bluuebunny/crossref_metadata_2025 huggingface dataset:
The World's First Multi-Year Slimhole Exploration Project — A Successful Partnership Between Operator and Contractor
Authors: Spoerker H. F. , Cambar Edgar , Nunez Jose
Published: December 2007

For the last decades, slimhole rigs were scarcely available, because drilling contractors wouldn't invest in new equipment without signed contracts in their hands, and operators were reluctant to enter in long-term slimhole exploration contracts. Maraven, S.A., and Corpoven, S.A., both operating affiliates of Venezuela's oil and gas holding PdVSA, have entered into multi-year contracts for two purpose-built slimhole drilling rigs, allowing the development of state-of-the-art drilling equipment and for the first time showing the technical and economic benefits attainable by fully applying slimhole technology over two entire exploration projects.

The paper presents the experience from more than two years drilling and completing slimhole wildcats in Venezuela. Based on 8 case studies from the wells completed so far, typical drilling problems and their solutions are discussed, new operational procedures developed during the project are listed, and the current state of slimhole technology is defined. Challenges originating from drilling in highly environmentally sensitive areas, such as full helicopter transportability and zero discharge drilling, as well as drilling slimholes to more than 13000 feet on the tectonically stressed southern flank of the Andes chain are presented. The organizational structure of the operation and the benefits derived from close partnership between the operator and contractor are outlined.

To quantify the success of the program, the economics of drilling these first 8 wells to depths of more than 13000 feet are presented, and the savings inherent to slimhole drilling technology are clearly defined. Comparisons to an alternative, standard drilling program are given, and the specific reasons for selecting slimhole technology for these projects are dicussed.
The Effect of Rheology on Rate of Penetration
Authors: Beck F. E. , Powell J. W. , Zamora Mario
Published: December 2007

Field data have been collected and analyzed to 1) identify the characteristics of a drilling fluid that enhance rate of penetration, and 2) quantify the impact of particular fluid properties on rate of penetration. The information is being used to evaluate the economics of a fluid treatment program in order to deliver optimal drilling performance and minimum drilling cost, rather than minimum fluid cost. Additionally, it is demonstrated how bit hydraulics can be improved through rheological modification without adjusting flow rate or nozzle size.
Commonly Used Biodegradation Techniques for Drilling Fluid Chemicals, Are They Appropriate?
Authors: Slater Monica , Hille M. H. , Molversmyr Åge
Published: December 2007

In order to assess the suitability of commonly used biodegradation techniques to simulate the environmental behaviour of pseudo oil-based fluids in the sea, a comprehensive study has been conducted. More than 40 biodegradation experiments, using different techniques, have been performed on one particular synthetic base fluid (an acetal). The results are compared to large scale simulation tests and a seabed survey in an attempt to identify the biodegradation method that most closely resembles the natural biodegradation process.
Case History of Directional Drilling in the Cusiana Field in Colombia
Authors: Skelton J. , Hogg T. W. , Cross R. , Verheggen L.
Published: December 2007

A "J"-shaped directional well was successfully drilled in record time without problems to total depth (TD) in the Cusiana Field in Colombia. The drilling conditions in this field have historically proven to be very difficult because the basin is heavily faulted and tectonically stressed. Previous wells in the area have encountered major drilling problems that have been primarily related to wellbore stability and directional drilling.

The Buenos Aires Well B-6 was drilled using only rotary bottomhole assemblies (BHA); no motor runs were planned or were made. Significant improvements in directional drilling practices were made as. a result of careful planning, close teamwork, and careful execution. The paper describes the keys to success in planning and drilling this 3500-ft step out well in a heavily faulted and tectonically active basin.
Subsea Drilling Riser Wear: A Case History
Authors: Poss G. T. , Hall R. W.
Published: December 2007

Wear in subsea drilling risers and BOP equipment while drilling can be an expensive problem. If the wear causes loss of riser integrity the risk to personnel and equipment is potentially significant due to the well control situation that could result. This paper presents information on a serious riser/BOP wear occurrence that resulted in serious well control problems and an expensive equipment repair. The case study presented here occurred in only 295 ft of water in a relatively short period of drilling time. The approximate cost of the resulting problems was in excess of US$3.5 million. This paper will also present a simple model that can be used to estimate the wear in a riser and flex joint. The calculations in this paper will provide a means to determine the relative effects of such parameters as riser angle and tooljoint hardbanding abrasiveness. With this knowledge it is possible to develop an informed riser wear management program.
Optimization of Bit Selection Leads to Improved Performances Onshore Thailand
Authors: Besson A. , Rabis P. , Scott D. E. , Torgerson T.
Published: December 2007

The lithology of northeastern Thailand features compacted shales, siltstones and claystones interbedded with hard and abrasive quartzitic sandstone and volcanic Stringers. Owing to the difficulties encountered in drilling this lithology, earlier wells were plagued by unacceptably low ROP and bit life. Further, unstable hole walls often led to excessive reaming, while use of heavier mud to maintain the hole wall would severely impact rate of penetration.

