bluuebunny/crossref_metadata_2025 huggingface dataset:
Practice and Viewpoint on Regional Cathodic Protection in the Guanghua Oil Field
Authors: Yinglong Zhao
Published: December 2007

The control of corrosion on pipeline network for gathering and transporting and on casings of oil and water well is a matter of primary importance to the prolongation of their service life, the cutting down of their operattion costs, the reduction of energy loss and the improvement of the level of management. From seven years field experiments in cathodic protection on a regional scale in the Guanghua oil field, this paper attempts to give a review of the experiences in respect to: the necessity of joint protection of pipeline network and casings, the method of measuring and ¼ayβ of eliminating interferences, the rational layout of anodic groundbeds and distribution of protection current the method of monitoring the state of casing protection and the technological and economic problems involved.
An Improved Technique For Predicting The Severity Of Calcium Carbonate
Authors: Valone Frederick William , Skillern Kenneth Richard
Published: December 2007

A new approach for computing calcite scaling tendencies is described. Computed values are obtained by exactly solving the chemical equilibria expressions for calcite precipitation. To date, extremely accurate predictions of calcite scale deposition in oilfield systems have been made based on this computed scaling value.
Performance Comparisons for Reservoir Simulation Problems on Three Supercomputers
Authors: Stanat Patricia L. , Nolen James S.
Published: December 2007

Recent decisions by several of the major oil companies to acquire vector processing computers indicate the growing acceptance of these machines in exploration and production applications. While seismic processing has probably provided the primary justification for these acquisitions, suitability for numerical reservoir simulation should be considered in evaluating such hardware.

This paper extends the results presented in a previous paper by comparing the performance of the CYBER 203, CYBER 205, and CRAY-1 S computers when running a three-dimensional, three-phase reservoir simulator.(1) Each of three different problems were run on the 203 and 205, and all three machines were used to solve one problem.

As might be expected, the results show that the improvement obtained from one computer to the next is somewhat problem dependent. The parameters affecting the differences include the vector length and the amount of scalar code executed relative to vector code. In the three cases, the CYBER 205 demonstrated run times of 2.3 to 3.4 times faster than the CYBER 203. The CYBER 205 was found to be 1.6 times faster than the CRAY-1 S in the case where all three machines were tested.
Seismic Imaging in Enhanced Recovery
Authors: Nur Amos M.
Published: December 2007

Laboratory measurements of seismic velocities and attenuation in fluid saturated rock samples strongly suggest that detectable changes in these properties are anticipated upon steam flooding of heavy oil reservoirs, or during other EOR operations. Such changes could be monitored with seismic array of receivers and transmitters situated around the region of enhanced recovery. The array will yield seismic wave travel times and amplitudes and their temporal and spatial changes. Inverting these measured values, it is possible to determine the distribution of velocities and Q within the reservoir. These distributions can uniquely be interpreted in terms of the distribution of a steam phase in the reservoir, using laboratory determined seismic response of reservoir rock samples.
Laboratory Investigation of the Oxygen Combustion Process for Heavy Oil Recovery
Authors: Moss Jon T. , Cady Gilbert V.
Published: December 2007

The laboratory investigations were conducted using core material and produced oil from a typical Alberta heavy oil reservoir. The experiments produced oil from a typical Alberta heavy oil reservoir. The experiments established combustion characteristics using air and the CTD process for thermal oil recovery. Both the combustion and CTD tests indicated the oil's favorable response to thermal recovery. The results of laboratory studies using oxygen and oxygen with water injection have indicated that the enriched air process, as Ramey suggested almost thirty years ago, is not only viable as an oil recovery method, but the process is also highly desirable.

Introduction

The in-situ combustion process has been thoroughly described in the literature over the last three decades. Early investigators used various methods for control of the combustion process. Sinclair's early field experiments in Kansas and Oklahoma advocated use of the heat wave process to control combustion variables. Volumes of air, gas and recycled gas were used to propagate a flame front through the reservoir. Worthington and the Forrest Oil Company used gas, air and steam in their 1953 field test in Illinois. Air was injected in the forward combustion process developed by Magnolia and General Petroleum in early field tests in Oklahoma and California. From these diverse, yet similar, pilot projects, Ramey suggested several alternate operational schemes for in-situ combustion. One of these proposals was to inject air enriched with oxygen.

Distinct improvement in combustion techniques came in the early 1960's when Tejas Engineers pilot tested the Combination Thermal Drive (CTD) process using air-water injection and AMOCO developed the COFCAW process. process using air-water injection and AMOCO developed the COFCAW process. To further enhance combustion drive, Dome Petroleum Limited initiated reservoir and laboratory studies to determine the process variables using oxygen as the injected gas. Several laboratory combustion tube experiments have been made using air, air and water, oxygen and oxygen-water injection.
A Practical Iterative Scheme for Coupling Geomechanics With Reservoir Simulation
Authors: Samier Pierre , de Gennaro Sergio
Published: December 2007

The use of reservoir simulation coupled with geomechanics to model physical phenomena such as compaction, subsidence, induced fracturing, enhancement of natural fractures and/or fault activation, SAGD recovery etc.., has been increasing. Among different methods investigated by researchers. The iterative explicit method appears to be the preferred method for field-scale simulation.

