bluuebunny/crossref_metadata_2025_split huggingface dataset:
Recommended Practices Improve Hole Opening and Underreaming in Offshore Wells
Authors: Mefford R. N. 
Published: December 2007

ABSTRACT
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

ABSTRACT
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

ABSTRACT
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

ABSTRACT
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

ABSTRACT
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

ABSTRACT
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

ABSTRACT
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

ABSTRACT
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

ABSTRACT
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

Abstract
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

Abstract
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

ABSTRACT
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

ABSTRACT
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

ABSTRACT
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

ABSTRACT
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

ABSTRACT
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

ABSTRACT
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

ABSTRACT
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.