bluuebunny/crossref_metadata_2025 huggingface dataset:
A New Binary Surfactant Mixture Improved Foam Performance in Gas Well Production
Authors: Xu Rong , Yang Lin
Published: December 2007

A binary surfactant mixture that can generate stable, high quality foam at insitu conditions has been developed in this study. This paper presents laboratory results of this surfactant system and discusses its application in the gas well production.

We have used Ross-Miles, Waring Blender and Drill-Aid methods to evaluate foamability, half life of foam volume decay, and foam stability. It was found that a mixture composed of THSP, a derivative of Tea Plant, and SDS (sodium dodecyl sulfate) is a desirable aqueous base surfactant foaming liquid. It presents much better foam performance than other surfactants used before. The effects of H2S, salts and surfactant concentrations, condensate and reservoir temperatures on the THSP-SDS mixture in foamability and foam stability are investigated. At insitu conditions, this surfactant mixture is only one that can be used to drain water out from the gas well, and therefore enhanced gas well productivity.

In this paper, we will present chemical compositions of the THSP-SDS, show all the laboratory data and test procedures, and illustrate field application results. Research findings in this work provide useful information for engineers involved in using foam drainage in gas well production.
Alteration of Permeability by Fine Particle Movement—A Water Injectivity Problem
Authors: Asghari Koorosh , Kharrat Riyaz , Vossoughi Shapour
Published: December 2007

Siri field is located off shore of Iran in Persian Gulf. It was discovered in 1972. The field is producing from a formation called Mishrif which is common between Iran and United Arab Emirates. Existence of an active aquifer and other appropriate conditions led to the decision of a water injection program. The design and the implementation of the water injection program was performed by Elf Aquitaine and water injection started in 1984. The sea water from the Persian Gulf was found to be compatible with the formation water and was directly injected into the formation after passing through 10 micron filters. Water injectivity was drastically decreased and it reached from an initial injection rate of 9100 bbl/day to 2200 bbl/day within six years. Because of the severe injectivity loss, the water injection was stopped.

An experimental investigation was undertaken to look into the possible causes of the injectivity loss. Two sets of experimental investigation were undertaken with different objectives in mind. In the first part glass bead packs were used to test the experimental set up and to observe the general behavior of fine particle movement in porous media. In the second part core plug from the field and sea water were used to determine the possible cause of injectivity loss in the field. The experiments were conducted with a range of injection rate of 0.9 cm3/s to 3.1 cm3/s. Particles of bentonite were suspended in the injected water to simulate fine particles migration in porous media. The particles were injected at concentrations ranged from 20 g/1 to 40 g/1. It was observed that the build up in flow resistance was mostly due to the frontal face plugging. Particles of bentonite and alumina were added to the glass beads to study the effect of particles initially present in the glass beads pack medium.

Field and the laboratory data clearly indicate the importance of the water quality in a waterflood project. Experimental data suggest that a smaller size filter should have been implemented to avoid the injectivity loss.
Thermal Recovery Processes and Hydrogen Sulfide Formation
Authors: Hoffmann G. G. , Steinfatt Ingeborg , Strohschein Adelgunde
Published: December 2007

Thermal recovery processes are well established enhanced oil recovery techniques and are widely applied for recovering heavy oil, heavy oil sands, and shale oil.

During thermal recovery the formation of hydrogen sulfide, H2S, including the H2S induced reduction of sulfate to H2S, has to be taken into account in the reservoirs. The mechanisms of H2S formation are not well understood. Therefore, a great variety of experiments was performed, mainly to investigate the formation of H2S in the presence of crude oil under variation of the temperature (250 - 320 °C) and the reaction time. Thus, the reactivity of crude oil in the presence and in the absence of H2S, as well as in the presence and in the absence of ammonium sulfate, (NH4)2SO4, or sodium sulfate, Na2SO4, was examined. An attempt is made to explain the chemical pathways leading to the formation of H2S during thermal recovery methods. The improved knowledge about the H2S-formation during thermal recovery of fossil fuels can contribute to find solutions for its prevention and must therefore be seen from the environmental standpoint of view.
The Efficiency of a DTPA-Based Solvent in the Dissolution of Barium Sulfate Scale Deposits
Authors: Putnis Andrew , Putnis C. V. , Paul J. M.
Published: December 2007

This paper describes kinetic experiments to determine the rate at which Ba ions are mobilized from crystalline barium sulfate into aqueous solution by a solvent in which the active ingredient is a strong chelating agent for Ba ions (DTPA - diethylene triamine pentaacetic acid). The experiments define the temperature dependence and hence the activation energy of the dissolution process, the surface area dependence and most importantly the dependence on the concentration of the DTPA in solution.