This paper describes the methodology and results of a partnership between operator and service company that greatly improved the drilling performance and economics of the subsequent exploration well. Central to the improvement was close cooperation between operator and service company in the early planning stages of the well and the decision to use advanced technology to reduce the risks. A detailed analysis of offset wells, including detailed dull bit analysis, led to the recommendation to use aggressive TCI bits with such premium features as metal face seals and active shear cutting diamond gauge inserts and selective placement of PDC bits where suitable.

The systematic selection of more aggressive cutting structures with active shear cutting diamond gauge inserts for drilling the very plastic shales with quartzitic sandstones instead of more traditional style medium formation TCI bits led to a higher ROP with no sacrifice in bit life.

The use of the active shear cutting diamond gauge configuration, usually applied in abrasive formations, led to increased life and reliability in the tough reaming operation in swelling / sloughing shales with excellent gauge holding performance and seal life. The more aggressive design yielded increases in ROP.

Results of the cooperative program – improved ROP, bit life and savings of more than $600,000 – will be presented and explained.
Prediction of Barite Sag Potential of Drilling Fluids from Rheological Measurements
Authors: Saasen Arild , Liu Dawei , Marken C. D. , Sterri Njål , Halsey G. W. , lsambourg Patrick
Published: December 2007

Barite sag under static and dynamic conditions has been studied in the laboratory. Static sag has been related to viscoelastic properties of several fluids. These viscoelastic properties are related to gel formation which needs to be sufficient to keep barite in suspension. This static sag was not predictable by the use of standard VG viscometers. Dynamic sag can be severe even when static sag is negligible. The understanding of dynamic sag is much more difficult than sag under static conditions.
Wellsite Action on Drilling Mechanics Information Improves Economics
Authors: Burgess T. M. , Martin C. A.
Published: December 2007

A major concern in the process of drilling is the high incidence and economic impact of lost time problems. In one study, it was shown that 75% of lost time incidents were associated with drilling mechanics problems. Obvious costs of poor drilling mechanics include lost rig time and damaged equipment. However hidden costs can add to this with low rate-of-penetration, more trips, lost-in-hole charges and increased service company charges.

Numerous technical papers in the past have documented specific drilling mechanics techniques. This paper summarizes the latest proven drilling mechanics techniques which have been applied to drilling operations to reduce these costs. The three major areas discussed are the following:

Stuck Pipe Prevention – Prevention of stuck pipe starts in the planning process where formation drillability is evaluated and borehole tortuosity is minimized. The operational phase of stuck pipe prevention involves continuous real time monitoring of drilling events, both for early detection of incipient sticking and to identify potential trouble spots while tripping.

Drillstring Failure Prevention – Shock and vibration often lead to extreme damage to drillstring and bit, broken downhole tools, and reduced rate-of-penetration. Mathematical models and surface measurements for failure prediction and detection have severe limitations. Downhole measurements of shock and vibration, in combination with surface measurements, can be used to determine which changes to drilling operational parameters can lead to the greatest reduction in downhole shock and vibrations.

Rate-of-Penetration Optimization – Using downhole drilling mechanics measurements, it is possible to increase weight transfer efficiency, reduce bit wear, optimize PDC bit performance, and improve PDM efficiency, all leading to improved penetration rates and more favorable economics.

Each of these broad areas is illustrated with field examples.
Fracturing Improvements Enhance Infill Drilling
Authors: Miller B. J. , Gillstrom R. L.
Published: December 2007

The production history of a one thousand well field extension drilled in the early 1980's showed that additional wells could not be drilled at current oil prices and oil recovery. Step out drilling and production history showed that an additional one hundred infill and development wells could be drilled if the recovery could be increased. Multiple production logs indicated the upper half of the zone was not open at the well bore. Thus, if the upper zone could be more effectively completed, the well recovery had the potential to be increased to a level where future development would be feasible. The low reservoir pressure and high permeability contrast requirements demanded that a much higher viscosity fluid system needed to be used that also had the ability to clean up easily. The nitrogen foam frac yielded these desired characteristics. Five infill wells were drilled in 1991 and 1993 utilizing a nitrogen foam frac system. Production from the wells has shown a projected ultimate recovery from the wells of approximately twice the original wells.
Process Redesign of Production Maintenance Operations
Authors: Rankin Mark , Lowe Bruce , Disney Vernon , Spilman Kirk
Published: December 2007

This paper describes a methodology for the systematic redesign of traditional production maintenance operations as they relate to subsurface failures of sucker rod pumped wells. The paper advocates an organized approach to process definition, refinement and redesign such that improvement objectives are clearly communicated, appropriate human and physical resources are brought to bear, and a system of improvement measurements becomes the overriding focus of the operation. Specific examples of the use of statistical process control tools in the production maintenance quality improvement effort are explored.
Design, Installation and Operation of a Pressure Maintenance Project: A Case Study
Authors: Campbell S. M. , Osisanya S. O.
Published: December 2007

