bluuebunny/crossref_metadata_2025 huggingface dataset:
Stress-Sensitive Fracture-Flow Modelling in Fractured Reservoirs
Authors: Jolly R. J. H. , Wei L. , Pine R. J.
Published: December 2007

The flow characteristics of fractures are significantly affected by the stresses acting upon them. Reservoirs where the majority of the fluid flow is through fractures are very sensitive to the stress regime and its perturbations. Activities, such as production from a reservoir or injection into a reservoir, cause changes in the fluid pressure. This will alter the effective stress, which in turn will affect the flow of hydrocarbons through the fracture network. In order to understand how hydrocarbons flow within a fractured reservoir it is necessary to determine the influence of both stress and fluid pressure in a fracture network.

There have been many experimental studies showing the influence of stress on the flow of fluid through single fractures from which a relationship between fracture permeability and effective stress can be developed. Effective stress acting on a fracture can be established by considering the orientation of the fracture relative to the in-situ stress regime and the fluid pressure within the fracture. Once the effective stress acting on a fracture has been found the corresponding permeability can be assigned within a discrete fracture network (DFN) model. This approach then allows examination of stress-sensitive flow within fractured reservoirs.

This paper presents a methodology for incorporating in-situ stresses and stress changes due to production and injection in DFN modelling. The approach is significantly different from published methodologies on this subject, which are based on continuum porous medium modelling. By simulating and interpreting well tests in the fracture network during reservoir appraisal and after significant production, the presented approach would help in determining the influence of stress on hydrocarbon flow within a fracture network and to optimise future well locations and orientations.
Coupling Fluid-Flow and Geomechanics in Dual-Porosity Modeling of Naturally Fractured Reservoirs – Model Description and Comparison
Authors: Chen Her-Yuan , Teufel Lawrence W.
Published: December 2007

The objective of this paper are: (i) to summarize a recently developed coupled fluid-flow/geomechancs, dual-porosity model intended to describe the behavior of naturally fractured reservoirs, and (ii) to analyze and compare four other existing models. Conceptual consistency is examined for each model within the concept of dual-porosity. The comparison provides important understanding and interpretation to the complex model parameters.
Relative Permabilities of Gas-Condensate Fluids in Heterogeneous Porous Media
Authors: Moctezuma-Berthier A. , Samaniego F. V.
Published: December 2007

Reservoir cores have complex porous structure and conventional approach to characterize two phase flows in the laboratory can be inadequate, especially in presence of fractured or vuggy porous media. An important problem is the determination of the relative permeabilities to the interpretation of two phase flow experiments. The relative permeability analysis for gas and condensate fluids presents special interest due to changes in fluids properties, like interfacial tension and viscosity due to compositional changes. In this way, relative permeability curves depend on the capillary number; thus the experimental conditions for the fluids and porous media must be carefully analyzed in order to get representative reservoir conditions.

This work presents a methodology for the realization of laboratory representative studies of flow in heterogeneous cores flowing with gas and condensate equivalents fluids. The relative permeability curves are found fitting the oil production and pressure drop experimental data with a compositional simulator. This simulator was used to have a detailed behavior of the fluids during the experiment.

Selection of the equivalent fluids was made plotting the derivative of the capillary number with respect to pressure vs. capillary number. We analyzed the curve for different mixtures and results compared with the reservoirs fluids curve. With this analysis, we got a pressure interval for the experiment and the required composition, the required to prepare a mixture which capillary number behavior was like reservoir fluids.

In order to reproduce the detailed petrophysical model of the sample, the longitudinal porosity distribution was gotten from X-ray computerized tomography. In addition, the petrophysical porosity and effective permeability behavior of the sample for different confining pressures was done.

This methodology was applied to fluids and samples from a carbonate fractured gas and condensate reservoir from Gulf of Mexico. It was possible to get the relative permeability curves using a binary mixture of C1-C10 in a specific range of pressure, where the capillary number for both real and mixture was quite similar. The match between laboratory and simulation results was very good.
Adjustable Rate Drilling Contracts - Go With the Flow?
Authors: Moomjian Cary A.
Published: December 2007

This paper reviews adjustable rate drilling contracts from philosophical and practical perspectives and discusses various means of structuring contractual provisions which adjust dayrates to reflect published rig rates, commodity (oil or gas) prices, an index or other designated measuring device. The analysis considers selection of an appropriate driver for rate adjustments, frequency of rate adjustments, use of a rate "floor" and "ceiling", and associated issues. The discussion reviews the attributes and drawbacks of adjustable rate drilling contracts, considers potential drivers for rate adjustments and evaluates hypothetical applications.
New Technology in Diamond Drill Bits Improves Performance in Variable Formations
Authors: Beaton Tim , Johnson Keith
Published: December 2007

Recent advances in diamond bit technology have helped to bridge the gap between polycrystalline diamond compact (PDC) and diamond impregnated bit applications. A new type of diamond bit has been developed to effectively drill hard, abrasive formations, while retaining the ability to efficiently drill through non-abrasive sections. This new type of diamond bit utilizes a three part cutting structure consisting of PDC cutters, diamond impregnated blades, and hot pressed diamond impregnated inserts.