This method is a loose coupled approach between a reservoir and a geomechanical simulator. At user-defined steps, the fluid pressures are transmitted to the geomechanical tool which computes the actual stresses and reports the modifications of porosities and permeabilities back to the reservoir simulator. In the classical iterative scheme, at each stress equilibration step, the reservoir simulation needs to be restarted from the previous converged step. This scheme can be difficult to implement within an industrial IT environment.

This paper presents a new iterative scheme which allows:

any reservoir simulator, to be coupled with any nonlinear FEM package for the stress analysis without any limitation on the functionality of either simulator.

The convergence of this new scheme is discussed and results are presented for three cases described below.

The first case is a validation case used by other SPE papers. The second case is a synthetic model of a highly compacting reservoir sensitive to water saturation. The third one is a full field reservoir model. Faults are modeled inside the reservoir CPG grid and also inside the geomechanical mesh using specific cohesive elements.

In all cases, convergence is achieved in a few iterations and results are comparable to those obtained with previously tested methods. The feasibility of the proposed coupling approach using industrial software is proved. Another advantage compared to the standard iterative scheme is the ability to compare production profiles over the complete time history at the end of each geomechanical iteration. The reservoir engineer evaluates the coupling effects and ends the iterative process when production curves variations between two iterations are no longer significant.
Performance of DOE's Micellar-Polymer Project in Northwest Oklahoma
Authors: Thomas Rex D. , Spence Kenneth L. , Burtch Fred W. , Lorenz Philip B.
Published: December 2007

DOE's Bartlesville Energy Technology Center has completed a micellar-polymer flood in the Delaware-Childers Field in NE Oklahoma. The producing horizon was the oil-wet Bartlesville sandstone, at a depth of 620 to 700 ft., which has a net pay thickness of 52 ft, an average permeability of 100 md, and an average porosity of 21 percent. Estimated oil saturation was 32 to 36 percent of 33° API gravity oil. Injection of the approximately 0.1 PV of micellar fluid was started April 28, 1976, following five months of brine preflush. Micellar injection was completed and polymer injection started October 5, 1976. Injection of the approximately 0.4 PV of polymer was completed in August 1979 and fresh water injection started. Pressure and flow for the injection-wells were monitored instrumentally. Spot checks for the quality of injected and produced fluids were made by chemical analysis. The project was not technically or economically a success, but did provide much information that is proving useful in other similar projects. A small amount of tertiary oil was produced by the micellar-polymer system.
A Numerical Model of the Non-Isothermal Flow of Carbon Dioxide in Wellbores
Authors: Cranshaw Mark B. , Bolling John D.
Published: December 2007

A numerical model of non-isothermal flow in pure carbon dioxide production or injection wells was developed. The model includes single or two-phase flow, heat transfer between the wellbore and its surroundings, and an accurate representation of the thermophysical properties of carbon dioxide, even near its critical point. Model predictions matched pressures measured during a field production test to within 30 psi and temperatures to within 3°F for flow rates between 4 and 22 MMscf/D. Sensitivities to wellhead conditions and flow rate for a pure carbon dioxide injector were examined with the model. Explanations of behavior during production and injection should improve our understanding of the use of carbon dioxide in the oil field.
Operational Experiences of a Downhole Steam Generator
Authors: Marshall Billy W.
Published: December 2007

The U. S. Department of Energy has supported the development of downhole steam generators for enhanced oil recovery as a part of Project DEEP STEAM. A final step in the development program was to deploy a downhole steam generator (DHSG) in the field to demonstrate its reliable operation and to evaluate the effect of the combined steam/exhaust products effluent on the reservoir. Sandia National Laboratories entered Into an agreement with the City of Long Beach to place two direct contact, high pressure combustors in the Wilmington Field in Long Beach, California. These units, one downhole and the other on the surface, have now been operated for a few months and gas communication with the production wells established. The operational experiences of this field experiment are discussed.
Downhole Steam Generator — Field Tests
Authors: Eson Rod L.
Published: December 2007

Excessive air pollution and heat losses up to 32% in the surface lines and out the stacks of conventional generators are reasons why conventional steam generation is inefficient. These problems are addressed and overcome through the use of a direct-fired Downhole Steam Generator (DSG). By carrying out the combustion process at high pressure, and then adding water, a mixture of carbon dioxide, nitrogen and steam is discharged directly into the heavy oil reservoir. This paper documents a series of field tests of a direct-fired DSG showing its ability to produce and inject high quality steam into heavy oil reservoirs without the need for expensive stack scrubbers to remove sulfur dioxide (SO2), as well as sophisticated nitrogen oxides (NOX) control techniques. Results from the 6 in. diameter, 6 ft long, 7.1 MMBtu/hr DSG showed that corrosion can be controlled and production can be improved dramatically in actual field tests in California heavy oil reservoirs.

