bluuebunny/crossref_metadata_2025 huggingface dataset:
The Thermosludge Water Treating and Steam Generation Process
Authors: Hull R.J.
Published: December 2007

The Thermosludge process internally softens and makes high-pressure steam directly from hard and saline oilfield or other water. Pilot plant and early full-scale plant work established several physical and chemical principles found necessary or desirable for good operation, and for control and practical elimination of scale on the process heating surfaces. These principles are use of a secondary liquid heat transfer medium, provision of time and space for water chemical reactions ahead of the boiling zone, and presence of sludged reaction products throughout the boiling zone. Other pertinent factors are discussed such as dissolved and suspended solids limits, foaming, corrosion, and heat transfer.

Introduction

In 1964 considerable use of steam in California oil fields was beginning to cause shortages of good steam generator feedwater in some areas. It seemed evident that in some situations oilfield brine or other low-quality water would have to be used to generate high-pressure steam directly. The Thermosludge process was developed to meet this need, and early results of its field use have been reported previously. This article discusses both pilot plant and full-scale plant design and operation particularly relative to the high-temperature reactions and scaling characteristics of some of the chemicals present in the waters.

Present understanding of the process should allow broader use in its original field, and in other processing areas dealing with difficult waters.

Pilot Plant Design and Operation

After considerable study of chemical and engineering factors involved, a pilot plant program was set up. Three main theories or principles believed to lead to successful operation were followed in the pilot plant design and the same principles were carried into the full-scale plant design.

First, heat should be applied via a secondary fluid heat transfer medium rather than directly in a combustion space. Relative to direct-fired beating, the secondary fluid heating guarantees that maximum tube wall temperature will be well within the allowable metal temperature limit regardless of local scaling or salting up. Many situations call for soluble salt in the steam generator in concentrations of as much as 15 percent by weight perhaps half of the limiting solubility. Even if conventional tube scaling were somehow entirely prevented, such situations would require the inherent heat flux control of a secondary heat medium to prevent gross fouling and plugging by salt deposits.

Second, means should be provided in terms of high-temperature time and volume to preheat and chemically react the feedwater before it enters the boiling zone. The practicality of this is based on the expectation that thermally induced mineral sludging reactions will proceed much faster and more completely in the 350 to 600F environment than, for example, in the conventional lime-soda process. Thus, the feedwater should be entirely softened by the time it arrives at the boiling zone.
Measuring Low Flows in Devonian Shale Gas Wells With a Tracer-Gas Flowmeter
Authors: Bennett Richmond , Schettler Paul D. , Gustafson Todd D. , Gillette Illona E.
Published: December 2007

A novel design for a downhole flowmeter that can locate and quantify gas-entry points in a well is presented. The instrument has a gas-tracer injector at its lower end and a tracer detector at its upper end. We determine gas flow in the well by injecting tracer gas at a precisely measured rate into the natural gas flow and measuring the concentration with the detector. The result is a wireline log that locates and quantifies natural gas sources from the decrease in measured flow as the wireline instrument passes each source. The new design has been tested against calibrated gas flows in the laboratory and in Devonian shale gas wells in the field. The new flowmeter is compared with spinner, temperature, sonic, and television logs. The instrument provides an expanded flow range compared with spinner logs and furnishes quantitative mass-flow information compared with incomplete and qualitative indications provided by temperature and sonic logs.
Tubing and Casing Buckling in Horizontal Wells (includes associated papers 21257 and 21308 )
Authors: Chen Yu-Che , Lin Yu-Hsu , Cheatham John B.
Published: December 2007

This paper describes new theoretical results for predicting the buckling behavior of pipe in horizontal holes. Pipe buckling in horizontal holes occurs initially in a sinusoidal mode along the low side of the hole; at higher axial compression a helix is formed. Equations are given for computing the forces required to initiate these different buckling modes. Simple experimental laboratory results confirm the theory. Results presented in this paper apply to friction modeling of buckled tubulars to help predict when pipe can be forced to move along a long section of a horizontal well.

Introduction

Since 1950, many analyses have been performed on the mechanics of pipe in oil and gas wells. Lubinski et al. defined the helical buckling behavior of pipes in vertical wells. However, the postbuckling behavior of pipe in horizontal wells is different from that in nearly vertical wells. Knowledge of the configuration of buckled tubulars is important to prevent costly failures and to predict whether a tool can be forced along a horizontal well. This paper provides methods to analyze these problems. Two modes of buckling can occur for tubulars in horizontal or steeply inclined wells: helical and sinusoidal (Fig. 1). The axial compressive force required to buckle the pipe into a sinusoidal configuration depends on pipe stiffness and weight and on hole size in a manner similar to a beam on an elastic foundation. As axial force is increased, the buckling mode changes from sinusoidal to helical. Model experiments confirm the results of the analyses.
Postfracturing Gas-Well-Test Analysis Using Buildup Type Curves
Authors: Walsh D. M. , Leung K. H.
Published: December 2007