Technological advances in the design and manufacture of diamond bits have greatly expanded the applications of both PDC and diamond impregnated bits. However, there are still many intervals of hard rock drilling which have sections that are too hard or abrasive for a conventional PDC bit, but also contain sections that are not sufficiently abrasive to be effectively drilled with a conventional diamond impregnated bit. Drilling these types of intervals with conventional drill bits has proven very costly. Operators have been forced to choose between incurring expensive trip times, due to the need to frequently change out bits to maximize the rate of penetration (ROP) in the different formations, or suffering through the very slow penetration rates typical of conventional impregnated drilling in non-abrasive formations.

A very successful run has recently been completed with this new diamond bit in the Huamampampa formation in Tarija, Bolivia. In a long, 8 ½" hole size section, where the shale content ranged from 10 to 90%, this new bit type drilled to TD with a higher overall rate of penetration than any offset. The combination of PDC cutters with hot pressed diamond impregnated inserts in a diamond impregnated matrix has proven to be a very versatile cutting structure in variable formations.
Optimization of Stress-Relief Grooves for Rotary Shoulder Connections
Authors: Hommel Mark
Published: December 2007

Field experience and finite element studies have established the effectiveness of utilizing a stress relief groove on the pin of a threaded connection to prolong its life. Nevertheless, the exact design geometry of the stress relief groove is subject to discussion and even controversy. Moreover, the need to recut damaged threads on extant tools motivates the minimization of stress relief groove width so that subsequent machining will not be precluded.

The purpose of this paper is to present some finite element results which examine the dependency of stress on stress relief groove width and thread runout.

A parameterized finite element model of a 5-1/2 F.H. threaded connection has been developed which allows the variation of the width of the stress relief groove. Stresses are computed for a variety of widths. It is found that an optimal width does in fact exist. Widths shorter than optimum simply introduce further stress concentrations due to the presence of unnecessary pin threads, while stress relief grooves with a larger width than optimum tend to load up the remaining threads excessively.

An unexpected result of this study is that the finite element results are strongly dependent on thread runout. This is not a factor for stress relief goove widths greater than approximately 1 inch. But for shorter widths, box thread runout is a factor because the partial box thread which engages the apparent last engaged thread of the pin causes a lower stress to be set up in the pin, compared with what it would be if a full thread were engaging the pin. In other words, thread runout works in the operator's favor in applying a more gradual load to the pin threads compared to what it would be in the absence of runout.

From this it is concluded that a re-examination of tolerances on stress relief groove width and also box counterbore depth is needed.
Development of OCTG Connection for Automated Drilling Rigs
Authors: Maruyama K. , Tsuru E. , Wada Y. , Tsukano Y.
Published: December 2007

Automated drilling technology in offshore rigs is becoming increasingly important. It provides for safer working environments and increased efficiency. New tubular handling equipment and remote controlled power tongs are integral components of the new automated rigs. Connection manufacturers have to develop new products that are compatible with the new technology.

In the conventional tapered connection it is possible to wedge the threads crest to crest, commonly resulting in a "galled" connection making it unusable. When manual tongs are used, the human operator is more responsive to this condition and takes corrective action prior to connection damage. With automated tongs, when this condition occurs, it is less likely to be recognized and reacted to before substantial damage has occurred.

This paper describes the research data of a newly developed tapered connection design. The design is capable of being assembled quickly and easily with the characteristics of simple easy stabbing and high galling resistance. The development incorporates a unique thread profile that is distinctly different from current OCTG thread forms. The new thread form may be applied to other connections that use the API Buttress type thread form.
Reeled Pipe Technology for Deepwater Drilling Utilizing a Dual Gradient Mud System
Authors: Fontana P. , Sjoberg G.
Published: December 2007

The search for hydrocarbons is constantly moving into deeper and deeper waters. This introduces new challenges to the drilling industry as production demands requires that large, high volume completions are placed in these wells. In addition, narrow pore pressure and fracture pressure margins increase the number and subsequently size of casings to be set.

The use of a "Dual Gradient" drilling system provides an answer to these challenges.

The use of large diameter "Reeled Pipe" further facilitates the dual gradient drilling process.