In a 0.05M DTPA solution the dissolution rate of barium sulfate is highly temperature dependent with an activation energy of ~45kJ mol-1. This value suggests that the rate is controlled by the desorption of a Ba-DTPA surface complex. Surface complexation is further identified as the key to barium sulfate dissolution by the observation that over the concentration range 0.5M to 0.05M DTPA the initial dissolution rate is inversely related to the DTPA concentration. The activation energy remains unaltered but the absolute dissolution rate is increased. In other words, a 0.05M DTPA solution is more efficient as a solvent than a 0.5M solution. This unexpected result is interpreted in terms of a passivation of the barium sulfate surface by the formation of a surface complex layer at high DTPA concentrations.
Evolution and Development of a Deliverability Improvement Program for Gas Storage
Authors: Maddox T. D. , Sikorski D. L.
Published: December 2007

With the implementation in November 1993 of FERC Order 636, the responsibilities and contractual obligations for a Gas Transmission Company operating Gas Storage have changed. Among these responsibilities is the ability to deliver gas from storage in a timely manner as specified by gas storage contracts.

To ensure that their deliverability obligations are met, a program has been implemented to review well performance and to re-work wells where deliverability can economically be improved. This program is aimed at maintaining or improving deliverability from wells and monitoring their future performance.

Re-working existing wells has proven to be an economically successful method of maintaining deliverability compared to drilling new wells to meet this purpose. Re-working can be broken into two groups of wells: wells that have mechanical problems that need to be corrected or wells that need some type of stimulation treatment. In developing a rework program, several things need to be addressed such as: a candidate recognition program, the design of the work to be performed, execution of that work, and the evaluation of the results obtained along with the economics.

The Deliverability Improvement Program is in its third year. It has developed from a small pilot program to a substantial part of normal storage activities. The purpose of this paper is to review the processes used to find candidates to work on and an evaluation of work performed.
Coiled Tubing Applications for Underground Gas Storage
Authors: Fowler Hampton , Holcombe Don
Published: December 2007

Technological advances in coiled tubing (CT), CT handling equipment, and application techniques have provided new opportunities for the effective, economic use of CT for gas storage and retrieval. This paper presents a review of the CT capabilities that can be used for improving the performance of gas storage wells and discusses applications that could be performed with CT in the near future.

For more than 25 years, coiled tubing has been used as an effective, economic means of performing remedial well services. In response to the demand for better horizontal drilling equipment, the strength and diameter of CT has been increased, while surface equipment and downhole tools have become more sophisticated. CT is also widely used in well servicing after initial completion, especially since declining oil prices have made it imperative that operators find more cost-effective methods of increasing production and reducing maintenance costs. The gas storage industry can effectively take advantage of the many recent advancements in CT technology.
Analysis of Rate Decline Derivatives
Authors: Zhang Wenxia , Grader A. S.
Published: December 2007

This paper describes rate derivative curves of constant pressure tests similar to derivative analysis for constant rate tests. Four rate decline derivatives: Cartesian, log-semi, semi-log, and log-log, are constructed, Typically, the rate derivative curves have some special characters. The specific characteristics of these derivative curves are related to the different flow regimes and various boundary effects. The derivative curves and decline curves can be used for well test interpretation and diagnostic in a similar way to the constant rate tests. Therefore, in some cases nonunique problems in well test analysis are eliminated. In this paper, we consider rate declines of an arbitrarily placed well in various shapes such as a circle, a rectangle, a stringer, and an irregular shape.
Change in Treatment Style Doubles Salem Limestone Production
Authors: Albi James , Rodvelt Gary
Published: December 2007

After redesigning stimulation treatments to include hydraulic fractures with an epoxy-coated sand final stage, Texaco has achieved a two-fold increase in initial oil production from its Illinois Basin wells completed in the Salem Limestone.

Previous treatments conducted in Salem Lime wells included gelled acid with rock salt diverter, and foamed acid jobs. Initial production increases were favorable, but production declined rapidly. Acid-etch tests on Salem Lime cores showed poor conductivity gains. Twenty-seven subsequent sand fracture treatments pumped with an epoxy-coated proppant in the last stage resulted in initial production averaging 60 BOPD per well. The previous treatments averaged an initial production of 24 BOPD per well. The epoxy-coated final stage served to lock proppant in place after wells were placed on production.

This paper presents job designs and case histories showing the benefits of fracture-stimulating the Salem Limestone for production enhancement.
Integrated Approach to Natural Gas Utilisation in the Asia Pacific Region
Authors: Hovdestad Wayne R. , Egbogah Emmanuel O.
Published: December 2007

Wayne R. Hovdestad and Emmanuel O. Egbogah

The rapidly expanding economies in the Pacific Rim have placed increasing demands upon indigenous natural gas supplies in South East Asia and Australia. Competing demands include exports of liquefied natural gas (LNG), domestic consumption, and potential use for enhanced oil recovery (EOR) to extend the useful life of maturing oil fields. An additional competing demand for gas exports may emerge as the interstate pipeline grid is expanded.