A major concern facing operators in pressure maintenance projects involving gas injection wells and gas compressors is maintaining the safety of the equipment, the people, and the environment in case of a system's failure. A safety system was designed and installed as one continuous supply gas loop to ensure complete shut down of the plant facility. Compressed air was used for the power-drive of the system. Automatic fire sensors and extinguishers were installed throughout the facilities to decrease the chance of fire. Total cost of installation of this safety system was 60% of the original estimated authorization for expenditure (AFE). This paper discusses the process of designing, installing and operating a cost-effective safety system for a pressure maintenance project operated by Mewbourne Oil Company in the South Higgins Field, Ellis County, Western Oklahoma.
A Field Example of a Gas Orifice Meter with Debris-Ridden Liquid in Mist Flow
Authors: Chisholm J. L. , Mooney C. V. , Datta-Barua L. , Feldmann R. J.
Published: December 2007

A field example of debris-ridden liquids in an orifice meter is presented in this paper. Flow conditions in gas pipelines containing hydrocarbon liquids and particulate matter are discussed. Known effects on measurement of the presence of these materials in orifice meters is presented. By definition, gas measurement is accurate if performed on a "clean and dry" flow stream. This paper demonstrates the importance of removing as much liquid and debris as possible prior to measurement.
Selective Gel Treatments in the Countyline Unit, Oklahoma
Authors: Jasti J. K. , Zambrano L. G.
Published: December 2007

A waterflood optimization work program was conducted in a "Type" fault block in the Countyline Unit, Sho-Vel-Tum Field, Oklahoma. Selective gels were used to block random thief zones in the Upper Fusulinia Formation. There were eleven workovers, selective gel treatments in five injection wells, and a shift of water injection to downdip wells. Results show that the program has been successful in increasing production and ultimate recovery with significant improvements in the water injection profiles.

In addition, a new gel injection procedure has been discovered while carrying out the project. The procedure involves "pulsing" the reservoir to increase the amount of gel that can be injected into the matrix (while maintaining the injection pressure below the formation fracture pressure), thereby improving the gel's blocking capability.
Decentralized, Continuous-Flow Gas Anchor
Authors: Podio A. L. , McCoy J. N. , Wood M. D.
Published: December 2007

A novel gas separator design has been developed and successfully tested in several beam pumped wells which were subject to severe gas interference. This paper presents a detailed description of various designs to cover various ranges of fluid production for the most common sizes of completions(4-1/2 to 7 inch casing) and rates from 120 to 825 barrels of liquid per day.

The new design is based on two innovations:

Decentralization of the gas separator in the casing, insures that a minimum amount of gas enters the separator. The presence of two ports located on the narrow side of the annulus and placed a significant distance apart allow continuous flow of fluids into and out of the separator during both the upstroke and downstroke of the pump.

These innovations have resulted in a gas separator efficiency much greater than that of conventional designs.
Drilling Mud Rheology and the API Recommended Measurements
Authors: Clark Peter E.
Published: December 2007

Drilling fluids are, among other things, expected to transport cuttings and control fluid loss. The rheology of drilling fluids plays an important roll in both of these aspects of drilling fluid performance. A number of years ago the American Petroleum Institute established a set of standards for evaluating the rheology of drilling fluids. While drilling fluid technology has evolved and drilling fluids have become more rheologically complex, the standards have not changed sufficiently to adequately characterize the new generation of drilling fluids.
A New Polymer/Glycol Water-Based System for Stabilizing Troublesome Water-Sensitive Shales
Authors: Jarrett M. A.
Published: December 2007

The oil and gas industry is emphasizing more and more attention to choosing alternative safe aqueous drilling fluid designs as substitutes to environmentally hazardous oil-based drilling fluids as regulations become more restrictive for offshore and land operations, particularly in the United States and Europe.

This paper discusses the research and development of a new polymeric aqueous drilling fluid alternative, incorporating glycol and salt technology with improved performance in stabilizing water-sensitive shales with better environmental acceptance and biodegradability.
The Evolution of an Applied Hydraulic Fracture Project, Frontier Formation Moxa Arch, Wyoming
Authors: Harkrider J. D. , Aud W. W. , Cipolla C. L. , Hansen J. T.
Published: December 2007

This paper demonstrates a methodical approach in the implementation of current hydraulic fracturing technologies. Specific examples illustrating the evolution of a consistent reservoir/hydraulic fracturing interpretation are presented in a case history of three GRI-Industry Technology Transfer wells. Detailed modeling of these project wells provided an overall reservoir and hydraulic fracture description that was consistent with respect to all observations. Based on identification of the fracturing mechanisms occurring, the second and third project wells show the capabilities of realtime diagnostics in the implementation of hydraulic fracture treatments. By optimizing the pad volume and fluid integrity to avoid premature screenouts, significant cost savings and improved proppant placement were achieved. The production and pressure build-up response in the first project well verifies the overall interpretation of the reservoir/hydraulic fracture model and provides the basis for eliminating the use of moderate strength/higher cost proppant over sand in low permeability/higher closure stress environments.
Optimization of Hydraulic Fracture Treatments in The Williams Fork Formation Of The Mesaverde Group
Authors: Ely John. W , Brown Ted. D , Reed Shawn. D
Published: December 2007