Some speculation was given to the positive effects from the injection of the combustion products with the steam. Field tests indicate that in at least one case, a 639 ft deep, 11° API gravity well with low reservoir pressures (100 psi) flowed after injection of only 1,393 barrels of steam along with the combustion gases of the direct-fired Downhole Steam Generator.

This field development of the direct-fired DSG not only has shown that it can be an effective Enhanced Oil Recovery (EOR) technique in existing heavy oil reservoirs, but also provides a feasible means of recovery for the 5-7 billion barrels of heavy oil known to exist in the United States below 2,500 ft.
Design Considerations of a Tension Leg Platform
Authors: Ghosh Susobhan , Chou Frank S. , Huang Edward W.
Published: December 2007

The offshore industry is presently reviewing the design and installation of various concepts for deepwater platforms. The concept most favored is probably that of the Tension Leg Platform (TLP). The design of a TLP has many challenging and intriging aspects, some of which are unique to itself. TLP'S are relatively new to the offshore industry, thus there are no standard design guides. In the years to come, as the industry learns more about the behavior of TLP'S; the design methods are expected to improve accordingly. A TLP design includes the design of the vessel, tether system, processing equipment and hardware e.g., well head system, drilling systems, tether handling equipment etc. This paper summarizes the authors' experience dealing with various challenging engineering problems in TLP design, and outlines the important design considerations which a designer is expected to encounter designing a TLP. A brief review of analytical tools and how they are applied in the design of a TLP are included in the paper. No attempt has been made to cover aspects related to hardware design.
Improved Liner Cementing Techniques for Alaska's Prudhoe Bay Field
Authors: Kolthoff Karl W. , Scales Glyn H.
Published: December 2007

This paper describes the current equipment and techniques used to reciprocate and cement liners in Alaska's Prudhoe Bay Field. Liner reciprocation was started in Prudhoe Bay by BP Alaska, Inc., using hydraulic-set hangers during 1976. Liner reciprocation was initially developed to improve mud displacement thereby improving cement bonding in high-angle wells. To date, more than 210 deviated wells have been successfully completed using the methods described in this paper.

Typical Prudhoe Bay Unit wells are completed with approximately 1,500 ft of 7 in. 29#/ft L-80 liner hung across 8-1/2 in. open hole at 10,800 ft MD in hole angles up to 67 degrees. Liners are routinely reciprocated while conditioning mud and while circulating and displacing cement slurries. The cement is preceded with a chemical or water pre-flush, and the entire slurry is displaced at turbulent flow rates. The hanger is hydraulically set with a liner wiper plug. Current technology includes the use of the latest recirculating cementing unit as well as liner hanger equipment designed for compactness, low-flow restriction, and high-load capacity.

Reciprocating liners in the Prudhoe Bay Unit has resulted in a significant drop in the number of squeeze cement jobs of the liner and/or liner lap. Success has been verified by lap in-flow testing, low-water production rates, and a good cement bonding at the critical oil/ water and gas/oil contacts.
A New Low-Cost Permafrost Cementing System
Authors: Benge O. G. , Jones R. R. , Dresher T. D. , Dolan R. T.
Published: December 2007

Extensive research has resulted in the development and subsequent field application of a new extended cement system for use in permafrost cementing projects. The use of this extended system instead of more expensive specialized cement systems leads to a reduction in overall permafrost cementing costs.

This paper reviews the design requirements for permafrost cementing. It also provides laboratory data and reviews the methods which have met those requirements.

Results of actual field application of the newly designed cement system and comparison with another specialized extended system are also presented.
Application of Pressure Transient Analysis in Steam Injection Wells
Authors: Messner Gregory L. , Williams Richard L.
Published: December 2007

The determination of the swept volume in a steam displacement process provides an early means to evaluate the project's progress. By determining the volume occupied by steam, and knowing the cumulative volume of steam injected, the heat losses from the injection interval and the ensuing heat efficiencies can be estimated. These parameters dictate the performance efficiency of the displacement project.

Getty Oil Company has run pressure falloff tests in several steamflood projects located on the west side of the San Joaquin Valley. The first project tested had undergone nine months of continuous steam injection, with little apparent increase in oil production or wellhead temperatures in the displacement wells. The test data was analyzed using the theory presented in Eggenschwiler, et al.'s1 work and Walsh, et al.'s3 analytical procedure. The initial results are very encouraging and more-or-less consistent with the previous theoretical studies, implying that this type of testing can be a valuable tool for early evaluation of the viability of a steamflood project, with a minimal shut-in time and expense.