Well-specific buildup type curves that incorporate non-Darcy effects and real-gas properties were used to obtain better estimates of fracture conductivities and lengths from postfracturing well tests in the Ravenspurn South gas field. Well productivities were calculated from the fracture parameters and used to optimize further fracturing and field development.
Prevention of Downhole Scale Deposition in the Ninian Field
Authors: Shuler P. J. , Jenkins W. H.
Published: December 2007

Conventional adsorption scale-inhibitor squeezes and newer equilibrium squeezes have successfully prevented downhole scale at the Ninian field. A mathematical model matched or underpredicted the lifetime of the adsorption squeezes. Underprediction probably resulted from the exclusion of real phenomena, such as fluid crossflow and inhibitor precipitation. Both the model and the field data suggest that the most important design factor that determines squeeze life is the total amount of scale inhibitor injected. Equilibrium squeezes use a unique product that yields a longer treatment lifetime when designed properly. This process is more difficult to implement; it requires careful planning and quality control to be successful.
Geostatistical Modeling of Transmissibility for 2D Reservoir Studies
Authors: Desbarats Alexander J. , Dimltrakopoulos Roussos
Published: December 2007

A geostatistical approach is used to characterize reservoir transmissibility with the aim of assigning simulator parameters in 2D models. Transmissibility is represented as a spatial random function where heterogeneity is described by the probability distribution and the variogram of sample values. The key element of the geostatistical model is the definition of block transmissibilities as spatial geometric averages. Published analytical results have shown that the effective transmissibility of infinite, statistically isotropic flow fields is equal to the ensemble geometric mean. Numerical results presented here show that a spatial geometric average is an excellent approximation of effective transmissibility in such finite fields as simulator gridblocks. The geostatistical model for transmissibility is used to show that the mean and variance of block-averaged values depend on the averaging area. As the averaging area is increased, mean block transmissibility decreases toward the ensemble geometric mean while the block variance decreases to zero. The geostatistical model is also used to investigate the kriging of block transmissibilities from well data. The current method of correcting bias in kriged values is found to cause artifacts of gridblock size in flow simulation results. The simpler, uncorrected kriging estimator is shown to preserve overall flow-field transmissibility, regardless of gridblock size.
Minimize Formation Damage by Rapid, Inexpensive Method of Completion- and Stimulation-Fluid Selection
Authors: Underdown D. R. , Conway M. W.
Published: December 2007

Minimizing or removing formation damage is a major objective in completion and stimulation operations. Formation damage is minimized by selection of "nondamaging" fluid systems and operations on the basis of petrographic analysis and field experience. A technique known as the capillary suction time (CST) test, adopted from the drilling-fluid industry, provides a quick and inexpensive method for qualitative selection or screening of the least damaging fluid system for a particular formation. The CST test is a fundamental filtration method for determining the electrolyte concentration that will produce the maximum inhibiting effect on a formation. The method uses an instrument to measure the time required for a liquid to travel a calibrated distance on a standard porous filter paper. The CST procedure currently is used very successfully to select completion fluids and to evaluate stimulation-fluid additives. This paper explains the procedure, discusses limitations of the test, and presents laboratory and field data to show the value of the technique.
Operational Review of a Large-Scale Saturated-Steam Delivery System
Authors: Schoen D. M. , Frazier T. L.
Published: December 2007

Since initiation in the mid-1960's, steamflooding operations have become increasingly complex. Whereas saturated steam delivery systems were once designed simply to deliver steam from a generator to an injection well, the requirements placed on these systems today are significantly broader. A need exists for controlling and counteracting the effects of phase splitting, and the ability to measure and control mass and heat injection rates at the wellhead is increasingly critical for reservoir analysis and economic success. In addition, the introduction of cogeneration plants as major suppliers of steam has been accompanied with new singular problems and forced redesign of delivery and support equipment.