An extensive fracturing study has been completed, evaluating over 400 fracture treatments on more than 130 Mesaverde gas wells in the Piceance Basin. This study involved a comparison of many types of fracturing fluids and techniques. Linear gels, foams, energized fluids, titanate crosslinked fluids, zirconium crosslinked fluids and borate crosslinked fluids have all been utilized in stimulating the Mesaverde formation in the study area. The authors evaluated the success of previous treatments which ultimately resulted in stimulation design changes, operational modifications, and expanded quality control methods. Dead strings were utilized on a number of treatments to record static tubing measurements and incorporate into a three dimensional (3D) fracture stimulation model. The modeling work assisted in determining fracture geometry which led to job size changes and revised perforating schemes. This paper will illustrate a number of correlations relating the effect of fracturing fluid viscosity, job size and completion method. Based upon the correlations of the study and the modeling work conducted, Barrett Resources has been able to greatly optimize their fracture treatments from the standpoint of cost effectiveness and enhancement of natural gas production.
Alkaline-Surfactant-Polymer Technology Potential of the Minnelusa Trend, Powder River Basin
Authors: Wyatt Kon , Pitts Malcolm J. , Surkalo Harry , Griffith Lawrence
Published: December 2007

The Alkaline-Surfactant-Polymer, ASP, process can significantly enhance waterfloods for appropriate reservoirs using carefully designed, reservoir specific, chemical injection strategies. This ASP technology recovers waterflood residual oil by reducing the capillary . forces trapping the oil and improving the overall contact efficiency. The Minnelusa formation in the Powder River Basin was the location of the first field-wide application of this process in the U.S. An assessment of this early project nearing the end of its economic life and of other ongoing ASP projects provides an estimate of the potential of the ASP process to add reserves in other Minnelusa fields.

Analysis of approximately 120 Minnelusa oil fields in the Powder River Basin indicates that the total original stock tank oil in place exceeds one billion barrels. The potential incremental oil recovery of the ASP process to these fields approaches 130 million barrels. This process can be applied at an incremental cost of $1.60 -$3.50/bbl.
State-of-the-Art Modeling for Unconventional Gas Recovery, Part II: Recent Developments (1989-1994)
Authors: King Gregory R. , Ertekin Turgay
Published: December 2007

In 1989, a survey of mathematical models which describe methane production from coal seams was presented at the SPE Joint Rocky Mountain Regional/Low Permeability Reservoirs Symposium in Denver, Colorado. This paper was later published in SPE Formation Evaluation Journal March 1991 issue. In this survey, 37 distinct models for coalbed methane production were reviewed in mathematical detail. Since that time, 15 additional mathematical approaches to forecasting reservoir performance, each with its own assumptions and limitations, have been developed. The objective of this paper is to discuss each of these recent models and to compare the assumptions, features, and limitations of these models with each other and with the original 37 models. Recommendations are also presented on the use of each model.
New Step-Rate Test Analysis for Fracture Evaluation
Authors: Lacy L. L. , Hudson H. G.
Published: December 2007

Step-rate injection tests are frequently performed in water injection wells for waterflooding reservoirs and in mini-fracture tests for stimulation treatments designs. In both applications, the data are usually analyzed to determine the fracture propagation gradient. To enhance the usefulness of step-rate test data, the current paper describes a new method of analysis that also determines the injectivity index of the well and fracture, the fracture length, width and effective leak-off rate. Injectivity analysis provides additional formation data which is useful for fracture designs, formation evaluation and optimizing water injection rates. Injection at gradients above the fracture gradient will greatly increase the injectivity of wells as determined by a fracture sensitivity parameter which is determined from step-rate data.

This analysis procedure has been successfully applied to multiple well tests conducted in Alaska and West Texas for waterfloods. In both waterfloods, multiple fracture gradients are indicated by the standard analysis. Injectivity analysis has determined the fracture gradient in both field cases using data from multiple wells. The analysis has also been successfully applied to low-permeability stimulation designs in the Rocky Mountains.
An Integrated Geologic and Engineering Reservoir Characterization of the North Robertson (Clearfork) Unit: A Case Study, Part 1
Authors: Doublet L. E. , Pande P. K. , Clark M. B , Nevans J. W. , Blasingame T. A.
Published: December 2007

BRIEF SUMMARY

Infill drilling of wells on a uniform spacing, without regard to reservoir performance and characterization, must become a process of the past. Such efforts do not optimize reservoir development as they fail to account for the complex nature of reservoir heterogeneities present in many low permeability carbonate reservoirs. These reservoirs arc typically characterized by:

Large, discontinuous pay intervals Vertical and lateral changes in reservoir properties Low reservoir energy High residual oil saturation Low recovery efficiency

The operational problems we encounter in these types of reservoirs include:

Poor or inadequate completions and stimulations Early water breakthrough Poor reservoir sweep efficiency in contacting oil throughout the reservoir as well as in the near-well regions Channeling of injected fluids due to preferential fracturing caused by excessive injection rates Limited data availability and poor data quality

Infill drilling operations only need target areas of the reservoir which will be economically successful. If the most productive areas of a reservoir can be accurately identified by combining the results of geologic, petrophysical, reservoir performance, and pressure transient analyses, then this "integrated" approach can be used to optimize reservoir performance during secondary and tertiary recovery operations without resorting to "blanket" infill drilling methods.

New and emerging technologies such as cross-borehole tomography, gcostatistical modeling, and rigorous decline type curve analysis can be used to quantify reservoir quality and the degree of interwell communication. These results can be used to develop a 3-D simulation model for prediction of infill locations. In this work, we will demonstrate the application of reservoir surveillance techniques to identify additional reservoir "pay" zones, and to monitor pressure and preferential fluid movement in the reservoir. These techniques are: long-term production and injection data analysis, pressure transient analysis, and advanced open and cased hole well log analysis.

The major contribution of this paper is our summary of cost effective reservoir characterization and management tools that will be helpful to both independent and major operators for the optimal development of heterogeneous, low permeability carbonate reservoirs such as the North Robertson (Clearfork) Unit.
Natural Fracture Characterization Using P-Wave Reflection Seismic Data, VSP, Borehole Imaging Logs, and the In-Situ Stress Field Determination
Authors: Lynn H. B. , Bates Richard , Layman Mike , Jones Mike
Published: December 2007

Seismic data in which anisotropy is observed have been used to detect and characterize the natural fractures, in the Bluebell-Altamont, Utah, field. We show an (azimuth-dependent) amplitude variation with offset (AVO) anomaly in the P-wave reflection seismic, attributable to the gas-filled vertical oriented fractures, and substantiated by the 9-component VSP.
Characterization of a Delaware Slope Basin Reservoir for Optimal Development
Authors: Weiss William W. , Ouenes Ahmed , Sultan Ahmad J.
Published: December 2007

A reliable reservoir description is essential to investigate various scenarios for successful field development. In this study, various new tools have been applied to fully characterize the East Livingston Ridge Delaware reservoir.

The Delaware formations in their slope/basin environment are difficult to characterize due to the channels in the submarine fans. Using well logs, a complex 3-D reservoir model composed of a channel through the bottom three layers of a seven layer model with one non-oil bearing zone was constructed to represent this complex depositional setting. Drastic changes in layer lithologies resulting in multiple oil/water contacts and varying water saturations required detailed log interpretation.

The porosity logs were tuned with available sidewall core information. Log porosity was determined for each layer at each well and kriging was used to estimate the areal distribution of the porosity. Porosity- permeability correlations for each layer were developed from sidewall core data. The correlations were used to make an initial estimate of the interwell permeabilities. A production history match was not possible with the initial characterization of the reservoir.

The production rates of the oil, gas, and water phases of each of the twenty-three wells in the East Livingston Ridge field and the pressure data were automatically history matched using a recently developed simulated annealing technique. The absolute and relative permeabilities of the layers were varied automatically during the history matching phase of the reservoir study. The larger scale properties resulting from the calibrated model were used to forecast the results of continued primary, infill drilling and/or waterflooding.
Engineering Criteria for Fracture Flowback Procedures
Authors: Barree Robert D. , Mukherjee Hemanta
Published: December 2007

Post treatment fracture flowback procedures during closure are often critical to the retention of fracture conductivity near the wellbore. Postfrac production performance largely depends on this conductivity. The importance of proper flowback procedure has been documented in the fracture industry, but definitive guidelines for flowback design have never been established. As a result, many misconceptions exist regarding the physics of proppant flowback and its effects on the final proppant distribution in the fracture.

This paper presents a rigorous study of fracture flowback and proppant migration during closure using a fully three-dimensional fracture geometry simulator (GOHFER). The effects of rate of flowback, location of the perforation interval, final proppant concentration, and the fracture geometry prior to flowback on the retained post closure proppant concentration are discussed. Consideration is given to the fluid velocity field in the created fracture resulting from the flowback, and its effects on proppant movement and localized fracture closure. These studies illustrate the difference between "forced closure" and "reverse screenout" concepts in flowback design. Other effects such as crossflow between multiple perforated layers are also studied. Simulation studies indicate that selection of a desirable flowback rate is very sensitive to crossflow effects resulting from induced fractures in multiple stress layers. This crossflow can result in significant overflushing of proppant in the lower stress zones, if not countered by properly applied flowback procedures. Very high flowback rates, exceeding the total leakoff rate, may be needed to avoid such overflushing.