Several more falloff tests were run in displacement projects having more history, temperature observation wells, and better control of reservoir properties. These tests were run to verify the analysis procedure and determine steamflood characteristics in projects designated as commercial successes. A simple numerical study using a thermal model was also used to further analyze the principles of the underlying theory and demonstrate the applicability of this particular simulator to pressure transient problems. The results of the numerical study are included.
Reflection Seismology as an Exploration Tool for Fractured Zones in Gas-Bearing Shale — Cottageville, West Virginia: A Case Study
Authors: Ruotsala James E. , Williams Richard T.
Published: December 2007

The Cottageville, West Virginia, gas field produces from the Lower Huron Member of the Ohio Shale formation of the Upper Devonian. The production results from increased permeability caused by anomalous fracturing of the shale. A normal basement fault, which lies below the fracture zone, may control fracturing in the shales.

Seismic reflection data obtained in the area in 1977 show the fault extending up into the Ordovician. These data are also analyzed for seismic velocity and attenuation anomalies associated with the gas-producing fracture zone. Gas production occurs in an area several miles long but only about one mile wide. Increased fracture intensity and presence of gas in the shale within this limited area serve to decrease the shear strength of the rock, decreasing the seismic velocity. Similarly, greater attenuation of the high-frequency components of the seismic wave can be expected. Examples from the Cottageville data showing basement structure and seismic velocity and attenuation anomalies associated with gas production are presented.

An exploration rationale for prospecting for eastern shale gas is developed. Although the total area covered by gas-bearing shales in the eastern United States is large, individual gas fields within this area are relatively small. Reflection seismology is used to target specific exploration wells after reconnaissance by other methods has been done.
Glacial Loading: A Cause of Natural Fracturing and a Control of the Present Stress State in Regions of High Devonian Shale Gas Production
Authors: Clark James A.
Published: December 2007

It is likely that ice sheets contributed significantly to natural fracturing and hence gas production in low permeability Devonian shale. The large ice sheet of the last ice age caused considerable deflection of the lithosphere. Predicted horizontal tensional stresses south of the glacial limit resulting from this crustal flexing exceed the tensile strength of Devonian shale. Glacially induced fracturing is therefore expected in these regions which correspond with regions of historical gas production. The north-south variation in observed stress ratios is also explained by the glacial model. Lineaments and faults will perturb locally the glacially induced stresses and, when coupled with the glacial model, offer an exploration rationale.
Preliminary Resource Assessment of Coalbed Methane in the U.S.
Authors: Byrer Charles W. , Malone Rodney D. , Hunt Arlen E.
Published: December 2007

Throughout the history of gas exploration and development in the U.S., potentially recoverable quantities of methane from unconventional sources such as coalbeds have been largely excluded from potential gas supply surveys. This is attributable to the lack of data about the resource, technology, and economics of its recovery. In order to provide answers, DOE initiated the Methane Recovery from Coalbeds Project (MRCP) to characterise the gas-in-place for various coalbeds and associated sediments.

Preliminary resuits of the DOE Methane Recovery from Coalbeds Project reveal that many of the coal regions in the United States have significant volumes of coalbed methane. Preliminary gas-in-place resource estimates were made based on the volume of coal-in-place and on direct methane-desorption data. It has been conservatively estimated that 14 percent of the 48 conterminous states are underlain by coal-bearing rocks(1). Over 50 wells have helped to update the estimates of methane in these various coal regions. The evaluation of 11 basins by the MRCP reveal that the total resource estimated in-place is between 57 and 285 Tcf· Those basins showing high potential include the Northern Appalachian, Arkorna, Piceance, Warrior, Illinois, and Greater Green River.
Methane Resources of the Unmineable Coal Seams in the Richmond Basin
Authors: Topuz Ertugrul , Wilkes Gerald P. , Karmis Michael , Lucas J. Richard , LeVan Donald
Published: December 2007

The objective of this study was to evaluate the potential of the methane resource associated with the Richmond Coal Basin of Virginia. The study indicated that the basin may have a potential of 0.7 to 1.4 trillion cubic feet of methane resource that may be of considerable value to the Richmond area and the nation.
Tight Gas Research and Development: The Industry Perspective
Authors: Brashear J. P. , Elkins Lloyd E. , Haas Mark R.
Published: December 2007

Low permeability gas reservoirs ("tight gas sands") are abundant in the U.S. Economic recovery of the gas in these formations requires reservoir stimulation, usually massive hydraulic fracturing. Significant investigations of tight gas sands by the National Petroleum Council (NPC)(1), Lewin and Associates(2), and the Gas Research Institute (GRI )(3) have agreed that, although some formations can be profitably produced with existing technology, improved reservoir diagnostic and stimulation techniques are required to realize the full potential of the resource.

Most major operators and well-service companies conduct research and development to improve tight gas technology. A survey of tight gas research managers in eight companies was conducted to determine their R&D priorities and the constraints under which they operate.