The DeepVision project has developed and tested several critical components of such a system. The system includes a subsea centrifugal pump system, large diameter reeled pipe up to 5.5", bottom hole assembly components, and a new injector head concept for the reeled pipe. The project is ready to be advanced into prototype field testing and commercialization.
Denver Unit Infill Drilling and Pattern Reconfiguration Program
Authors: Thai B. N. , Hsu C. F. , Bergersen B. M. , Albrecht S. L. , Richardson T. W.
Published: December 2007

The Denver Unit CO2 flood, one of the largest in the world, was implemented in 1984. CO2 injection was subsequently expanded in 1989 and again in 1991. By 1994, this 10 year old CO2 flood had a well-established decline in its production function. Through infill drilling and pattern conversion, the mature CO2 flood in the Denver Unit was revived. The redevelopment program depended heavily on the reservoir simulation technology and the multi-discipline team concept to ensure its technical and economical success. Thus far, the redevelopment program has added approximately 6600 barrels of oil per day to the existing production at peak rate, and approximately 14.2 million barrels of oil to the ultimate reserves. This report reviews the infill drilling and pattern reconfiguration simulation studies, the pilot program, which led to full field development, and the results of the project to date.
A New Technique to Determine Porosity and Deep Resistivity from Old Gamma Ray and Neutron Count Logs
Authors: Wo S. , Weiss W. W. , Balch R. S. , Scott L. R. , Kendall R. P.
Published: December 2007

Multivariate correlations developed via radial-basis function (RBF) network analysis of a modern suite of logs are used to estimate crossplot density-neutron porosity and pseudo-deep resistivity from 1950's vintage well logs. Historically, porosity has been estimated with the logarithm of the neutron count rate standardized with a 2% porosity tight spot and a maximum porosity of ~40% in a shale stringer. Despite a frequently observed visual correlation of the gamma ray track with the neutron count rate, the gamma ray log information is not included in conventional porosity estimates.

The visual comparison of the openhole gamma ray and the neutron porosity to the shape of the crossplot porosity from a new well, Foster 4, is similar to the pattern seen between the old gamma ray and the neutron-count rate logs. The new log data were investigated with various RBF networks to correlate the gamma ray and neutron-count rate with the crossplot porosity. An optimal RBF network was then used to estimate the crossplot porosity of the Penrose sand for 22 wells in the Reed Sanderson Unit where only cased-hole gamma ray and neutron-count rate logs are available. An equation converts the modern neutron log to the old style neutron count rate while providing a normalized input to the network training. The "goodness" of the RBF network predictions was validated via exclusion testing.

A similar procedure was used to estimate a pseudo-deep resistivity in old wells. The study indicated that a carefully trained RBF network could identify the high resistivity intervals (shale stringers) with only gamma ray and neutron count rate used as the network inputs. The methodology presented should prove useful to others faced with characterizing old fields.
Time-to-Depth Conversion of Nash Draw "L" Seismic Horizon using Seismic Attributes and Neural Networks
Authors: Hart D. M. , Balch R. S. , Weiss W. W. , Wo S.
Published: December 2007

Well log and 3-D seismic data were used to construct three depth maps for the top of the target L horizon of the Nash Draw field in southeastern New Mexico. The first two depth maps were made using Landmark° software packages TDQ and Z-map. The third depth map was made using a multilayer perceptron (MLP) neural network to regress for velocity at each seismic bin. At Nash Draw the wells are confined to the central region of the seismic survey, and conventional geostatistics reliably interpolated depths only in the region defined by well control. The MLP approach used the best three of 28 statistically ranked seismic attributes to predict the average velocity field from the surface to the L horizon. Each map was constructed using 15 wells as control points with three wells excluded for testing. Test wells one and two were located away from the control wells and have anomalous average velocities/depths.

Accurate depth maps are useful for reservoir development, particularly for stratigraphic and structural trap location, drilling depth and reservoir modeling.

The three test wells were used to compare the robustness of the computed depth maps, and all depth predictions were compared to the true depths determined from gamma ray logs for each well. TDQ, Z-map and MLP predicted values within 229.4, 104.7 and 7.6 feet, respectively, at test-well-1; 129.4, 47.7 and 43.7 feet, respectively, at test-well-2; and 12.4, 4.1 and 16.5 feet, respectively, for test-well-3.

Geostatistical methods underestimate the depths to the top of the L for the test wells lying outside the central clustering of control wells, while the MLP solution calculates a relationship that should be valid in each seismic bin in the field. Further refinements in the data and improved methodology are expected to yield a higher degree of accuracy between the real and predicted depths using MLP.
Iterative Method To Determine Gas Reserves Using Material Balance and Pressure Transient Analysis
Authors: Sehbi Baljit S. , Frailey Scott M. , Lawal Akanni S.
Published: December 2007

The p/z vs. Gp material balance approach is an established, simple, quick and convenient means of surveying a reservoir's performance and determining gas reserves and gas-in-place (G). The x-intercept is G. Unfortunately, this approach may be an independent analysis, and not confirmed with a separate method.