The results of this study are assimilated into a set of recommendations for optimum flowback design leading to the maximization of the near-wellbore fracture conductivity and maximum attainable conductive length in communication with the perforations. Ideally, any properly applied controlled flowback procedure should induce a reverse screenout at the wellbore - forcing closure on the proppant by packing the near-wellbore area, not by depleting fluid pressure and "pinching" the fracture closed.
Imaging Hydraulic Fractures Using Temperature Transients in the Belridge Diatomite
Authors: Shahin G. T. , Johnston R. M.
Published: December 2007

Abstract*

Results of a temperature transient analysis of Shell's Phase I and Phase II Diatomite Steamdrive Pilots are used to image hydraulic injection fracture lengths, angles, and heat injectivities into the low-permeability formation. The Phase I Pilot is a limited-interval injection test. In Phase II, steam is injected into two 350 ft upper and lower zones through separate hydraulic fractures. Temperature response of both pilots is monitored with sixteen logging observation wells.

A perturbation analysis of the non-linear pressure diffusion and heat transport equations indicates that at a permeability of about 0.1 md or less, heat transport in the Diatomite tends to be dominated by thermal diffusivity, and pressure diffusion is dominated by the ratio of thermal expansion to fluid compressibility. Under these conditions, the temperature observed at a logging observation well is governed by a dimensionless quantity that depends on the perpendicular distance between the observation well and the hydraulic fracture, divided by the square root of time. Using this dependence, a novel method is developed for imaging hydraulic fracture geometry and relative heat injectivity from the temperature history of the pilot.

The azimuth of the Phase I hydraulic fracture is determined to be 14 ± 2° N-NE. The azimuth of the Phase II upper hydraulic fracture is determined to be 16 ± 2 ° N - NE in the northern half of the pilot, increasing to 21 ± 2° in the southern half of the pilot. The azimuth of the lower hydraulic fracture averages 19 ± 4°. The hydraulic fractures are found to be symmetric around both injectors with an estimated length of 200 ft.

Increased steam injection after the first year of pilot operations caused what is interpreted to be horizontal fractures toward the west in the G cycle and the east in the M cycle. These features are imaged to be at least 100 ft and 160 ft along the hydraulic fracture azimuth.

These conclusions are compared to tiltmeter data, microseismic data, and a simulation history match of pilot performance. Microseismic events recorded in the pilot are apparently not diagnostic of heat delivery to the formation.
Optimizing Steamflood Performance Utilizing a New and Highly Accurate Two-Phase Steam Measurement System
Authors: Huff B. D. , Warren P. B. , Whorff F. M.
Published: December 2007

A new highly accurate steam measurement system has been developed for the measurement of steam quality and flow rate. This system consists of a "V" cone (differential pressure device) and a vortex meter (velocity device) in series, along with temperature and pressure sensors all interfacing with an electronic datalogger. These basic mechanical meters are both rugged and relatively inexpensive for field monitoring purposes. Tests performed in active steam drive projects prove the viability of this system. As a result, every injector in the Coalinga field (around 100 steam injectors) has been economically justified for utilizing this new technology. Ever since the application of steam for commercial EOR operations, the petroleum industry has been searching for a method to determine both steam quality and flow rate for monitoring, analyzing and optimizing steam drive projects. This paper p00000000resents an overview of the new system, the background and development work that has been completed to date, and the reservoir analysis and economic justification required to implement this project.
Project Design for Slimhole Steam Injectors in Thermal Recovery Projects as Compared to Conventional Steam Injectors
Authors: Dennis E. L.
Published: December 2007

Slimhole injection technology has been used since early 1992 in San Joaquin Valley steamfloods. The major advantages of slimhole injectors over conventional injectors are: (1) low initial capital cost, (2) ability to place wells at optimum locations, (3) improved injection profile, (4) ease with controlling steam breakthrough in individual sands, and (5) low cost access to bypassed oil. There also are disadvantages: (1) limited injection rates and limited downhole survey or remedial work, (2) increased wellbore heat losses, and (3) increased potential for thermal stress- related casing failure.

This paper details advantages and disadvantages of slimhole injectors over conventional injectors and discusses design parameters that must be considered for successful implementation of slimhole injectors.
Testing and Production Performance of Slim-Hole Wells
Authors: Azari Mehdi , Soliman Mohamed , Wendler Curtis
Published: December 2007

The petroleum industry is focusing on cost reduction and efficiency more than it ever had. Slim-hole drilling and completion technology offer significant cost reduction potentials to the oil and gas industry. To provide an insight into slim-hole technology, production, stimulation, conformance, perforation, and testing aspects of reservoirs with wellbore and completion string diameters of less than conventionally drilled and completed wells are detailed here.

Productivity of both horizontal and vertical slim-hole wells, with and without hydraulic fractures, is compared with wells having standard wellbore sizes. Comparisons with conventional sized wellbores will be given that concern; 1) wellbore hydraulics, including nodal analysis and minimum gas rates required to lift fluids off the well, 2) the effect of wellbqre diameter on transient pressure testing, and 3) coning and cresting problems.