Natural gas supplies in South East Asia and Australia are adequate to satisfy the increasing demands associated with economic growth and the desire to use environmentally cleaner fuels. The development of new gas fields, processing and transmissions facilities, however, involves large capital commitments and long lead times. These factors tend to favour staged development to ensure that facilities are fully utilised when placed onstream. This approach can lead to a mismatch between supply and demand depending on the development timing for gas supplies and increases to market demand.

An integrated approach incorporating the evolving nature of gas demands and discrete physical supplies would provide a means to mitigate against potential mismatching of supply and demand. The consideration of the evolving nature of gas demands could promote economically beneficial changes to gas field development. The development of high carbon dioxide (CO2 content gas fields has been slowed by the lack of a market for CO2. Utilisation of by-product CO2 for EOR could improve development economics, thus facilitating earlier development of gas supplies to satisfy gas demands including domestic use and LNG exports. End users would also benefit from the assurance that gas supplies would become available as needed. The maturity and increasingly complex natural gas industry in the Asia Pacific Region has led to a qualitative change. The model of single projects to satisfy single markets is no longer valid. The current environment is more dynamic, creating the need to anticipate changes to market demands and to find value-added markets for by-products. The integrated approach to gas utilisation discussed in this paper presents a new model more appropriate to the gas industry existing today in the Asia Pacific Region. This approach is particularly significant to widely discussed proposals for an Asia Pacific energy grid extending to Australia. In order to proceed, there must exist specific driving factors and stand alone economic merit to each segment in view of the high capital costs. The benefits of a completed system are often long deferred and hence of limited utility when actual project financing is to be obtained.

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A Hydraulic Fracturing Application To Overcome a Near Wellbore Damage in a High Permeability Formation
Authors: Soedarsono G. , Shucart J.K. , Harding C.D. , Said R.
Published: December 2007

In contrast to the common use of a hydraulic fracturing treatment in low permeability formations, recent advances of these treatment have overcome the limitations of matrix acidizing treatments performed in high permeability formations common to Indonesia. Being gravel packed with 5 Darcy permeability formation, WIA-8 well showed lower than expected productivity after completion. Efforts to restore the well productivity using matrix acidizing treatments resulted in additional productivity impairment. Recently, the well was worked over and the formation was treated with a small volume, high concentration, propped fracture treatment which successfully rectified the impairment. This is believed to be the highest permeability formation ever hydraulically fractured. This paper will outline the methodology used to design and perform a hydraulic fracturing treatment in high permeability formations.

INTRODUCTION

Widuri field is 90 miles (145 kms) north of Jakarta in the Java sea. The field is located on the northwest flank of the newly developed Asri basin (Figure 1).

The field was discovered in April 1988 vkaen Widuri-1 well was drilled to a total depth of 3735' subsea and encountered 170' of net oil pay in the Talang Akar sandstone formation. The field structure is a faulted anticline formed in the early Miocene age shortly after deposition of the sandstone formation. The trapping mechanism is both structure and stratigraphy with hydrocarbon deposits found in six immature fluvial or distributary channel sandstone formations from 3200' to 3700' subsea depth1. Most Widuri wells are gravel packed initially in an individual sand formation and produced using electrical submersible pumps. The subject of this paper, WIA-8 well, is gravel packed in the 35-1 formation which is unconsolidated sand with a log porosity of 29% and a test permeability of 5 Darcies.

After completion, some Widuri wells had experienced a productivity impairment. In August 1990, laboratory analysis was commenced to investigate the cause of the impairment and to determine an appropriate treatment. The results lead to performing subsequent matrix treatments on the WIA-8 well (Figure 2). In February 1992, a hot solvent treatment pumped into the well resulted in an additional productivity impairment. In April 1992, a retarded mud acid treatment performed in the well caused a severe productivity impairment. In November 1992, a revised retarded mud acid treatment with an improved clay stabilizer pumped into the well did not improve the productivity impairment.
The Drilled Well Scorecard: A Step to Building a Learning Organization
Authors: Brooker M. W. , Walker M. J. , Brett J. F.
Published: December 2007

Performance measurement is useless if it does not lead to process improvement. Evaluation of individual functional areas alone will not necessarily lead to a better overall process. The effectiveness of process inputs, outputs, and actions must be measured against the organization's underlying goals. UPRC is not in business just to drill holes in the ground; UPRC is in business to make money. Ideally, all actions in the process should reflect this goal.

To describe this whole system phenomena, we have developed a relational control model of the drilling process. Together, UPRC and OGCI designed a performance measurement system, the Drilled Well Scorecard, to reflect the relationships in this model and to make performance evaluations that will lead to real, continuous improvement. The scorecard was designed to facilitate communication across teams, to document project goals and assumptions, to measure the effectiveness of drilling plans in meeting these goals, and to reconcile the differences between intended and actual results.

If these scorecards are used for post-analysis and then to help plan future projects, they can facilitate organizational learning. A learning organization must: • define specific goals linked with its financial performance • ensure that actions are directed at meeting these goals • "remember" how decisions were made • build an accessible reservoir of experience, of the right expertise and technology • accurately monitor performance »use this experience to adapt its practices to "do it better next time.