Theory requires that the "p" in the p/z term to be the average reservoir pressure at which a cumulative production of Gp occurs. A source of average reservoir pressure is a pressure buildup test in which the MBH method is used to find average reservoir pressure. The MBH method requires an estimate of drainage area (A), which is directly related to G (∞Ah); this is termed GMBH. The average reservoir pressure that was calculated using the estimated A are plotted as p/z in the material balance plot. An extrapolation of the trend to the x-axis is Gp/z. The GMBH and Gp/z are used iteratively until the two estimates of G converge.

This proposed method is tested on synthetically derived pressure data simulated with a commercially available, analytical well testing program for two different reservoir shapes and three different well locations. One single-well gas reservoir is analyzed for the case study.
New Dual-Probe Wireline Formation Testing and Sampling Tool Enables Real-Time Permeability and Anisotropy Measurements
Authors: Proett Mark A. , Chin Wilson C. , Manohar Mohan , Gilbert Gregory N. , Monroe Myrick L.
Published: December 2007

A recently introduced wireline formation-testing tool incorporates new digital control technology to significantly improve formation pressure testing and fluid sampling. Closely spaced dual probes are simultaneously deployed for pressure testing and fluid sampling. Besides increasing tool reliability through redundancy, the two probes allow for advanced pressure-testing techniques. For example, formation anisotropy can be determined with an interference test between the two probes. Alternatively, a new pressure-pulsing technique can be used, which uses time delays between the probes’ measured pressures to determine additional hydraulic diffusive properties of the formation. The drawdowns can be rate- or pressure-controlled from either probe, making it suitable for pressure testing in very low to high permeability formations (0.001 to 1000 md).

A primary focus of the new technology is improving the quality of reservoir fluid samples. An innovative pump-out design using a digital control feedback system enables the tester to continuously monitor the fluid sampled and to make precise adjustments to the rate and pressure at which the fluid is withdrawn from the formation and injected into a sample chamber. Because the tool design incorporates a powerful pumping-system motor and an efficient hydraulic system, invaded fluids surrounding the probes, such as mud filtrate, can be flushed 50% faster than other wireline test tools, thereby enabling quicker sampling of virgin formation fluids. Sample chambers can be filled against hydrostatic pressure to ensure pressure-volume-temperature (PVT) quality samples, and additional pressure can be applied to minimize phase changes that might otherwise occur because of temperature gradients in the borehole. The new system can also be used to perform a closed-chamber PVT test for the bubble point of the fluid sampled.

This paper details operational features of the new tester and introduces new pressure-testing and sampling interpretation techniques. Field-test results are used to demonstrate these features and techniques.
Asphaltene: To Treat or Not
Authors: Becker Harold L.
Published: December 2007

The work described in this paper has been conducted over several years under both laboratory and field conditions. Several field case histories and supporting laboratory observations are presented to substantiate the conclusions expressed.

Asphaltenes are often invoked to describe the nature of organic damage and obstructions found when atypical forms of organic deposits appear. In fact a majority of problems studied by this laboratory have been misidentified as asphaltene when the true problem was due to paraffin wax deposition. Asphaltenes are poorly understood, consequently methods aimed at dealing with deposit mechanisms and chemical prevention present a doubly difficult challenge. Asphaltene deposition mechanisms and the chemical structures responsible are less well characterized than those of emulsion breaking, corrosion protection, and paraffin deposit control. Since most asphaltene deposits are associated with paraffin and there exists many proven methods of paraffin control, in many cases it makes better sense to attack organic deposit problems with paraffin control products than some unproven "asphaltene inhibitor".

This paper suggests that adequate methods exist today for the removal and control of paraffin wax damage, and that methods for the control of asphaltenes are still in a relatively embryonic state of development. Until the day comes that asphaltenes are well understood chemically, as are waxes, emulsions, corrosion, and scale, the hope of economically treating them will remain a problem for research.
Plunger Lift Benefits Bottom Line for a Southeast New Mexico Operator
Authors: Schneider T. S. , Mackey V.
Published: December 2007

The development of the Eumont gas play in Lea County, New Mexico created unacceptably high operating costs associated with gas well production. Two major issues were economically producing low pressure gas wells (1.5-2 psi/100 feet) with low connate water production and proppant production. The first choice for artificial lift once loadup occurred was beam pumps. Sand production and low fluid volumes however forced a paradigm shift to evaluate plunger lift as an alternative based on the low fluid volumes and low bottom hole pressures. The end result has reduced operating costs by over 70% in the areas that plunger lift has become the primary artificial lift method and reduced the lease expense per BOE by 25% over the 2-1/2 year implementation period.