The performance of slim-hole wells compares favorably to standard wellbore completions for the parameters investigated in this study.
Economic Disposal of Solid Oil Field Wastes through Slurry Fracture Injection
Authors: Bruno M. S. , Bilak R. A. , Dusseault M. B. , Rothenburg L.
Published: December 2007

A variety of solid oil field wastes, including produced sand, tank bottoms, and crude contaminated soils from old well cellars and tank farms can be economically disposed of in an environmentally acceptable manner through slurry fracture injection (SFI). Solids are mixed into a slurry with fresh or produced water and injected at high pressure into suitable sand formations. The carrying fluid bleeds off rapidly, leaving behind a pod of solid wastes entombed by the natural earth stresses. High fluid leakoff allows more efficient creation and packing of short wide fractures.

At shallow to moderate depths, in-situ stresses may be sufficiently modified to establish horizontal fractures and allow periodic disposal of large quantities of solids - on the order of tens of thousands of cubic yards; With proper process design and monitoring, fracture growth can be Carefully controlled and contained within the target interval.

The slurry fracture injection process has been successfully applied to dispose of large quantities of oil saturated sands and tank bottoms in Alberta and Saskatchewan, Canada. This technique offers a number of economic and environmental advantages for disposal of solid oil field wastes. When reinjecting into depleted oil sands, the crude waste is simply being returned to its place of origin. The long term liability to the operator is eliminated, in marked contrast to surface storage or landfill disposal. Finally, for moderate to large quantities of solid waste fracture injection costs are less than typical transport and landfill disposal costs.
Computer Simulations of Proppant Transport in a Hydraulic Fracture
Authors: Unwin A. T. , Hammond P. S.
Published: December 2007

The equations of motion of a slurry in a narrow slot, such as a hydraulic fracture, are presented and solved numerically to obtain an estimate of the amount of gravity-driven vertical motion of proppant that can occur within a fracture during placement.

Two types of gravity-driven motion are studied: settling of heavy proppant particles; and convective proppant transport, which refers to the motion driven by large-scale density differences between regions of different proppant concentration.

Computer simulations are performed using realistic parameter values. In particular, we compare the vertical motion of proppant in a slurry in which the proppant particles are uniformly distributed across the fracture width (referred to as homogeneous flow) with that in a slurry in which some unspecified, but rapid, process has caused all the proppant to migrate across the fracture width into a close-packed sheet at the fracture centre (referred to as sheet flow).

In addition to considering a constant channel width, we also investigate the effects of an elliptic fracture cross-section on proppant placement. This fracture shape is predicted by idealized fracture propagation models such as the PKN model.

The main conclusions are that during placement Proppant settling and convection can occur under practical conditions.Convection rates are slightly greater in sheet flow than in homogeneous flow, and settling is greatly enhanced in sheet flow. Overall, settling in sheet flow gives the worst vertical motion of proppant. Settling and convection in homogeneous flow cause no problems under the conditions considered in this paper.In elliptic fractures, heavy proppant-laden slurry can over-ride earlier pumped lighter pad (zero solids) under most fracturing conditions.
Steam Management in Composite Mature Steam Floods, Midway Sunset Field
Authors: van Dorp J. J. , Roach R. H.
Published: December 2007

Vogel1 noted that oil production rates in many steam floods are not predictable from steam injection rates and must be estimated on some other basis. He presented a conservative method, based on simple models assuming instantaneous steam overlay, to calculate heat requirements once the oil rate is known. By more accurately describing the reservoir being flooded and the steam flood process, Vogel's method was refined resulting in significant steam savings for SWEPI's leasehold in the northern part of the Midway Sunset field. Analytical expressions are presented for 1) the heat required to support a steam chest descending into an oil column, 2) the heating of a cap or base rock already partially heated by an adjacent steam flood and 3) die heating of a cap or base rock which is exposed to a uniformally growing steam zone. A method is also described to operate a mature steam flood at a constant oil steam ratio while scavenging some heat stored in the steam zone.
Utilizing WASP and Hot Waterflood to Maximize the Value of a Thermally Mature Steam Drive in the West Coalinga Field
Authors: DeFrancisco S. T. , Sanford S. J. , Hong K. C.
Published: December 2007

The Water-Altemating-Steam-Process (WASP) has been utilized on Section 13D, West Coalinga Field since 1988. Originally implemented to control premature, high-temperature steam breakthrough, the process has improved sales oil recovery in both breakthrough and non-breakthrough patterns.

A desktop, semi-conceptual simulation study was initiated in June 1993 to provide a theoretical basis for optimizing and monitoring the WASP project. The simulation study results showed that the existing WASP injection strategy could be further optimized. It also showed that conversion to continuous hot waterflood was the optimum injection strategy for the steamflood sands.