When the organization uses the scorecards as system feedback, it will be able to capture the benefits of it's experience. The company is planning to use the experience stored on the "Drilled Well Scorecard" as part of an effort to improve both it's planning process and it's project execution, as a step to building a learning organization. Again, this should be the ultimate goal of any performance measurement program.
Safety Performance Monitoring for Drilling: A More Comprehensive System
Authors: Lievre Thierry
Published: December 2007

The Frequency Rates generally used in safety statistics for Lost Time Injuries and Minor Injuries provide measurement only on consequences and not on causes. As such they cannot help much in improving the safety performance of one particular operation or contract, especially for short term contracts. This paper describes a system which enables an early detection of failures of the safety management systems, before such failures lead to injuries. This system improved the safety performances of drilling rigs around the world, which resulted in a company Lost Time Accident Frequency rates divided by two.
Cuttings Re-injection on Mature Platforms: a Case History
Authors: van Gils J. M. I. , Thornton T. J. O. , Kece M. , Bennett W. , Yule G. K.
Published: December 2007

The paper summarises the experiences gained to date during the successful installation and six months' operation of cuttings reinjection (CRI) equipment on a major Operator's mature northern North Sea platforms.

Consideration is given to the constraints that mature platforms impose on the design in terms of power availablility, weight and space limitations, and personnel-on-board, as well as problems overcome in locating the CRI processing equipment away from the solids control package.

Other issues addressed in the paper include the rationale for the selection of injection candidates from existing wells; well integrity and wellhead erosion, including the results of erosion tests performed onshore; and operational experience.

The paper concludes that CRI is a practical solution to the tightening governmental legislation on discharges to the sea, allowing the unrestricted use of mineral oil based drilling muds for the extended reach and horizontal wells critical to the future of the Operator's field development.
Drilling Fluid Disposal System
Authors: Haymes R. D. , Daily S. C. , McGowin J. L.
Published: December 2007

A superior method of downhole annular disposal of drilling mud waste has been developed utilizing external casing packers and a modified port collar to isolate a predetermined disposal zone. The benefits of this system are that it reduces the risk of contamination of fresh (potable) water sources and greatly reduces the risk of jeopardizing the mechanical integrity of the well.

The conventional method of disposing of water-based drilling mud by evaporation/dewatering and backfilling of the reserve pit in many cases is no longer allowed, due to the protection of aquifers, hydrologically sensitive areas (HSA), and wellhead protection areas (WPA) in the State of Oklahoma. The use of geomembrane or soil liners is required in these areas.

The common methods of water-based drilling mud disposal in these areas are the following: Chemical solidification of pit contentsDisposal in a permitted commercial injection wellDownhole annular injection.
Low Cost Slim Hole Drilling System
Authors: Beswick A. J. , Hills D. L.
Published: December 2007

Interest in reducing the cost of exploration in frontier areas and in areas of special environmental concern has given rise to a variety of initiatives to develop ‘slim hole’ drilling systems and down hole tools. The market over capacity of conventional rigs offered at unrealistic commercial rates masks the real cost of operating heavy drilling equipment. This acts as a disincentive to the development of smaller innovative drilling rigs and associated equipment and the development of a smaller scale drilling system that has wide acceptance in the industry. Furthermore, funding for development of such systems has been sadly lacking.

In response to a contractual commitment, an opportunity arose to design and construct a small, low cost drilling system suitable for a range of slim hole and downsized drilling scenarios. In this particular case, the equipment was required to drill both vertical and slant boreholes with slant angles up to 45°. The drilling unit and associated equipment combine a blend of oilfield and mining ideas with the objective of demonstrating that a low cost unit could satisfy the requirements of the industry for frontier drilling.

The drilling unit is capable of both conventional destructive drilling up to 17-1/2 in diameter and continuous coring using heavy duty systems up to 6-1/4 in hole size. The singles rig is 100 ton capacity with a rotary capability from the top drive system of up to 400 rpm which gives a slim hole capability of over 3500 m.

The mechanised pipe handling system includes a hydraulic clamping device within the top drive head and an elevating and extending catwalk with hydraulic power breaker capable of breaking 8 in drill collars. The handling System will accommodate 13-3/8 in Range 3 casing. Triplex mud pumps, power pack and generators are housed in acoustic containers. The rig and associated equipment is designed to oilfield standards and all pressure lines are rated to 5000 lb/in2. A BOP handling system is included especially to cater for slant drilling and a hydraulic crane mounted at drill floor level together with a tugger winch provides general handling facilities around the rig. All main rig units are configured to 6 m ISO container standards for ease of shipping and port handling including mud tanks.

The rig includes a comprehensive computerised rig instrumentation system with a local computer network for the site and a sensitive automatic drilling facility operating through the hydraulic drawworks winch control system.