Several unique solutions have been developed to meet these challenges. A monitoring system comprising more than 300 pressure transducers allows determination of line velocities and mass rates within the steam transmission network and calculation of injection wellhead pressure. A technique to measure steam quality and mass flow rate accurately has been developed and adapted for use with both ongoing displacement and stimulation service.
An Algorithm for Determining Smooth, Continuous Pressure Derivatives From Well-Test Data
Authors: Lane H. Scott , Lee W. John , Watson A. Ted
Published: December 2007

An algorithm for determining pressure-derivative functions from measured well-test data is presented. The pressure data are fit with a spline function that can account for curve shape constraints. The first and second derivatives of the resulting spline function are calculated analytically and can be used for type-curve matching. Two examples illustrate the performance of the algorithm.
New Dimensions in Geophysics for Reservoir Monitoring
Authors: Greaves R. J. , Beydoun W. B. , Spies B. R.
Published: December 2007

Advances in geophysical survey techniques have improved surface and borehole methods used for reservoir delineation and description. These same techniques can be used to map changes in reservoir conditions caused by various types of reservoir flooding. This paper discusses reflection and borehole seismic techniques and borehole electrical methods used for secondary and tertiary recovery. The unique aspect of geophysical monitoring is that the surveys are repeated during field development, so changes in geophysical response can be observed. These data can be interpreted by reservoir geologists and engineers to reveal the distribution of the production process and then used in production planning.
Using Artificial Neural Nets To Identify the Well-Test Interpretation Model
Authors: Al-Kaabi Abdul-Aziz U. , Lee W. John
Published: December 2007

This paper presents a new approach, based on artificial neural net technology, to identify a preliminary well-test interpretation model from derivative plot data. Artificial neural nets can identify patterns from incomplete and distorted data and also eliminate the need for elaborate data preparation, such as smoothing.
An Expert System To Design and Evaluate Matrix Acidizing
Authors: Blackburn C. R. , Abel J. C. , Day R.
Published: December 2007

An expert system called ACIDMAN was developed to design matrix acid treatments that remove damage near the wellbore and increase production. Input data can range from unknown formation damage, for which the system designs a conservative treatment based on well history and geological probability, to cases with detailed formation information available, in which very precise treatments are prescribed. The system requests additional specific laboratory tests, when needed, to aid in product selection. Basic input data requested include well type and history, formation-damage mechanism, bottomhole temperature, reservoir pressure, formation permeability, lithology, porosity, interval size, and crude oil gravity. Output includes product selection, additives, treatment volumes, and treatment technique. Phase 1 of the ACIDMAN expert system was delivered in beta test in March 1990, and full implementation of all phases is planned during 1990.
Total Connectivity Speeds Research and Support Of Field Operations
Authors: Himes R. E. , Frost K. I. , Henry S. R. , Funkhouser J. D.
Published: December 2007

Research and field support roles in the oilfield service industry have become increasingly complex in the last 15 years. Experimental apparatus are more dependent on the data-acquisition and processing capabilities of computers as the amount of data generated increases. Therefore, the need to network these computers for data transport has significantly increased. The type of network system selected depends on the goals to be achieved. Incorporation of existing equipment, communication between systems of different architectures, and future expandability are only a few of the necessary attributes. With these in mind, a computer network system was designed and is being implemented. The system combines local- and wide-area networks (LAN's or WAN's) of different protocols to acquire, process, and transport information worldwide. The result is faster development of new products and quicker response in support of field operations.
Use of a Relational Database on a PC Network for Reservoir Studies
Authors: Harwell D. C. , Hyche N. K. , Harmon R. A. , Wentz R. M.
Published: December 2007

The prevelant trend in the petroleum industry regarding field development has incorporated a synergistic approach toward evaluating reservoirs. In Aug. 1988, Conoco’s Casper Div. took this approach of integrating the geoscience and engineering disciplines by creating four EOR study teams. Their mission was to determine the economic feasibility of CO2 injection, to improve secondary recovery operations, to increase operating gain, and to identify areas with development potential in preselected reservoirs. As part of this team concept, a computer network was created to assist the engineers and geologists in compiling and processing the massive amounts of data needed for the reservoir studies. The network was designed with data bases distributed among multiple servers. In essence, this network provides a "reservoir evaluation workstation, " which can be used interactively from each individual’s office. A wide range of software programs (i.e., interpretation tools) can be accessed with direct ties to the project data base. The network effectively connects PC’s, data bases, and a MicroVAX III computer into one integrated system.
Using a PC To Process MRI Data
Authors: Halimi H. I. , Capps K. , Poston S. W.
Published: December 2007

Nuclear magnetic resonance (NMR) imaging techniques are used to measure changing fluid saturations and relative permeabilities in porous materials.1, 2 The recorded signals are a measure of the volumes of the fluids residing in the pore spaces.3’4 A technique coupling public-domain image processing programs with in-house programs for downloading and interpreting NMR data has been developed at Texas A&M U. The new method permits a PC or Macintosh II computer system to be used in place of the more sophisticated and expensive graphics workstations. Raw NMR data files are downloaded by a parallel to serial link as 256 × 256 matrices of positive even integers. In-house developed C programs are used to convert the text files to binary data to reduce both storage requirements and image noise level. An interactive portion of the program permits the operator to choose the level where the good data start. These data are then extracted and processed into colored images. The extracted data are divided by 256 and a color table ranging from 0 to 255 is arranged. The end points are quantified by measuring these saturation values during the experimental run. The data are stored in binary form once a color has been assigned to each pixel. The process of converting the NMR files to binary files and assigning colors to the pixels takes 90 to 120 seconds of computer time. This process produces images with sufficiently good resolution to show saturation fronts and to distinguish features within the image.
Pre- and Postprocessing for Reservoir Simulation
Authors: Rogers W. L. , Ingalls L. J. , Prasad S. J.
Published: December 2007

