly customized opportunity. This paper will review the new regulations as they apply to the petroleum industry, give examples showing how effective use of the strategy will preserve much needed capital, and demonstrate how the use of an Intermediary expands the application and flexibility of tax-deferred exchange1 to a very broad spectrum of oil and gas entities. There is a significant benefit in developing a management procedure that regularly determines the applicability of tax-deferred exchange in all sales of assets and implements operational steps to execute an exchange routinely and in compliance with tax regulations.