The responses of the R&D managers showed a high degree of consensus on tight gas R&D objectives, company priorities, decisionmaking criteria, current activities, and constraints. The representatives of six operating and two service companies stated that they prefer R&D that produces high "payoffs" in the near term, with low-to-medium risk of R&D failure. This characteristic leads industry to focus current R&D on measurement and prediction of fracture geometry (shape and orientation), particularly in the lower-risk blanket-type (as opposed to lens-type or lenticular) formations. Despite the presence of price incentives for production of tight gas and the potential of high return, the constraints on available personnel and funds for R&D limit industry's willingness to conduct the long-term, high-risk R&D needed to produce the lenticular resource. The industry R&D personnel interviewed were familiar with, and generally endorse, those long-range and high-risk objectives and priorities of the Federal tight gas research program that complement university and industry efforts.
GRI Program for Tight Gas Sands Research
Authors: O'Shea Patrick A. , Murphy William O.
Published: December 2007

In mid-1981, the Gas Research Institute (GRI) drafted comprehensive programs for research directed toward increasing the national supply of natural gas from unconventional sources. Low-permeabi1ity (tight) gas sands are one of these sources. GRI's pre-draft planning for the tight gas sands program was for a duration of about one year and included workshops with advisors from the natural gas industry. The resulting program plan for tight gas sands research is oriented to industry participation and field testing. Research results are freely distributed to a wide variety of users.

The tight gas sands program is initiating in 1982; planning updates by GRI are on an annual cycle. GRI is proceeding with six projects for tight gas sands research, involving analyses for producing natural gas from tight blanket sands that are presently considered as non-commercial. The program plan is comprised of a sequence of projects relating to resource identification, formation evaluation, fluids and proppants investigations, fracture design, reservoir modeling, and staged field tests with technology transfer. Accelerated research work is scheduled for 1983, with emphasis on field evaluations beginning in 1984.

This paper describes the philosophy, objective, and content of the GRI program plan, which is currently scheduled through 1988. Accomplishment of the program is expected to provide for significant advances in tight gas sands research. GRI is a nonprofit scientific organization which contracts applicable research work to others for benefit to the natural gas industry and to natural gas consumers.
Methane Recovery From Deep Coalbeds in the Book Cliffs
Authors: Allred Larry D. , Coates Ralph L.
Published: December 2007

A project jointly funded by Mountain Fuel Supply Company and the U.S. Department of Energy is being conducted to show the commercial potential of recovering methane gas from deep coal seams in the Book Cliffs coal field in Central Utah. Recovery technologies are being defined and economic analyses of methane recovery are being made. Three vertical wells have been drilled to depths ranging between 3,000 and 4,110 feet. Desorption measurements on core samples indicate gas contents up to 440 cu ft/ton. All three wells have been subjected to hydraulic stimulation treatments but with drastically different results. One well has demonstrated gas production of 20 to 30 mcfd from a 13-foot coalbed. A second well was extremely "tight" and very little production has been achieved to date. The third well has not been put on continuous production, but gas production rates of 120 mcfd averaged over a short testing period were measured.
Fracturing Using a Stabilized Foam Pad
Authors: Ainley Brian Roland , Charles J. Gary
Published: December 2007

The development of stabilized foam has created the potential for a widely suitable fluid in water-sensitive and/or under-pressured reservoirs. Foams, to date, have proved to be effective fracturing fluids in shale, coal and tight sands, but proppant placement has been a problem. With the use of a stable foam pad, proppant can be transported with a crosslinked fluid at optimum concentrations for maximum fracture conductivity. The stable foam pad has excellent fluid-loss characteristics and will retain energy to flow back the gelled water stage. With the use of a stable foam pad and crosslinked proppant-carrying fluid, the advantages of both fluids can be utilized in creating a highly conductive fracture with minimal formation damage.

In coal seams where proppant may not be needed due to low closure stresses, stable foam alone can be an efficient fracturing fluid. With higher viscosities and better fluid-loss control properties than previous foams, a wider and longer fracture can be generated with similar volumes of fluid.
Recovery of Gas From Hydrate Deposits Using Conventional Technology
Authors: McGuire Patrick L.
Published: December 2007

Methane hydrate gas could be a sizable energy resource if methods can be devised to produce this gas economically. This paper examines two methods of producing gas from hydrate deposits by the injection of hot water or steam, and also examines the feasibility of hydraulic fracturing and pressure reduction as a hydrate gas production technique. A hydraulic fracturing technique suitable for hydrate reservoirs is also described.
Unconventional Ideas About Unconventional Gas
Authors: Rose Walter , Pfannkuch Hans Olaf
Published: December 2007

Vast quantities of natural gas exist as solid hydrates in the world's permafrost and deep sea environments. Russian experts estimate potential resources in excess of 107 TCF natural gas. Geophysical inference and direct sampling seem to substantiate the existence of hydrates where thermodynamic conditions are favorable. Their ubiquity provides an interesting link to another unconventional hypothesis of unconventional gas supply, namely the abiogenic origin of deep earth gas. A method to evaluate the abiogenic hypothesis is to compare the isotopic, trace element and compositional signature of hydrate samples from deep lake sediments in basins over crystalline basement rocks (Lake Superior) and over sedimentary rocks in connection with a producing, petroliferous province (Lake Michigan). Because of the complex relations between in situ dissociation and production of the free gas phase actual extraction methods will be technically complicated. A method to circulate warm surface water through a set of injection and withdrawal wells in deep sea hydrate deposits promises some advantages over conventional offshore drilling practices. Even if only a fraction of the claimed hydrate resources are accessible and producible the absolute amount is still very large compared to all other conventional and unconventional gas resources.
A Hydrodynamic Analogy of Production Decline for Devonian Shale Wells
Authors: Pullé Christopher V.
Published: December 2007