This paper describes the functionality and underlying programming paradigms of Shell’s simulator-related reservoir-engineering graphics system. This system includes the simulation postprocessing programs Reservoir Display System (RDS) and Fast Reservoir Engineering Displays (FRED), a hypertext-like on-line documentation system (DOC), and a simulator input preprocessor (SIMPL-SIM). RDS creates displays of reservoir simulation results. These displays represent the areal or cross-sectional distribution of computed reservoir parameters, such as pressure, phase saturation, or temperature. Generation of these images at real-time animation rates is discussed. FRED facilitates the creation of plot files from reservoir simulation output. The use of dynamic memory allocation, asynchronous I/O, a table-driven screen manager, and mixed-language (FORTRAN and C) programming are detailed. DOC is used to create and access on-line documentation for the pre- and postprocessing programs and the reservoir simulators. DOC can be run by itself or can be accessed from within any other graphics or nongraphics application program. DOC includes a text editor, which is the basis for a reservoir simulation tutorial and greatly simplifies the preparation of simulator input. The use of sharable images, graphics, and the documentation file network are described. Finally, SIMPLSIM is a suite of programs that uses interactive graphics in the preparation of reservoir description data for input into reservoir simulators. The SIMPLSIM user-interface manager (UIM) and its graphic interface for reservoir description are discussed.
Field Testing of Low-Friction-Gauge PDC Bits
Authors: Sinor L. A. , Brett J. F. , Warren T. M. , Behr S. M.
Published: December 2007

This paper presents the results of developmental work applied to modify "off-the-shelf polycrystalline-diamond-compact (PDC) bit designs to incorporate low-friction-gauge technology. The low-friction gauge limits harmful bit-whirl tendencies by directing the radial bit imbalance to a gauge pad that makes smooth sliding contact with the wellbore wall. Field testing indicates that use of a low-friction gauge improves bit life and rate of penetration (ROP).
Successful Flow Testing of a Gas Reservoir in 3,500 ft of Water
Authors: Shaughnessy J.M. , Carpenter R.S. , Coleman R.A. , Jackson C.W.
Published: December 2007

This paper reviews the planning and implementation of a flow test of a gas reservoir, including the general goal of the test, equipment used, problems anticipated, and the steps to minimize or to avoid problems. The well successfully tested at rates of 22.5 MMcf/D and 2,670 B/D condensate with a 2,800-psi flowing tubing pressure through a 46/64-in. choke for 4 days.

Introduction

The test of Viosca Knoll Block 957 Well No. 1 Sidetrack No. 2 was Amoco Production Co.'s deepest test from a floating rig. Viosca Knoll 957 is 115 miles southeast of New Orleans in 3,500 ft of water. The test, at a record water depth for the Gulf of Mexico, also set a world water-depth record for testing a gas reservoir.

Safety to crew and the environment were top priorities during the planning. A team consisting of drilling, completion, reservoir, and facilities engineers and a foreman were assigned to plan and implement the test. Early planning involved field, service company, and engineering groups. Every effort was made to identify potential problems and to design the system to handle them.

The goals of the test were to determine reservoir properties and reservoir limits. Several significant challenges were involved in the well test. The reservoir was gas with a potentially significant condensate yield. The ability to dispose of the large volumes of produced fluids safely without polluting was critical to maintaining uninterrupted flow. Potential shut-in surface pressure was 6,500 psi. Seafloor temperature in 3,500 ft of water was 39F. Preventing gas hydrates was a major problem. The inhibition was Preventing gas hydrates was a major problem. The inhibition was done by chemical injection into the flow stream before the gas and condensate reached ambient seafloor temperature. The ability to acidize was necessary. Optimum reservoir evaluation required varying the lengths and rates of the flow periods and shut-in times. During startup, hydrate inhibition was critical and a large volume of fluids in the surface tanks, both the tubing volume and produced fluids, required significant handling and proper disposal. produced fluids, required significant handling and proper disposal.