The paper describes the background philosophy, the equipment and the initial operations since commissioning the equipment in June 1994.
New Bi-Center Technology Proves Effective in Slim Hole Horizontal Well
Authors: Sketchler B. C. , Fielder C. M. , Lee B. E.
Published: December 2007

This paper describes the design and application of new bi-center bit technology in the Bay Marchand Field (offshore Louisiana). A bi-center bit and tandem motor assembly were used to simultaneously drill, underream, and directionally control a slim hole horizontal re-entry well using conventional directional techniques. This new bi-center technology significantly reduced cost for underreaming and eliminated the risk associated with the use of underreamers in a slim hole, high angle environment.
A New Development Towards Improved Synthetic Based Mud Performance
Authors: McKee J. D. A. , Dowrick Kevin , Astleford S. J.
Published: December 2007

This paper describes a new synthetic based drilling fluid (SBM) which is able to emulate oil based mud performance whilst complying with environmental legislation. Comparisons with oil based mud in the laboratory show that the system can provide similar performance at low synthetic:water ratio, high mud weight, high temperature and in the presence of contaminants. The laboratory results are supported by field data which demonstrate that the system can be managed like mineral oil based mud, giving good rates of penetration with minimum mud maintenance and low retentioh of the synthetic base fluid on cuttings discharged to the sea.

Marine toxicity, bioaccumulation and biodegradation data has been compiled for the SBM and the synthetic base fluid. Based on these results, the system has been accepted for use in UK and Norwegian waters, subject to Sea bed surveys following its use in trial wells. In the UK, the system has been placed in provisional Group E of the revised Offshore Chemical Notification Scheme (OCNS)1 product categorisation. For operations in the United States, the mysid shrimp 96 hour LC50 toxicity test result significantly exceeds the limit required for use in the Western Gulf of Mexico outer continental shelf.
Drilling Onshore People's Republic of China Utilizing a Chinese Contractor
Authors: Switzer S. S. , Frisbie J. W. , Malpas Peter
Published: December 2007

This paper reviews Fletcher Challenge Petroleum's experience in drilling a well onshore China utilising a Chinese drilling contractor. It details our approach to the project, the results achieved, and covers the full operations cycle from initial evaluation of the Chinese contractor's capabilities through their performance on the well drilled. This information provides insight and knowledge to Western operators who may work onshore China in the future.
Main Contractor's View Point of the Lekhwair Turnkey Project: Case History
Authors: Dudouet Michel , DeGuillaume Jacques
Published: December 2007

As part of the field development plan for the LEKHWAIR A-North oil field in the northern desert of OMAN, Petroleum Development of Oman (P.D.O.) has initiated middle of 1990 a Turnkey Drilling Project.

Galfar Engineering & Contracting of Oman and Forasol of France, by their joint-venture company (resp. 70/30 interests) National Drilling & Services Company LLC (N.D.S.C.) have been awarded the contract in november 1990 and have then initiated the challenging project. It started by the new construction of two purpose-built highly movable desert rigs and led to the spud of the 1st well, September 18th 1991 in the way to meet demanding targets (as to complete the first 25 wells by February 1st 1992). Simultaneously a turnkey drilling organization was installed locally in conjunction with well service companies and logistical/civil works forces to assume and supervise petroleum engineering functions and supplementary responsabilities, which were integrated in the Lekhwair Turnkey Drilling Contract. A total of 115 medium depth wells (94vertical at 1320/1330 m or deviated, plus 21 horizontal wells) were drilled on such a turnkey basis up to august 1993. Thus allowed the main contractor to handle new specialities like well completion services or managing of horizontal drilling directional package, simultaneously to the task of running operations in the hostile Omani desert; it appeared that the mode of new or improved drilling technology helped strongly to resolve this challenging context.

The paper will firstly give the various stages of the project, detailing scope of work, integration of drilling and completion services, QA/QC-safety management system, and rig design.

Secondly, we will analyze the general performances, highlighting the areas of particular importance (learning curve evolution, well acceptance relationship).

In the third instance main learning points are set up.

To conclude, we will give our opinion on how similar type of project should be approached in future.
A Case History of Completing and Fracture Stimulating a Horizontal Well
Authors: Abass Hazim H. , Hagist Peter , Harry James , Hunt James L. , Shumway Mark , Gazi Naz
Published: December 2007

This paper presents a detailed description of the completion and fracture stimulation of a high-angle well in the Madison formation of the Williston Basin in North Dakota. The case history of the Candee 26-13 HA well is used. The completion and fracture stimulation techniques used on this well resulted in a three and a half-fold increase in the ultimate recovery of the well, in comparison to a vertical well in the same field.

The well was directionally drilled to intersect natural fractures and provide optimal conditions for hydraulic fracture stimulation. To ensure zone selectivity and isolation, the well was cased and cemented. Notching techniques were used to allow hydraulic fracture treatments to be selectively initiated along the wellbore. Matrix acidizing was an essential phase to achieve this goal.