Several studies on production decline curves have shown that an exponential or hyperbolic curve adequately fits production decline data for Devonian shale wells. Attempts to characterize the production decline based on open flows, rock pressures, and specific shale production mechanisms have also been made. This paper seeks to provide a genesis of the decline curves with the use of a simple hydrodynamic analogy. Some physical factors critical to well productivity are also examined.
Production Systems Analysis of Vertically Fractured Wells
Authors: Meng Hai-Zui , Proano Eduardo Antonio , Buhidma Ismail M. , Mach Joe M.
Published: December 2007

A systematic approach is presented for generating transient inflow performance relationship curves for finite conductivity vertically fractured wells. A semi-analytical model was developed to simulate dimensionless wellbore pressure drop and dimensionless pressure loss through the fracture vs. dimensionless time at constant-rate of production for wells intercepted by a finite-conductivity vertical fracture. Flowing bottom hole pressure can be predicted at any time period using these dimensionless variables. System average pressure at any stage of production can be obtained through material balance calculations.

A straight line reference curve was observed at all times provided that the real gas pseudo-pressure function is used to plot m(pwf(t))/m(p¯R(t)) vs. qg(t)/qgmax (t). The advantage of normalizing the dimensionless variable in termas of pseudo-pressure function is that only one straight line relationship is obtained throughout the entire production life of the reservoir. This provides a more simple means for performance prediction purposes.

The major contribution of this paper is the provision of a valuable tocl to study the sensitivity of fracture design parameters on ultimate well performance. The economic benefits of this approach can be substantial.
Optimization of Hydraulic Fracturing Techniques for Eastern Devonian Shales
Authors: Swartz Greg
Published: December 2007

A laboratory test program was performed to evaluate the physical characteristics of Devonian Shale reservoirs from six wells in the Appalachian Basin, four in Ohio and two in New York. As hydraulic fracturing is a mainstay for increasing well production, the interaction between fracturing fluids, the formation, and proppant in the induced fracture becomes of prime importance. In analyzing the physical characteristics of the core material, three types of tests were performed: physical properties, matrix permeability damage, and fracture conductivity damage.

Results of the physical properties testing indicate that the typical Devonian shale matrix was dense and of low porosity, averaging 2.75 gm/cc and 6 percent, respectively. In situ permeability values of the tested samples averaged 66 μd, with 9 of 13 samples below 10 μd. Fracturing fluid matrix damage tests were performed with three different fracturing fluids for comparison: a water-based gel (cellulose thickener), a nitrogen foamed liquid (75 percent quality), and a brine/CO2 mixture fracturing fluid. Recovery was based on the calculated ratio of final permeability to initial permeability. Results from these tests show better recoveries from those samples exposed to the nitrogen foam, up to 18 percent. Fracture conductivity damage tests were performed with the same fracturing fluids. Results of these tests give recovery values of 35 to 100 percent. Nitrogen foam gave better results. All testing of reservoir material, except some basic physical properties, was conducted at simulated in situ conditions.
Successful Deep Openhole Cement Plugs for the Anadarko Basin
Authors: Dees John M. , Spradlin William N.
Published: December 2007

A cement plug is placed above a non-retrievable fish when a hole is to be sidetracked. The plug provides support and strength to commence deviation from the original hole. Setting a firm high strength cement plug in order to sidetrack is a difficult task. The volume of wellbore and displacement fluids are quite large compared to the volume of cement in the plug. This situation is compounded in a deep hole. Placement of the cement slurry without contamination from wellbore and displacement fluids becomes an exceedingly difficult task. Several cement plugs may be required before a successful plug is set.

The techniques described were developed for sidetracking purposes. However, they can be applied in setting other types of cement plugs.

Parameters involved in properly setting an open hole cement plug are defined in detail in this report. The primary objective of this work was to define techniques and materials necessary to optimize success with deep hole cement plugs. Important factors in successfully setting an open hole cement plug are hole condition, mud condition, cement composition, and placement technique. An example is included describing a successful technique used to set deep open hole cement plugs in the Anadarko Basin.
Fracture Width—Design vs. Measurement
Authors: Smith Michael B. , Rosenberg Randi J. , Bowen Jerry F.
Published: December 2007

Current fracture designs are based on choosing fracture height and using a 2-D approximation to calculate fracture width. There are however, two approximations which can be used, leading to greatly different designs in terms of fluid volume, pad volume, etc. Given this discrepancy, accurate in-situ measurements of fracture width are needed to help define fracture geometry.