The well tested was the third sidetrack from a wellbore spudded in Jan. 1989 by the drillship Discoverer 534. Initial plans were to test the second sidetrack from the drillship in the spring, but a third sidetrack was added to the drilling program and the drilling was prolonged into the summer. Rather than begin testing operations in July, a decision was made to move the drillship off location and to bring back the ship or another rig after hurricane season. The time required to secure the ship for a hurricane when in the testing mode would require beginning to secure when the potential storm was at least 750 miles away (mid-Cuba). This was not considered practical; therefore, Penrod 78 was moved to location in late October after Hurricane Penrod 78 was moved to location in late October after Hurricane Jerry.
Multiwell, Multilayer Model To Evaluate Infill-Drilling Potential in the Oklahoma Hugoton Field
Authors: Fetkovich M. J. , Ebbs D. J. , Voelker J. J.
Published: December 2007

A 3D simulation was conducted on a portion of the Oklahoma Hugoton gas field to evaluate infill-drilling potential. The impor- tance of understanding the behavior of layered, no-crossflow reservoirs is emphasized by matching detailed performance histories. Further insight into this long-lived field is obtained by forecasting performance, both for continued current operations and for infill drilling on each proration unit.
Flexible Riser and Mooring System Develops Small Oil Fields in the North Sea
Authors: Thompson A. M. , Holmes G. A. A. H. , Benstead P. J.
Published: December 2007

The flexible riser and mooring system (FRAMS) provides a technically straightforward, commercially attractive method of developing small oil fields. A passively moored 60, 000-deadweight-ton (60, 000-DWT) tanker with deck-mounted equipment provides a swivelless well fluid and injection water path from and to the wellheads. The system can be disconnected rapidly in severe weather.
Technical Requirements for GOC Monitoring in Horizontal Wells by Direct-Arrival Travel-Time Inversion
Authors: Elde Rigmor M. , Mæland Einar , Petersen Steen A.
Published: December 2007

This paper describes a theoretical study of the technical requirements for gas/oil contact (GOC) monitoring in horizontal wells. The goal is to detect changes in the velocity field related to the GOC in a producing reservoir. Examples are based on synthetic travel-time data. The necessary accuracy of location of the source and the receiver is determined so that a difference in the observed travel time can give information about the GOC displacement.
Mobility Control for Steamflooding With High-Temperature-Resistant Additives
Authors: Stoll R. D. , Gudenau H. W. , Lupik M. W.
Published: December 2007

Steamflooding efficiency can be increased by foaming injected surfactants in deoiled reservoir zones to divert steam into higher-oil-saturation zones. The purpose of this project is to develop test facilities (static tests and flooding trials) to check the applicability of various high-temperature-resistant surfactants at temperatures up to 572°F.
Sulfonate Retention by Kaolinite at High pH—Effect of Inorganic Anions
Authors: Bavière Marc , Ruaux Eliane , Defives Daniel
Published: December 2007

At high pH and with surfactant concentrations well above the critical micelle concentration (CMC), the pH-dependent part of adsorption is small. Retention depends especially on the sodium-ion activity and on the type and valence of inorganic anions. As the anionic charge increases, adsorption at a given ionic strength decreases. This behavior correlates with the effect of anions on the sulfonate activity in solution.
Interpretation of a Pulse Test in a Layered Reservoir
Authors: Kaneda Ryuzo , Saeedi Jawaid , Ayestaran Luis C.
Published: December 2007

An interwell pressure test, designed and implemented as a pulse test, was performed in the Arab zones of an offshore field in Abu Dhabi. The interpretation of three pulses yielded inconsistent results for transmissibility and storativity. The pressure response data were interpreted with a two-layer analytical model after a numerical simulator was used to modify the pressure response for the interference from a third well. The two-layer analytical model provided an excellent match of the modified pressure response. We conclude that conventional pulse-test interpretation methods cannot be satisfactorily applied to the pressure response in a two-layer system.
Immiscible CO2 Process for the Salt Creek Field
Authors: Bargas C. L. , Montgomery H. D. , Sharp D. H. , Vosika J. L.
Published: December 2007

An immiscible CO2 flooding process was investigated for use at the Salt Creek field, WY. This proposed process with CO2 slug and 100% carbonated chase water may recover an incremental 8.6% original oil in place (OOIP). However, tertiary recovery of this light crude is sensitive to the reservoir crude composition, temperature, and pressure. Initial studies and simulations led to a proposed process pilot.
Evaluation of Limestone Formation Characteristics From Well Logs
Authors: Cregeen D.J. , Moir H.
Published: December 2007

Introduction

The evaluation of limestone formations by well logs has brought many interesting problems to light, some of which are as yet unresolved. While a major purpose of well logging is to ensure that zones containing producible hydrocarbons are not bypassed, this paper is more concerned with the further information that can be derived from the logs to assist in more clearly defining reservoir characteristics, fluid content and performance. In the hard limestones of Southeast Arabia sufficient evidence has not yet been gathered to allow any large-scale tailoring of the logging program; a number of logs are still run which ostensibly can be used to compute the same parameter. The validity of some of these measurements is discussed, and some tentative interpretations are made concerning their significance. In this paper, the five selected topics are discussed in light of their application to the hard limestone reservoirs under review.