This paper also presents a discussion of how reservoir simulators can be used to optimize the number of fractures needed to cover a given drainage area. In addition, prefracture and postfracture evaluations are discussed.
Investigation of Intermittent Gas Lift by Using Mechanistic Modeling
Authors: Liao Tianlu , Schmidt Zelimir , Doty D. R.
Published: December 2007

Intermittent gas lift is a cyclic process which can be divided into four stages. This paper describes a mechanistic model for the intermittent gas lift system based on fundamental physical principles. The model accounts for reservoir inflow performance, fluid properties, two-phase flow in the tubing, gas flow in the tubing-casing annulus, the performance of a gas-lift valve and a surface gas injection choke, and various intermittent gas-lift control mechanisms. The mathematical model consists of a system of ordinary and partial differential equations for each of the four stages. The resulting system of equations is numerically solved. The model is capable of generating the detailed cyclic characteristics and the overall performance of an intermittent gas-lift system. The model is validated using experimental data collected by a number of previous investigators. These data cover a wide range of operating conditions for intermittent gas lift The model's predictions compare well with the experimental measurements. The effects of various system parameters on the performance of the intermittent gas-lift system are studied using the model, and the most important controlling parameters are identified. The ability to identify these controlling parameters and their optimum values for a given system allows one to operate an intermittent gas-lift system more efficiently. Finally, the performance of intermittent and continuous gas lift are compared, and qualitative guidelines are outlined for selecting between intermittent and continuous gas-lift methods.
Coiled Tubing Working Life Prediction
Authors: Wu Jiang
Published: December 2007

Failure of coiled tubing, due to the repeated bending and plastic deformation of coiled tubing on and off the reel and gooseneck, is of great concern in coiled tubing operations. This paper discusses the coiled tubing working life based on one of the coiled tubing life models published in the literature, and compares the results with other models. Certain agreements are found among these models.

A group of curves is presented to illustrate the coiled tubing working life affected by coiled tubing size and wall thickness, internal pressure, yield strength, reel diameter, gooseneck radius, operation condition (corrosion) and butt- welded connection (stress concentration). The results show that coiled tubing life can be greatly increased by increasing CT wall thickness and CT strength, while the coiled tubing working life decreases under high internal pressure, corrosion, and butt-weld conditions. These curves can be easily used in estimating coiled tubing life for the field use.
Thickness Optimization of Drilling Fluid Filter Cakes for Cement Slurry Filtrate Control and Long-Term Zonal Isolation
Authors: Griffith James E. , Osisanya Samuel
Published: December 2007

In this paper, the long-term isolation characteristics of two typical filter-cake systems in a gas or water environment are investigated. The test models were designed to measure the sealing capability of a premium cement and filter-cake system used to prevent hydraulic communication at a permeable-nonpermeable boundary. The test models represented the area of a sand-stone/shale layer in an actual well. In a real well, sandstone is a water- or gas-bearing formation, and sealing the annulus at the shale formation would prevent hydraulic communication to an upper productive zone. To simulate these conditions, the test models remained in a gas or water environment at either 80° or 150°F for periods of 3, 4, 30, and 90 days before the hydraulic isolation measurements were conducted. Models without filter cake, consisting of 100% cement, were tested for zonal isolation with the filter-cake models to provide reference points.

Results show that at 80°F, all filter cakes tested provided adequate zonal isolation up to 90 days. However, at 150°F, the reduction in filter-cake thickness prevented communication at higher pressures, The two highest pressures recorded occurred when no filter cake was on a water-saturated core. The next three highest pressures were measured with no filter cake on a gas-saturated core.

These results show how critical filter-cake removal is to the long-term sealing of the cemented annulus. Results indicate that complete removal of the filter cake provides the greatest resistance to fluid communication in most of the cases studied.
Shut-Off of a Geopressured Water Channel Behind Casing via Coiled Tubing Utilizing a Dual Slurry Cement System: A Case History
Authors: Nowak T. W. , Lange K. J. , Grant W. H. , Patout T. S.
Published: December 2007

This paper presents a case history involving a unique dual cement system to shut off a geopressured water channel behind casing utilizing coiled tubing. The channeling problem was identified and documented using water flow logging techniques. Logging indicated the lower gravel packed selective could produce salt water if perforated without eliminating the suspected water channel. Reserves did not warrant a major rig workover, making a non-rig workover via coiled tubing the only viable option to repair the well. A unique dual cement system tested on a hesitation squeeze schedule pumped through coiled tubing with extremely limited thickening time was necessary to repair the primary cement job.
Investigation of Procedures and Economics of Spill Site Remediation in Southeast New Mexico
Authors: Abbott Dave , Hillard Jerry D.
Published: December 2007

A pilot field study was initiated to evaluate the feasibility of remediating produced water and hydro-carbon contaminated soils along produced water gathering lines and disposal facilities in Southeast New Mexico. The soils were contaminated by leaks occurring adjacent to gathering lines and along Right-of-Ways over a 30 year time frame.
A Novel Approach to Predict the Co-Precipitation of BaSO4 and SrSO4
Authors: Li Ying-Hsiao , Crane Steven D. , Coleman James R.
Published: December 2007

Co-precipitation of strontium sulfate with barium sulfate is often observed in oil fields. Some explanations have been given, but the mechanism is not fully understood. A numerical simulation approach gives a detailed explanation of its occurrence. This results in an improved tool for operators in dealing with prevention and treatment procedures.