This paper discusses the steps taken to apply basic plunger lift concepts and progresses to the current plunger lift system that incorporates annular flow to minimize bottom hole pressure; therefore maximizing production. Evidence will be presented to validate that switching from beam pump to plunger lift has on average increased production. Integrating this "new found" technology on high GLR oil wells has been beneficial as well.
Practical Applications of Compressor Sizing
Authors: Gajjar Hasmukh N. (Hasu)
Published: December 2007

Production companies purchase natural gas compressor packages designed for specific operating conditions. When those conditions change, the operator may be uncertain about utilizing the compressor package on the same application or moving it to another location. By following a concise procedure, an operator can determine the fitness of equipment for a new assignment. He must take into account the performance parameters of the engine, the compressor frame and cylinders, and the heat exchanger. With full information on gas analysis, brake horsepower of the engine, compressor frame and cylinder sizes, and pressure pulsation control, the operator can make the most efficient use of equipment.
New Production Logging Sensors Revolutionize Water/CO2 Conformance in the Pumping Wells of West Texas
Authors: Logan Dale , Strubberg Carl , Conner John
Published: December 2007

The Permian Basin is a mature oil province where many fields are under secondary and tertiary recovery. Waterfloods abound and it is not uncommon to have wells that make 20 BOPD and 2000 BWPD. At today's oil price the economics of these fields are marginal on a good day. The operators of these reservoirs would like to be able to shut off some of the water production without losing a drop of their meager oil production. Ideally, the drop in water production would affect relative permeability and result in an increase in oil. The only technique available to shut off water has been the "plug-and-see" (also known as the hunt-and-peck) method. Experience with this technique indicates that in 60% of the cases either the water cut increases or the oil production decreases.

If the reservoir engineers better understood where the oil and water were coming from they would be more successful in using plugs to decrease the water flow. There have been two major roadblocks to the successful application of production logging. First, the wells do not flow naturally so pumps are used. As a result the production logging string cannot get to bottom. Second, even if tools could be placed below the pump, conventional production logging tool strings cannot accurately detect oil cuts below 5%. Until the introduction of the new PS Platform* production services tool string, West Texas waterflood operators had no way to accurately determine what was happening downhole.

The sensors on the PS Platform string not only measure very low oil cuts, but the tool string has also been placed below electronic submersible pumps (ESPs) in an ingenious rig-up technique that required a joint effort between Schlumberger Wireline and REDA. Once the pump is turned on and flow stabilizes, the sensors can measure very low oil rates accompanied by high water rates.

This paper describes the use of the new technique on two wells in the Altura Midland Farms Unit. In both cases the PS Platform was deployed below an ESP and delivered high-quality answers that significantly impacted the economics of the field. These successes consequently lead to the use of the PS Platform sensors, in conjunction with TDT* Thermal Decay Time tool, in tertiary CO2 floods.
Low Permeability Gas Reservoirs and Formation Damage -Tricks and Traps
Authors: Bennion D. B. , Thomas F. B. , Imer D. , Ma T.
Published: December 2007

As drilling and completion technology advances, the trend to exploitation of gas reservoirs exhibiting ever lower permeabilities continues. This paper discusses issues associated with the identification of productive, low permeability, gas-producing formations and the successful completion and production of these reservoirs. For the purposes of this paper, a very low permeability gas reservoir is defined as a formation having an in-situ matrix permeability to gas of 0.5 mD or less. Criteria are presented for identifying economic absolute permeability cutoffs for low permeability gas-bearing formations. Very low permeability gas reservoirs are typically in a state of capillary undersaturation where the initial water (and sometimes oil) saturation is less than would be expected from conventional capillary mechanics for the pore system under consideration. These formations are commonly referred to as dehydrated or desiccated formations and have been documented on a worldwide basis. Retention of fluids (phase trapping) is discussed as one of the major mechanisms of reduced productivity, even in successfully fractured completions in these types of formations. As well, a variety of diagnostic and remedial treatment options are presented.
Residual Gas Saturation Revisited
Authors: Kantzas Apostolos , Ding Minghua , Lee Jong
Published: December 2007

The determination of the true residual gas saturation in gas reservoirs is addressed in this paper. It is customarily assumed that when a gas reservoir is overlaying an aquifer, water will imbibe into the gas-saturated zone with the onset of gas production. The process of gas displacement by water will be forced imbibition in areas of high drawdown and spontaneous imbibition in the areas of low drawdown. It is further assumed that in the bulk of the reservoir spontaneous imbibition will prevail and that the reservoir is water-wet. A final assumption is that the gas behaves as an incompressible fluid. All these assumptions are challenged in this paper. The topics of imbibition and wetting phase film flow are reviewed along with a brief summary of the work on the determination of residual gas saturation to date. Furthermore, a series of experiments are presented whereby it is demonstrated that the residual gas saturation obtained by a short imbibition test is not necessarily the correct residual gas saturation. Imbibition tests by different methods yield very different results, while saturation history and core cleaning also seem to have a strong effect on the determination of residual gas saturation. In some cases, it was found that the residual gas by spontaneous imbibition was unreasonably high. This was attributed to weak wetting conditions of the core (no water "pull" by imbibition). It is expected that this work will shed some new light in an old but not so well understood topic.
Properties of Paleocene Fort Union Formation Canyon Seam Coal at the Triton Federal Coalbed Methane Well, Campbell County, Wyoming
Authors: Nelson Charles R. , Hill David G. , Pratt Timothy J.
Published: December 2007