The purpose of this paper is to present measurements made with a downhole closed-circuit television camera during a fracture stimulation (without proppant) of an oil bearing sandstone formation in an effort to investigate the applicability of the two fracturing models. Data is presented showing fracture width as a function of height and pressure. The measured widths are briefly compared to different design theories.
Local Mesh Refinement for Finite Difference Methods
Authors: von Rosenberg Dale U.
Published: December 2007

A method of local mesh refinement has been developed in which additional nodes are used only in regions where they are necessary. The extra mesh lines are not extended across the entire simulator as in the usual current practice. Refinement of a two-dimensional element, herein defined as the rectangle formed by mesh lines with nodes at the vertices, consists of bisecting it in each coordinate direction, thus dividing the original element into four smaller, but similar ones, and creating five nodes. The resulting smaller elements may themselves be refined by the same procedure. An element must be refined if two adjacent elements of the same size have been refined or if one smaller adjacent element has been refined. Three configurations of five nodes each which arise in current refinement methods also appear in the new procedure. In addition, a configuration of six nodes also occurs. Finite difference analogs for all configurations were developed.

An extensive study of local mesh refinement near a well was made for the repeated five spot in a homogeneous reservoir with unit mobility ratio. Results of the finite difference solutions were compared with the analytic solution. Generally, it was found there should be at least two consecutive increments of the same size between changes in increment size. When this practice is followed, a local minimum in truncation error occurs at each node where there is a change in increment size. The more accurate solution obtained in the vicinity of the well by use of smaller increments there results in a more accurate solution also in the coarser unrefined mesh. Some improvement elements with the well node as a vertex. An effective refinement was one using increments which were one half and one fourth the size of those in the coarser mesh. Four small increments were used nearest the well, and four was obtained by one refinement of the four mid-sized ones were used between these and the coarsest mesh. Results are presented to aid the reader in selecting the extent of refinement he desires.
An Improved Method for the Determination of Pseudo-Relative Permeability Data for Stratified Systems
Authors: Simon Andrew D. , Koederitz Leonard F.
Published: December 2007

A procedure for modifying relative permeabilities for use in an areal model becomes necessitated in reservoir cases for which vertical equilibrium pseudo functions are not applicable and the displacement process is dominated by viscous horizontal flow. In practice, the areal model representation of stratified flow in such cases will lie between the extremes of the performance of a homogeneous layer of parallel-average permeability and the performance of a series of non-communicating layers. To date, the only analytical method specifically developed to approximate viscous flow in a stratified reservoir with an areal model is attributed to Hearn. This method employed the assumption of a unit mobility ratio displacement to generate pseudo relative permeability curves reflecting an instantaneous change from non-wetting phase to wetting phase production at each layer breakthrough. Due to this assumption, the history match procedure involved correcting for both the effects of crossflow and subordinate non-wetting phase production after breakthrough. A technique has been developed to account for the effects of subordinate phase production in a non-unit mobility ratio displacement occuring in noncomrnunieating layers. This adaptation is an improvement to the original method of Hearn, providing both a closer initial approximation to reservoir fluid flow in stratified systems, as well as affording a consistent basis for history matching through adjustments to relative permeability.
Isobaric Heat Capacities of Natural Gases at Elevated Pressures and Temperatures
Authors: Abou-Kassem J. H. , Dranchuk P. M.
Published: December 2007

A new correlation has been developed for ideal isobaric heat capacity for natural gases. It is applicable over the temperature ranges of 32 ≤ T°F < 2240 and 32 < T°F < 300 for sweet and sour gases respectively. In addition a new generalized mathematical correlation was developed for the isobaric heat capacity departures, for such gases, which is applicable over the range of variables 0.2 ≤ Pr ≤ 15 and 1.05 ≤ Tr ≤ 3.0. This latter correlation is based on a reduced form of the BWR equation of state.

Both correlations are adaptable to computer application. Comparisons with data from the literature are presented and discussed.
Water Can Be Controlled in Air and Gas Drilling
Authors: Hower Wayne F. , McLaughlin Charles , Ramos Joe , Land John
Published: December 2007

The control of water in air-drilled wells is a difficult problem and quite different from conditions normally encountered in oil producing wells. To evaluate better the many materials developed by laboratory research, several relatively shallow wells were drilled adjacent to the Research Center. In this way, materials and placement techniques could be evaluated under controlled field conditions. The research program, to date, has developed two distinctly different materials that promise to be adaptable for most of the varied water control conditions encountered in the industry. One material is a very low viscosity solution that, with time, sets to form a stiff gel. The other is a liquid synthetic resin that can be used by itself or in a slurry with fluid loss additives. The resulting set of the resin or slurry is strong and is capable of holding back higher pressures than the stiff gel. Both the stiff gel and resin materials have been applied successfully in the designed use and are also being successfully applied in other water control problems. The material that sets to form a stiff gel is particularly adaptable for many types of fluid grouting problems where stabilization of soil as well as water control is desired.