Water Saturation, Sw

Well-log analysis lends itself readily to the determination of water saturation and, hence, to computation of hydrocarbon reserves. However, it is advisable to obtain confirmation of the values so obtained by alternative methods because several factors influence the basic data from which these values are derived. As has been pointed out elsewhere, water saturations of 2 to 50 per cent of the available pore space have been observed in oil-producing formations. This wide range invalidates the possibility of choosing a reasonable value by inspecting the available choices and, thus, makes corroboration from other sources essential.

The methods used to determine connate-water saturation in the formations under review were core analysis of formations cut under oil-base mud, measurement of capillary pressures of cores and log analysis. Each of these methods suffers from limitations, and only where mutual agreement exists may a value be accepted with confidence. Since the log-analysis method offers distinct advantages over the other two, affording as it does a measurement under reservoir conditions, it was of interest to attempt to resolve the uncertainties inherent in the method by comparing results obtained on cores in the laboratory.
Measured and Calculated Horizontal Stresses in the Travis Peak Formation
Authors: Walls J. D. , Dvorkin Jack
Published: December 2007

This paper presents the results of an experimental program to determine in-situ horizontal stress magnitudes from the dynamic mechanical properties of tight-gas sand cores. These measurements were made on 47 vertical plug samples from the Gas Research Inst. (GRI) test wells, Staged Field Experiment (SFE) Wells 1 through 3. The wells were cored in the Travis Peak formation of east Texas from ≈ 6,500 to ≈ 9,500 ft deep. Vertical overburden stress gradient was measured in one well using a downhole gravimeter.

The core mechanical properties were used with the Anderson and Newberry equations to calculate in-situ horizontal stress. Actual in-situ minimum horizontal stress was determined from instantaneous shut-in pressures measured during minifracture and microfracture tests. The Newberry equation was found to give results that agreed best with measured horizontal stress. A closer match was obtained between measured and calculated horizontal stress values when we used dynamic Poisson's ratio from partially gas-saturated samples. The assumptions and limitations of the procedure are presented.
Incorporation of 2D Fluid Flow into a Pseudo-3D Hydraulic Fracturing Simulator
Authors: Weng Xiaowei
Published: December 2007

Pseudo 3D (P3D) hydraulic fracturing models often overpredict fracture height for a poorly contained fracture. This is caused partly by either the neglect of the fluid flow component in the vertical direction or a crude treatment of the 2D fluid flow in the fracture as 1D flow in the vertical direction in the fracture-height calculation. This paper presents a height-growth model that adopts a flow field more representative of the actual 2D flow in a fracture. In this model, the fracture is divided into two regions: an inner region where the flow direction is nearly horizontal, and an outer region where the flow field is approximated by a radial flow from an imaginary source. The governing equations for determining height growth rate and the numerical method for solving these equations are described. A commercial P3D simulator was modified by replacing its original height-growth model with this 2D flow-height model. The modified simulator was tested against the original simulator and the Terra Tek and U. of Texas fully 3D simulators. The modified P3D simulator incorporating the new height model showed significant improvement over the original model in height calculations and good agreement with the fully 3D models.
Eggbeater PDC Drillbit Design Eliminates Balling in Water-Based Drilling Fluids
Authors: Zijsllng D. H. , Illerhaus Roland
Published: December 2007

This paper describes a novel polycrystalline-diamond-compact (PDC) -bit concept based on insights into PDC-bit cutting mechanism and rock behavior during drilling. The design comprises a hydraulic layout that optimizes bit cleaning and cuttings removal in soft and sticky formations. Significant improvements in performance have been achieved in Cretaceous and Triassic formations drilled with water-based muds.
A Unified Approach to Drillstem-Failure Prevention
Authors: Hill T. H. , Seshadri P. V. , Durham K. S.
Published: December 2007

Practical drillstem-failure prevention seems to be based more on individual knowledge of specific failures than on any standard model. To present a broader approach to drillstem-failure prevention, this paper draws on failure-prediction models, failure-investigation results, drillpipe finite-element analysis, and the API/IADC Drillstring Database to construct a unified approach to failure prevention.
Economic and Reserve Evaluation of Coalbed Methane Reservoirs
Authors: Dhir R. , Dern R.R. , Mavor M.J.
Published: December 2007

This paper presents examples of a reservoir-simulation-based technique for evaluating coalbed methane reserves. Simulation results and an economic analysis model that incorporates the effects of nonconventional fuel tax credits are used to compute economics. A statistical model quantifies economic risk on the basis of uncertainty in relevant geologic properties.