This paper presents results from evaluations of geochemical, petrographic and reservoir properties of Powder River Basin, Paleocene Fort Union Formation Canyon seam subbituminous coal at the Triton Federal #21C-2623 coalbed methane well in Campbell County, WY. The core analysis data reveal that at this location the Canyon seam coalbed is a multi-layered reservoir with each layer having different bulk compositional and fluid mobility properties. A very unique reservoir property of this subbituminous coal is its extremely fast gas desorption rate, which, in turn, facilitates a high early time gas production rate from the coalbed reservoir. The core analysis data indicate that the gas desorption rate is dependent on the maceral composition of the bulk coal organic matter.

It was found that several commonly used coal and coalbed reservoir property analysis methods required modification to prevent or minimize errors due to subbituminous coal's propensity to undergo aerial oxidation and desiccation. The occurrence of these processes during sample handling, storage or testing causes significant (15% or greater) underestimation errors in key reservoir properties such as the in-situ gas content, moisture holding capacity, sorbed gas composition, and percent gas saturation. Effective methods for avoiding or minimizing subbituminous coal property analysis errors due to oxidation and desiccation are described in this paper. Because these error prone analysis practices have been commonly used in the past, there may be significant potential for large coalbed methane resource and reserve estimate gains in this and other Rocky Mountain region basins.
Imports
Authors: O'Connor Lawrence J.
Published: December 2007

O'CONNOR JR., LAWRENCE J., ADMINISTRATOR, OIL IMPORT ADMINISTRATION, DEPARTMENT OF THE INTERIOR

It is a pleasure and honor to be with you today. I do not come to this meeting as a stranger to the American Institute of Mining Engineers because a large portion of my adult life has been spent in professional and personal contact with the members of AIME's Society of Petroleum Engineers.

Secretary of the Interior Udall has asked me to convey his personal greetings to you. Secretary Udall is new in the Department of the Interior, but let me assure you that his interest in the energy problems of the United States is far from newly acquired. Since he has assumed his new post, he has taken an active and vigorous interest in the oil problems of the Nation.

Also, I wish to extend to you the best wishes of John M. Kelly, a member of AIME, who has been recently nominated by President Kennedy to be Assistant Secretary of the Interior for Mineral Resources. Mr. Kelly is a professional petroleum engineer, and, in accepting this new responsibility, will bring a broad background of knowledge of oil and fuel problems to the post.

The Department of the Interior, through Secretary Udall, is the principal petroleum policy making body in our Federal Government—it is the agency of executive responsibility which devotes more time, effort, and thought to our complex national fuels problems than any other body in Washington.

The Department takes an active interest in all phases of oil—from the first shot of the seismographic crews to the ultimate delivery to the home and automobile of the Nation's consumers. And, the Department, through my office, the Oil Import Administration, has primary operational control over the flow of imports of petroleum and petroleum products into the United States from all other petroleum producing areas of the world.
Benefits of Using Deliquescing Desiccants for Gas Dehydration
Authors: Bowman Bob
Published: December 2007

Deliquescing desiccants have been used for gas dehydration for over 40 years. Historically this technology had limited applications due to poor desiccant quality and integrity, equipment design problems, operational difficulty, and limited drying ability. Recent advances in dry material blending and tableting, formulation, and equipment design have greatly expanded the application range of deliquescing desiccants. Deliquescing desiccants are now used to dry sales gas, fuel gas, sour gas, excess or "peak" gas, and for hydrate control. Operating and capital costs compare favorably to traditional TEG systems. Field data verifies the drying ability and performance of deliquescing desiccant systems. Because of the operational simplicity and closed system design, deliquescing desiccants offer many advantages over traditional drying methods such as triethylene glycol, including: no VOC or BTEX emissions, no ground contamination, no fire hazard, low capital expense, low maintenance, no "turn down" concerns, and simple operation. Used for hydrate control in gathering systems, desiccants offer a simple and inexpensive method to dry below pipeline dewpoint thereby allowing trouble free gas flow from wellhead to processing plant. At the plant, gas is further dehydrated to meet pipeline requirements. Desiccants have substantial advantages for drying sour gas both for hydrate control and pipeline sales. There are no emissions, odors, or glycol contamination, and vessels can be over-sized to extend the service interval to only several times per year, greatly reducing employee exposure to hydrogen sulfide. Because of it's simplicity and small footprint, desiccant drying of fuel gas yields increased revenues by using suction gas, not sales gas, for compressor fuel. The entire compressor throughput capacity can be sold, instead of a portion being used for fuel. Desiccant dehydration is well suited for remote, unmanned locations, which are not visited daily. Because operation is simple and service intervals long, operators can schedule maintenance and service weekly or even monthly. This reduces total operating costs and labor requirements.
Near-Critical Models of Thermodynamic Behavior for Gas-Condensate Mixtures
Authors: Gorodetsky E. , Panfilov M. , Kabanov N. , Sedykh A.
Published: December 2007