The computer model simulates reactive flow through porous media since injection of an incompatible fluid can induce numerous chemical reactions in a reservoir. The model uses the Gibbs free energy minimization technique to calculate chemical reactions that include precipitation from dissolved ionic species and dissolution of formation rocks. The model applies finite difference technique to solve mass transfer of the dissolved ionic species by convective fluid flow and diffusion.

A case study of a North Sea seawater flood revealed the mechanism of strontium sulfate formation and its relationship to barium sulfate precipitation. Once seawater contacted barium (in the carbonate form) in the reservoir, barium sulfate dropped out immediately. This reaction also created excess carbonate ion (CO3−−). Furthermore, although strontium carbonate is more stable than strontium sulfate, redistribution of the available CO3− forced strontium carbonate to dissolve and strontium sulfate to form. The results also suggest that the formation of the sulfate scales is not only controlled by their equilibrium constants but also dependent upon the concentrations of all other ionic species in the immediate vicinity.

The simulation technique leads to a better prediction of the quantity and composition of sulfate scale formation. It also provides in-depth understanding of the interactions of the reservoir rocks with injected fluids. The application can also be extended to quantify the formation of other types of scales which occur during production operations.
The SPE Video-Tape Series for Continuing Education
Authors: Caudle B.H.
Published: December 2007

In early 1967, the SPE elected to make a video-tape course that could be used by the membership in small groups at remote locations. The first video-tape series was designed to be given in 13 weekly sessions, each session consisting of 3 hours. Approximately 2 1/2 hours of video-tape lecture was prepared for each session. A technique was developed whereby a lecture was accomplished with the use of a black brush pen on white paper. This first course covered basic mathematics, fluid flow, material balance, and well testing procedures which are applicable to reservoir engineering. A text was prepared to accompany the lecture. Homework was assigned to be done between the sessions, and a solution of assigned homework was put on the first part of the succeeding week's video-tape. Approximately 8 months after the completion of the first course, a follow-up course was produced using the same techniques as in the first course. The second course was designed for 12 weeks of study.

The two SPE video-tape courses are administered by the Society's headquarters office in Dallas. The courses are offered twice each year to sections, and playback equipment and tapes are then loaned to each group wishing to conduct a course. The costs of administration are partially deferred through enrollment fee partially deferred through enrollment fee to local members.

The Society has constructed a small television studio in its headquarters office and additional courses are being developed in order to expand the SPE Continuing Education Program.

Introduction

During the latter part of the 1960s, a large fraction of the society membership became interested in "refresher" and "updating" continuing education courses. Those members in large local sections were able to organize such courses while members residing near a suitable Petroleum Engineering school could attend classes there. However, a large part of the membership could not be satisfied thusly. In 1967, the Continuing Education Committee of S.P.E. (which had been active in helping larger sections to arrange their courses) turned their attention toward the development of continuing education for the more isolated members.

After some discussion, 1/2 inch video-tape equipment was selected to be the vehicle for these courses.
Beta Field History: Submersible Pumps in Heavy Crude
Authors: Carpenter D. E. , McCrea A. A.
Published: December 2007

Beta Field, offshore Long Beach, was developed in 1981 with electric submersible pumps as it's primary artificial lift. The produced oil gravity ranges from 10-19 API. The wells had low initial water cuts, which increased as the waterflood matured. The impact of viscous production and increased water cuts on the ESP run times are presented here. Despite these challenges, equipment life is currently at 594 days. Equipment sizing techniques and the failure history are also shared.
A Commercial Microbial Enhanced Oil Recovery Technology: Evaluation of 322 Projects
Authors: Portwood J. T.
Published: December 2007

This paper discusses a data-base of information collected from 322 projects, all treated with the same Microbial Enhanced Oil Recovery process. An analysis of the data quantifies the effectiveness and economics of this particular process, and is a source of information useful for predicting treatment response in any given reservoir.
A New Environmentally Safe Crosslinked Polymer for Fluid-Loss Control
Authors: Cole R. Clay , Ali Syed A. , Foley Keith A.
Published: December 2007

The adverse effects of inadequate fluid-loss control associated with gravel-packed completions is well known. Controlling fluid losses to the formation before and after pack placement is critical to ultimately achieving optimum productivity from a given well for the following two reasons:

Fluid-loss control is necessary to prevent losses of expensive high-density brines, sometimes used for well control in high-permeability, unconsolidated formations. The costly loss of expensive brines can also lead to critically unsafe well conditions, where high overbalance pressures are required to control highly geopressured zones. Dense brines have been reported as being difficult to unload from formations once losses have occurred.1 Calcium and zinc-bromide brines can form highly stable, acid-insoluble compounds when reacted with some formation brines. Because of the high density of these brines, stratification tends to further inhibit their removal. The most effective means of preventing the formation damage described is to limit completion brine losses to the formation.
Measuring Skin While Drilling
Authors: Engler Thomas W. , Osisanya Samuel , Tiab Djebbar
Published: December 2007

A new model is proposed to characterize the variation in skin effect along a horizontal well. Typically, a cylindrical-shaped damaged region is assumed; however, this work describes the damaged region as a combination cylindrical-conical shape. The shape of the damaged region and the severity of the damage is governed by the contact time of the drilling fluid with the formation. This time is a function of the drilling rate penetration (ROP) and the mud filtrate invasion rate. Simple, empirical models are used to provide ROP and mud filtrate invasion rate.

The effects of anisotropy ratio, penetration rates, and horizontal length are included in the analysis. Anisotropy and increasing penetration rate both will result in a decrease in the skin effect. Any horizontal well length greater than the equivalent horizontal length of the cone-shaped damage region will result in a constant cylindrical-shaped damage region, which can be evaluated using Hawkins’ formula.

The cone-shaped damage region will exist at the furtherest end of the horizontal length. The time to transform the cone-shaped damage region to a cylinder is the circulation time after drilling to the total length. This circulation time is determined for the various anisotropy ratios and penetration rates.
A Comprehensive Approach to Formation Damage Diagnosis and Corresponding Stimulation Type and Fluid Selection
Authors: Xiong Hongjie , Holditch Stephen A.
Published: December 2007

This paper describes a comprehensive approach to formation damage diagnosis. Once the cause of formation damage and the location of the damage is known, then one can select the optimum fluid and design the best treatment to remove the damage. Our approach combines the domain knowledge with the best available expertise, then uses new technologies, which include fuzzy logic and an expert system. Our approach first diagnoses the formation damage mechanism, then we determine the treatment method, and finally we select the optimal fluids for the treatment.
Hydraulic Gas Pump: A Discussion of its Power Usage
Authors: Amani Mahmood
Published: December 2007

This paper presents the results of a study that compares the theoretically calculated power consumption of a Hydraulic Gas Pump, rod pumps, and electric submersible pumps. The results indicate that, depending on the flowing bottomhole pressure of a well, a Hydraulic Gas Pump can have lower power costs than a rod pump or a submersible pump.

We present a method for calculating the power cost of a Hydraulic Gas Pump and discuss the relationship of the power cost of this pump to the flowing bottomhole pressure. Several graphs compare the calculated power consumption of a rod pump, submersible pump, and Hydraulic Gas Pump for well depths ranging between 6,000 and 10,000 feet; flowing bottomhole pressure ranging between 500 and 2,000 psi; and production rates of 300 and 500 BLPD.
Development of a Completion Design to Control Screenouts Caused by Multiple Near-Wellbore Fractures
Authors: Stadulis Jerome M.
Published: December 2007

This paper discusses possible explanations, based upon previous studies, for the hypothesis that multiple fractures at the borehole wall may be a common feature of the hydraulic fracturing process. It then uses field examples to show how we concluded that a type of low-concentration screenout common to three fields in Texas and Oklahoma was caused by multiple fractures. Next, it shows how we developed a completion that controls loss of the pad and slurry to multiple fractures. Finally, it discusses some of the implications of our experience for completion design in general. Since the symptoms of the low-concentration screenout have been documented in the literature by other authors and appear to be quite common, our design techniques should be effective in other areas as well.

The completion design combines unoriented, zero-degree-phased, big-hole perforations shot at low density; and small, high-concentration proppant slugs with clean spacer stages pumped very early in the treatment. These strategies were chosen (1) to limit the number of separate fractures that initiate from individual perforations, and (2) to screen out narrow fractures early in the treatment so that more width is developed in the remaining fracture(s). We have used these techniques to increase overall sand/fluid ratios (including the pad) from about 2.3 ppg (Ibm added per gal fluid) to over 8 ppg, on modestly-sized treatments up to 200,000 Ibm.
Modeling of Undersaturated Coal Seam Gas Reservoirs
Authors: Kohier Timothy E. , Ertekin Turgay
Published: December 2007

Earlier numerical models for coal seam gas reservoirs assume that at initial reservoir conditions coal is either on or above the sorption isotherm, i.e., either equilibrium or saturated conditions prevail. Therefore, when undersaturated conditions exist, implementation of these models does not capture the physics of the problem accurately. In this paper, simple algorithmic procedures are proposed which allow the model to cross the isotherm between saturated and undersaturated regions during computations.

Several examples which demonstrate the successful application of the proposed algorithms are presented. Implementation of the switching mechanisms to existing coalbed simulators is straightforward and should significantly enhance their applications.