Introduction

The purpose of this paper is to discuss a methodology for the estimation and classification of reserves from coalbed methane reservoirs and to present a technique for determining the 'economic feasibility of proposed coalbed methane investments.

Coalbed methane reservoirs are characterized by the nonconventional nature of gas storage and fluid production, which limits the use of traditional decline curve or volumetric methods for reserve estimations. To account accurately for the physical phenomena affecting production, an approach based on the use of reservoir simulators is recommended. Applications of this approach for different reserve categories are presented.

Production from coalbed methane reservoirs is affected by several reservoir and geologic factors. Some of these factors can be determined with standard formation evaluation methods; others must be inferred by production analysis. The use of production history matching as a reservoir analysis tool is illustrated.

Natural gas production from coalbed methane reservoirs in the U.S. qualifies for a nonconventional fuel tax credit under Sec. 29 of the Internal Revenue Code (lRC). If these credits can be utilized, the positive effects on project economics are quite significant. These effects are demonstrated by various examples.

Reservoir-property estimates and production forecasts are subject to a certain level of uncertainty. It is important to recognize the effects of these uncertainties on the predicted economic returns from a project. A unique approach to quantifying the geologic risks associated with coalbed methane projects is presented.
Closing the Loop: Production Data Management by PC's in the Field
Authors: Taylor S.
Published: December 2007

Accounting and engineering groups have long commanded a high level of expertise in the ability to manipulate well production data for the calculation of well performance trends, reserve estimations, and lease-hold accounting. Unfortunately, the data crucial to the accuracy of this work are often affected negatively by human error (or mathematical ability) in the calculation of production volumes, the time available (or interest) in performing "paperwork"-oriented tasks, and the timeliness with which computed data are made available to these groups. To correct this situation, we have developed a PC-based Production Acquisition Allocation and Reporting System (PAARS) for field and office personnel. With this system, all data entry and allocations are still assembled in the field, but all calculations are done by the PC. Additional tracked data include personnel costs and activities, regulatory compliance information, and marketing data.

Whenever desired, data are transmitted to a central PC or mainframe data base, where they become immediately available for use by accounting, engineering, marketing, and management personnel. At the Offshore Div., for example, the office staff has current production and well test data available off the PC network, for every operated well, when they arrive at work in the morning.

Numerous customized reports are available for use by field and office personnel. The system also automatically generates the government reports required by the regulatory staff. The system has been used throughout the Offshore Div. for 4 years with considerable success and was recently adapted for land operations. In addition, OGCI Software has now joined with Samedan to include PAARS (now PA_PAARS) for distribution with its family of Production Analyst programs.
A Task Management System for Compliance With Health, Safety, and Environmental Regulations
Authors: Crump J. J. , O'Gorman T. P.
Published: December 2007

Shell Western E&P Inc. (SWEPI) has developed a new computer system to help it comply with health, safety, and environmental (HS&E) regulations. It is a task management system that functions at the detailed inventory level. It schedules work, instructs operations, and records compliance status. This article discusses design and development of the system.
Complete Multiplatform Networking Integration in a Petroleum Research Environment
Authors: Jefferson L. L. , Arirachakaran S. , Brill J. P.
Published: December 2007

This paper describes a new computer network, its implementation, the moderate costs involved, and the tremendous benefits it offers a petroleum research environment.
Interactive Reservoir Simulation
Authors: McVay D. A. , Bastian P. A. , Epperson B. D.
Published: December 2007

This paper describes a system that allows engineers to monitor and control a reservoir simulation run during its execution. The system consists of a 3D, three-phase black-oil reservoir simulator running simultaneously with an interactive graphics pre- and postprocessor. Previous authors have described systems that allow monitoring of job execution with simultaneous graphics displays; the system described here is unique in that the engineer can modify simulator and well-control parameters during the execution. While the system will be helpful in detection and correction of timedependent data problems, it will be very useful in optimizing reservoir management decisions in future performance projections.

The system is implemented on an IBM-compatible 486 microcomputer with commercially available multitasking software, although it can be implemented easily on any microcomputer or workstation capable of multitasking. We show that implementation of the system required only a moderate amount of modification of the pre- and postprocessor and even less modification of the reservoir simulator.
Risk Profile Modification of Energy Projects: The Impact of Controlling Financial Risk Utilizing Swaps
Authors: Larson B.O.
Published: December 2007

The commodity futures and swaps markets are thought to be the invention of speculators, the bane of the oil business, or possibly something confined to finance departments of major corporations. In actuality, they should be considered more as an insurance vehicle and can be used at the project level to modify the risk profile of a property. In this context, an increased familiarity with them can be useful for an engineer. Either futures or swaps can be used to guarantee or modify product prices. While this does not necessarily maximize cash flow or present worth, it can protect a project or company for several years from downside price risk, thereby reducing the risk of the venture. This can be particularly important if lower product prices would cause unacceptable cash flows or net incomes. Reducing risk by limiting downside price exposure could alter budgeting decisions, allow continued or expanded operations of a particular property, or increase debt capacity.