Thermodynamic state of any hydrocarbon mixture in gas-condensate reservoir is characterized by the near-critical behavior. The new approach is proposed to simulate the behavior of gas-condensate mixtures under high temperature and pressure. Instead of the classical approach based on the updated theory of ideal gases, the new approach is based on the theory of fluid behavior in wide vicinity of critical point. New equations of state are proposed. Anomalous properties of gas-condensate mixtures appropriated to the near-critical systems are detected. They are the anomalous fluid density profile in gravity field, the influence of porous medium of thermodynamic fluid behavior. These phenomena are shown to significantly affect the hydrocarbon reserves estimation.
Oklahoma and Louisiana Statute—Help in Times of Low Oil Prices
Authors: Joyner Hagan D.
Published: December 2007

In the United States both state and federal government have provided incentives in recent years to maintain production, increase production, and discover new production. On the state level, the incentives involve mostly abatement or rebate of severance taxes. Oklahoma and Louisiana (and possibly other states) have had severance tax relief statutes in recent years that are producer helpful in maintaining production in times of low oil prices. All of the incentives are noted but the two discussed most require no investment by the operator. This paper gives a brief history of the statutes which might be considered relatively generous. In the case of Louisiana, the major statute could be considered farsighted in nature. Oklahoma's incentives history shows a rapid willingness to adjust to help maintain production. The paper also comments on the applicability of use of the statutes.
A Risk Analysis of Transition Zone Drilling
Authors: Turley John A.
Published: December 2007

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

A technique has been developed to aid the drilling operator in making minimum-cost decisions regarding the selection of casing points. A mathematical model of the typical pressured environment drilling situation is operated on pressured environment drilling situation is operated on by Monte Carlo simulation techniques to generate quantified expected-loss information as a function of the systems various drilling and environmental parameters. Results indicate that it is possible to determine those combinations of mud weight, kick tolerance, and implied formation pressure that preclude further drilling and that economically justify the running of casing.

Introduction

One of the objectives of optimized drilling is to make as much footage as possible prior to running the next string of casing. prior to running the next string of casing. This philosophy has several advantages, two of which are significant to this analysis:Maximizes the fracture pressure of formations exposed at the most recent casing shoe.Maximizes the amount of hole logged and safety protected by casing during subsequent drilling.

In the context of this study, there is also a significant disadvantage to setting pipe at extreme depths, especially where mud pipe at extreme depths, especially where mud weight requirements are known to increase with depth; namely, that the deep-casing philosophy minimizes the margin of safety between open-hole fracture pressure and required mud weight.

The name of the game then, is "How deep can an operator drill and set pipe so as to be able to benefit by the advantages and not be overwhelmed by the disadvantages?"

A trite, but logical, answer is "Either drill and pay the price of the risks involved, or set pipe and pay the price of new casing, whichever is cheaper."
Comparison of Core Petrophysical Properties Between Low-Permeability Sandstone Reservoirs: Eastern U.S. Medina Group and Western U.S. Mesaverde Group and Frontier Formation
Authors: Byrnes Alan P. , Castle James W.
Published: December 2007

Comparison of petrophysical properties between Eastern U.S. Silurian-age sandstones and Western U.S. Cretaceous-age sandstones illustrates the universality of certain low-permeability reservoir properties. In the Medina insitu porosities are generally within 97% of routine porosities and in Mesaverde-Frontier are approximately 0.8 porosity percent less than routine porosities. In both groups insitu Klinkenberg permeability (ki) exhibits an increasing difference from routine air permeability with decreasing permeability. Both groups of low-permeability sandstones exhibit very similar decrease in "irreducible" water saturation (Siw) with increasing ki. However, lithologic variations that are related primarily to grain size and shaliness cause variance in Siw at any given permeability. Both eastern and western low-permeability sandstones exhibit sharp decrease in gas relative permeability (krg,Siw) with increasing Siw. The krg,Siw values are generally less than 5% at Siw greater than 60%. Although average krgSiw is low and average Siw is high, these sandstones typically produce water-free gas. Analysis of cumulative flow capacity in wells in both regions indicates that a significant fraction of total flow capacity often comes from a few, thin, higher permeability intervals within generally low-permeability sandstone. Although storage capacity declines with decreasing permeability due to increasing Siw, low-permeability intervals still represent a significant fraction of total storage.
Effects of Diagenesis on Neural-Network Grain-Size Prediction
Authors: Faga A. T. , Oyeneyin B. M.
Published: December 2007