Research is continuing in an effort to improve the present materials and placement techniques. New ideas are also being investigated. One is a gaseous system that has given encouraging results in initial tests.

Introduction

The substitution of air or gas for all or a part of the mud used in drilling for hydrocarbons has presented a new and difficult problem to the industry. This problem is the economic control of water that is normally suppressed by conventional heavier muds.

Many papers have been published during the past few years describing practically every aspect of "air" drilling. Increased drilling rates and longer bit life have been reported which have contributed to significant savings in rig time. The resulting economic advantage has varied for different areas and, where no particular troubles were encountered, savings were phenomenal. As experience was accumulated in this type of drilling, its advantages and disadvantages became more exactly defined. In some instances, the disadvantages outweighed the advantages and caused a cessation of this type of drilling in the particular area. In almost every case, influx of water to well bore was the major cause for return to conventional drilling methods.

All kinds of water production have been encountered and each type presents its own particular problem. The weeping or very low water producing zones provide enough water to wet the cuttings but not enough to flush them out of the hole.
Underground Coal Gasification of Steeply Dipping Beds: A Second Generation Synthetic Fuels Process
Authors: Davis Burl E. , Ahner Paul F.
Published: December 2007

In situ gasification of steeply dipping coal beds (UCG-SDB) has significant advantages over the more conventional horizontal UCG. In fact, the UCG-SDB process appears to be both technically and operationally competitive with surface gasifiers. The results of the Rawlins UCG-SDB field test program suggest that the process can compete with more conventional sources of synthesis gas on an economic basis. The SDB process mechanism has several advantages over the horizontal process and performs in a fashion similar to surface packed-bed reactors. The oxygen requirements for the process are quite low and the degree of process control observed at Rawlins is very attractive.
Geology of Post West (Strawn) Field, Garza County, Texas
Authors: Myers Sherris R.
Published: December 2007

Post West (Strawn) Field, in Garza County, Texas, has a structurally and stratigraphically controlled hydrocarbon trap. The field produces oil from a structure with fifty feet of closure in two of four reservoir zones. The geologic study of the Strawn reservoir described in this paper should aid in hydrocarbon reserves calculations.
Polycrystalline Diamond Compact Bit Hydraulics
Authors: Knowlton R. Helene , Huang Hsin
Published: December 2007

It is well understood and documented that bottom-hole hydraulics plays an important role in conventional diamond bit performance. Recent industry experience has shown a similar importance with the new synthetic diamond compact bits. Certain types of polycrystalline diamond compact bits have cutters arranged in a reverse spiral mode. For optimum performance bit hydraulic design should be tailored to that reverse spiral mode. Theory reveals that a bit built with rectangular nozzles with a long axis in the tangential direction can give a fluid velocity envelope similar to the envelope of the reverse spiral. A rectangle can also reduce bit plugging by providing an increased perimeter in a non-concentric geometry. The introduction of rectangular nozzles into the bit renders the regular round nozzle pressure drop equation unsuitable for direct application. Extensive hydraulic tests were performed with different configurations of rectangular nozzles to establish more accurate pressure loss equations. The experiments included single nozzle studies and laboratory and field tests of bits. Field test results confirmed the reliability of the results obtained in the laboratory studies.
The Effects of Shear and Proppant on the Viscosity of Cross-Linked Fracturing Fluids
Authors: Gardner David C , Eikerts John V.
Published: December 2007

Several frequently used cross-linked fracturing fluids, hereafter referred to as gels, have been evaluated as to the effects that shear and that 20/40 mesh sand proppant have on their rheological properties. A closed-loop pipe viscometer was used to evaluate the shear resistance and post-shear recovery of various gels as a function of pH, cross-linker type, polymer concentration, shear intensity (shear stress and shear rate), and shear duration. The aqueous-base gels that were tested included those made with guar, hydroxypropyl guar (HPG), and carboxymethyl hydroxyethyl cellulose (CMHEC) polymers. Selected aqueous-base gels were also evaluated as to the effect on slurry viscosity of varying concentrations of 20/40 mesh sand proppant.

Test results indicate that when cross-linked with borate ions, guar and HPG gels have the greatest resistance to shear. Yet when cross-linked with various titanates, HPG gels showed significantly lower resistance to induced shear. Tests on CMHEC gels which were cross-linked with trivalent aluminum (Al+++) indicate a shear resistance between that of the HPG-borate gels and that of the HPG-titanate gels. Also tested was post-shear recovery or the percentage of viscosity increase following high shear exposure as correlated to field tubular pumping conditions. The HPG-borate gels and the CMHEC-Al+++ gels demonstrated considerably higher post-shear recoveries than those attained with HPG-titanate gels. In addition, the effect of 20/40 mesh sand on the viscosity of gels is a larger increase in slurry viscosity in the fracture than that predicted from Newtonian slurry mathematical models.

Finally, laboratory study indicates that the actual slurry viscosity, accounting for shear and proppant effects within the fracture, is apparently moderately to extensively lower than that predicted by conventional rheological methods.