Introduction

As commodity markets have increasingly assumed the role of discovering near-term prices for oil and are beginning to affect natural gas prices similarly, several financial products have been developed that can reduce product pricing risk. Risk can be reduced directly in the futures market or in the over-the-counter market with financial institutions and trading companies using hedging products like swaps. The role that these products play and the importance of understanding it are increasing as price volatility becomes more pronounced. Their impact is highest and their cost is lowest over the immediate future (1 to 5 years). This may also be the period of maximum producing rate, highest present worth, and maximum uncertainty concerning price; thus, they can provide substantial risk protection.

Futures and swaps markets exist for crude oil, natural gas, and several refined hydrocarbon products. While gas futures and swaps can be executed, that market is less well-developed than the oil market, and the relative prices in the two markets do not necessarily correlate. This paper is limited to crude oil transactions to avoid those complications and to concentrate on the risk-modification aspects of hedging. Most comments and all concepts are equally valid for natural gas production.

This paper briefly outlines how oil futures and swaps function and then concentrates on demonstrating the effect of swaps on risk management at the project level through specific examples. An attempt is made to focus on the basic fundamentals of altering project risk rather than dealing with the infinite variability of swaps or the mechanical complexities of executing futures contracts.
Drilling the First Horizontal Well in the Gulf of Mexico: A Case History of East Cameron Block 278 Well B-12
Authors: Fisher E. K. , French M. R.
Published: December 2007

East Cameron Block 278 Well B-12 was the first horizontal well drilled in the Gulf of Mexico. This well, located in the Texaco Inc. operated East Cameron 265 field, was drilled and completed in May 1990. The objective formation was a high-permeability, shallow, unconsolidated gas sand located about 1, 450 ft below the mudline (BML). The success of this well proved that horizontal wells are viable alternatives to extended-reach development wells from offshore platforms in the Gulf of Mexico. The cost to drill and complete this horizontal well was less than comparable extended-reach development wells drilled in the same field. A minimal increase in drilling costs accompanied by considerable savings in completion costs resulted in favorable economics for the project. Drilling a shallow horizontal well in the Gulf of Mexico presented several challenges. This paper discusses prewell planning, formulation of contingency plans, and implementation of a drilling/completion program designed to meet these challenges.
Oilfield Environmental Control Technology: A Synopsis
Authors: Wojtanowicz A.K.
Published: December 2007

This paper shows, in a systematic way, that the long-term solution to the environmental issue in petroleum engineering is the development of a new area: environmental control technology (ECT). ECT is defined as intrinsic in and integrated with an oilfield process. Its preventive function is contrasted to the remediating nature of conventional waste-management technology (WMT). This paper has two objectives: to identify and qualify ECT for petroleum engineering and to overview recent ECT developments, particularly in oilfield production operations.

Introduction

In the 1980's, low oil prices forced oilfield technology to focus on economic efficiency and productivity. Simultaneously, environmental regulatory pressure added a new factor to petroleum engineering economics: the cost of working within the constraints of an environmental issue. The industry is absorbing this cost while revising oilfield technology to reduce the environmental impact. The new area, ECT, has the potential to become a widely accepted way for the oil industry to address the environmental issue.

The API is currently working on a supporting agenda for reauthorization of the U.S. Clean Water Act. One important issue of the new act introduces the concept of pollution prevention to the permit procedure. In regulatory language, pollution should be prevented through source reduction, which necessitates improvements to oilfield processes to reduce waste generation. API supports the concept but favors the inclusion of other preventive measures in this act, such as recycling, reuse (beneficial use), and treatment (to comply with discharge criteria).These and similar past regulatory actions have altered the industry's approach to the oilfield environmental issue. As a result, the remediation approach represented by WMT is being replaced with a preventive approach (ECT). The heart of ECT is prevention of environmental impact. The other features need further clarification.

Identification of ECT

A general definition of ECT is presented in the appendix, along with a description of its basic methods. Ref. 1 discusses the position of ECT among other techniques used by the oil industry to tackle the environmental issue. (The nontechnical means are social, legal, commercial, scientific, and logistic.)

The technical approach to the environmental issue usually is undertaken after the nontechnical means become redundant or uneconomical.