The use of gamma-ray log shapes to determine grain-size trends is commonplace despite obvious limitations (Rider 1990, Hurst1990). In a recent development, this implied qualitative relationship between the gamma-ray response and grain-size was exploited in developing a quantitative means of predicting grain-size from well logs (Oyeneyin and Faga, 1999) using neural networks. However, for this in situ prediction methodology to succeed the relationship between gamma-ray log values and clay content and between clay content and grain-size needs to be consistent within a range that will not negate the generalisation capabilities of a Backpropagation-Neural-Network. One of the main factors affecting the natural variability that exists in these relationships and causes reduction in porosity and permeability is diagenesis. The others include compositional and textural factors (Rider 1990). This paper presents the results and recommendations of a study carried out to determine the effects of diagenesis on the accuracy of nonlinear grain-size modelling in sandstones.

The results of the study indicate that grain-size modelling in diagenetically modified formations is feasible. It characterises the effects of cemented zones. The study further concludes that cross-depositional environment prediction of grain-size in the case of the Brent and Statfjord formations generates representative grain-size trends and values.
Stimulation Fracture Height Control Above Water or Depleted Zones
Authors: Talbot D. M. , Hemke K. A. , Leshchyshyn T. H.
Published: December 2007

Many potentially productive zones located a few meters (feet) above a water or pressure-depleted interval are not fracture-stimulated, or are eliminated from further investigation rather than risk inter-zone communication. In either case, production fails to be optimized and often recoverable reserves are lost. Several techniques for controlling formation fracture height growth have been successfully field-tested. The fracturing fluid used was either water- or oil-based with a low viscosity of 20 to 50 cp. A general program, utilizing a timed sequence of rate and proppant concentration control, is preceded by application of fracture height-controlling material in the pad. Approximately 5 tonne (11,000 lb) of proppant were consistently placed with total fracture height growth traced to less than 15 m (50 ft). Post-stimulation well testing indicated fracture lengths to 90 m (300 ft) in reservoirs having permeabilities as low as 0.1 md. Fracture modeling using a numerical simulator prior to actual field stimulation has proven to be instrumental in designing an optimal fracture program. This unified procedure prevents or minimizes fracture height growth, from initial breakdown of the formation to the flow period after pumping. Well stimulation is performed through tubing to reduce fluid volumes. Pumping rates ranged from 0.5 to 1.5 m3/min (3.1 to 9.4 bbl/min). To date, ten treatments have been successfully placed and there is no evidence to suggest that fracture heights were greater than those predicted by computer simulation.
Application of a Single-Phase Simulator to Study the Effects of Liquids on Pipeline Efficiencies in a Natural Gas Gathering Network
Authors: Knobloch M.H. , Brill J.P. , Crafton J.W.
Published: December 2007

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

It is possible to history-match an existing gas pipeline network to obtain flow efficiencies that account for abnormal pressure losses resulting from liquids entrained in the gaseous flow stream. An actual gas gathering network which was known to produce relatively large volumes of condensate was successfully history-matched. The network was studied with a simulator which uses the single-phase Panhandle Equations to calculate the pressure losses in the pipeline. The observed pressures were matched in the calculations by lowering the pipeline efficiencies to account for liquids in pipeline efficiencies to account for liquids in the flow stream. Data was gathered which supported the theory that the low pipeline efficiencies resulting from the calculations were in fact due to liquids in the pipeline. Summaries and graphs of the data and calculated results are presented.

Introduction

The capability exists to completely simulate a gas gathering network with the modern digital computer. The simulator which has been used in this study employs single-phase flow equations to calculate the pressure drops through the pipeline segments. Satisfactory results have been achieved for all dry gas systems which have been studied using the simulator.

One gathering system was known to produce relatively large amounts of natural gas liquids, i.e. condensate. The single-phase simulator yielded rather wide pressure discrepancies when applied to this particular network. The purpose of this study was to determine if it is possible to apply a single-phase simulator to an actual operational flow network having abnormal pressure losses caused by the inclusion of liquids pressure losses caused by the inclusion of liquids in the gaseous stream.

The simulator calculates the pressure loss in a pipeline segment with an equation which incorporates a flow efficiency term. Normal line efficiencies for dry gas systems range from 70% to 90%. The nature of work performed was to duplicate the observed pressure losses by adjusting the line efficiencies of each individual pipeline segment.

The study was accomplished by concentrating on two different time periods; one during the winter when liquid production was high, and one during the spring when liquid production was low. The result was that two efficiencies were derived for each pipeline segment.