The Section 13D WASP project was gradually converted to hot waterflood during 1994. Conversion to hot waterflood has significantly improved project cash flow and increased the value of the Section 13D thermal project.
Data Integration and Synergy Improve Reservoir Surveillance at South Belridge Tulare Field
Authors: Yonke C. L.
Published: December 2007

This paper describes some of the steps that Shell's Belridge Tulare asset took to successfully implement an integrated surveillance database system. The system has resulted in significant improvements in reservoir surveillance. The integration of all the available reservoir management data led to the creation of new multifunctional surveillance tools. These tools include steam injection maps by sand, sand drainage maps, wellbore diagrams for the 2,800+ Tulare wells, and annotated cross sections. These tools enable our engineering and operations teams to realize the benefits of multidisciplinary team synergy.

The database system allows multi-user access. It maintains data evergreen through electronic data updates, and it features automated procedures to generate and distribute the data needed for the surveillance tools. It is the product of a data management philosophy driven by multi-disciplinary teams. Placing information-rich surveillance tools directly in the hands of the end-user teams is a fundamental tenet of that philosophy.
Steamflooding a Waterflooded Reservoir -- Performance Evaluation and Prediction
Authors: Joshi Sameer , Wood Mike C. , Castanier L. M. , Brigham W. E.
Published: December 2007

The Wilmington Steamflood of Union Pacific Resources Co. (UPRC) at Long Beach, CA was initiated in 1989, in a previously waterflooded reservoir. Average initial reservoir oil saturation, at the start of the steamflood, was 35%.

Field production data were studied, to derive an overall energy balance for the steamflood, to calculate the steamflood capture efficiency and predict further steamflood performance. Heat-losses due to produced fluids were calculated. Predicted production schedules from the model were history-matched with field production data.'

All steamflood calculations were carried out using a PC-based spreadsheet program. The major results were as follows: The capture efficiency of the Wilmington steamflood was calculated at 60%. This is an acceptable value, taking into account the fact that the reservoir had previously been waterflooded to a low oil saturation of 35%.The calculated heat balance showed a high heat-loss, not only to adjacent formations, but also through produced fluids. Of the cumulative heat injected up to the time of the study, 21% had been lost to vertical conduction and 21% through produced fluids.Predicted production schedules indicated that up to 43% of the oil in place (at steamflood initiation) would be recovered by the steamflood.
Pressure Transient Analysis in Multilayered Faulted Reservoirs
Authors: Sahni A. , Hatzignatiou D. G.
Published: December 2007

This paper presents an analysis of the transient pressure behavior in a multilayered faulted reservoir with sealing and non-sealing faults. A three-dimensional numerical model is used to generate transient pressure responses at the producing well. A sensitivity analysis is conducted to examine the effects of the fault throw, formation transmissibility and storativity on the transient pressure behavior. Dimensionless pressure and pressure derivative type curves are developed and studied for the system under consideration. A methodology is developed which can be used to estimate the fault and formation transmissibility as well as the distance of the fault to the producing well from the newly derived type curves. Information obtained from this work can be used to improve the reservoir description and to optimize development plans.
Application of Damage Removal Treatment Results in Multi-Fold Well Productivity Improvement: A Case Study
Authors: Brannon H. D. , Tjon-Joe-Pin R. M.
Published: December 2007

Damage to proppant pack and formation permeability can drastically decrease well production. In many cases the damage is due to inconsistent degradation of gelled stimulation fluids and residual filter cake on the formation face. Several methods have been employed with limited success to remove polymeric damage in an effort to increase well productivity.

A new technique utilizing polymer specific enzymes has been developed to facilitate removal of polymeric damage. The new, environmentally safe, remedial treatment can be applied over a wide pH range and at temperatures as high as 300°F. Laboratory analysis has shown that multi-fold permeability improvements can be achieved through polymeric damage removal with the new system.

A case study of several low productivity wells suffering from polymeric damage was conducted. Production histories and return flow analysis were evaluated to characterize the damage and guide the remedial treatment design. The case histories of several wells treated with the remedial polymeric damage removal treatment demonstrate multi-fold improvements in well productivity.
In-Situ Radium Activity Measurements for NORM Assessment and Remediation.
Authors: Greer Charles. R. , Landress Mark. R.
Published: December 2007

The measurement of naturally occurring radioactive material (NORM) in soils and sludges associated with oil field production sites and waste pits traditionally has been performed by estimating radium-226 levels using gamma scintillation detectors and selective laboratory measurements on solid samples. NORM contamination in pits and ponds pose a particular challenge in terms of manpower and cost using current sampling and evaluation methods. Physical conditions and sample costs often limit the number of samples that are collected, and potentially results in serious errors in estimating NORM waste.

This paper will discuss a direct in-situ measurement technique to detect radium-226 which has been developed to overcome the limitations of standard NORM sampling techniques. Operational experience has demonstrated the effectiveness of this method for remediation which provides low cost and near real-time analysis for radium-226 in the subsurface. A case study is presented using this technique for a NORM pit remediation.