bluuebunny/crossref_metadata_2025 huggingface dataset:
Field and Laboratory Tests on Nitrate Treatment for Potential Use in Natural Gas Operations
Authors: Morris E. A. , Derr R. M. , Kenney T. M. , Pope D. H.
Published: December 2007

A variety of treatment products containing forms of nitrate have become available for use in optimizing microbial activities in a manner that results in improved system performance. While many of the traditional approaches to microbiological control have involved the use of biocides to achieve overall reduction in bacteria levels, the nitrate approach involves promoting growth of "beneficial" organisms which can negate the effects of, or out-compete the offending organisms. Suppliers of products, as well as systems operators in the natural gas industry, have reported the approach successful in a wide variety of applications including mitigation of downhole and above-ground produced water sulfide-souring, enhanced recovery of hydrocarbons in production reservoirs, and expediting cleanup of wastewater. In a study sponsored by the Gas Research Institute (GRI), Chicago Illinois, nitrate-based treatment strategies were assessed in field tests for efficacy in wastewater cleanup and mitigation of sulfide-souring in a produced water containment facility. In addition, laboratory tests were done to assess nitrate treatment for its potential for mitigation of downhole sulfide-souring using a test loop containing formation core material which was colonized by microbes producing sour water. Details on the test results, discussion of potential advantages/disadvantages of nitrate treatment, and criteria for determining if nitrate treatment is appropriate are provided herein.
Use of Fourier Transform Infrared (FTIR) Instrument for Air Toxic Compound Screening and Quantitation in the Natural Gas Industry
Authors: Evans Jim , McCarthy Jim , Ogle Larry , Shareef Gunseli Sagun , Campbell Lisa , Ferry Kathy , LaCosse Jeff
Published: December 2007

In response to the 1990 Clean Air Act Amendments, the Gas Research Institute is investigating emissions of air toxics from natural gas industry sources. As part of this effort, air toxic emissions data has been collected for various gas industry sources using a combination of measurement methods, including extractive Fourier Transform Infrared (FTIR). The FTIR protocol used during the program was initially developed along with quality control/quality assurance (QA/QC) procedures to meet the needs of the air toxics measurement program. Since there are no validated measurement methods currently available for quantifying aldehyde emissions from engines, GRI initiated a field test to validate the extractive FTIR method for measurement of these species using U.S. EPA Method 301 "Field Validation of Pollutant Measurement Methods for Various Media".

FTIR and other measurement methods were used in the field to collect air toxics data from sources located at a sour gas plant, as well as internal combustion (IC) engines at compressor stations. At the sour gas plant, emissions were monitored for IC engines, gas turbines, heaters, boilers, and tanks, as well as other sources. This paper presents a summary of the extractive FTIR measurement method, the development of the measurement protocol and reference spectra, and how the method was used in the field for data collection. Also included is a summary of the results using FTIR during the first four measurement campaigns, and a discussion of the FTIR validation effort using EPA Method 301 procedures.
Natural Gas Production: Performance of Commercial Technology for Removing Small Amounts of Hydrogen Sulfide
Authors: Leppin Dennis
Published: December 2007

The Gas Research Institute (GRI) is sponsoring an evaluation program for hydrogen sulfide (H2S) scavenging technologies as part of an overall sulfur removal recovery research program. The evaluation of liquid-based scavenging processes in batch tower applications was the first in a series of full-scale field evaluations. This paper discusses the results of the initial field evaluation which was conducted at a natural gas production plant in South Texas treating 16 MMSCFD of natural gas with 19 ppmv H2S and 0.5 percent CO2 at 1000 psig.

Three types of commercial scavenging agents were evaluated: nitrite, nonregenerable amine, and triazine. All three types met the treatment specification of 4 ppmv H2S. Capacities ranged from about 0.60 lbs sulfur per gallon of scavenging agent for the nonregenerable amine and triazine agents to about 0.75 lbs/gallon for the nitrite agent. Foaming was encountered with all of the agents and was controlled to manageable levels with defoaming additives. Overall treatment costs including capital recovery and operating costs ranged from about 0.037/MSCF for the nitrite agent to about $0.051/MSCF for the nonregenerable amine and triazine agents, based on treating gas containing 19 ppm H2S. (Operating costs will increase nearly in proportion to H2S concentration.)
Developments in Regulation of Air Pollution from Oil and Gas Exploration and Production James D. Braddock, Kelly, Hart & Hallman, P.C.
Authors: Braddock James D.
Published: December 2007

The impacts of the 1990 amendments to the federal Clean Air Act on oil and gas exploration and production activity are now being experienced. Regulations developed by both state and federal regulatory agencies are having direct as well as indirect effects on the industry. Although the 1990 amendments granted the industry regulatory relief in several areas, regulatory agencies are developing and implementing new programs that will have significant impacts.

This paper will address the substance and impact on the oil and gas industry of federal environmental regulatory programs such as those involving hazardous air pollutants (including risk management), control of methane to prevent global warming, regulation of hydrogen sulfide, and exploration activities in the outer continental shelf. The paper will also discuss state regulation, using Texas as an example. State activity includes implementation of many of the federal programs in addition to state-initiated regulation of the industry. Among the Texas regulatory efforts that will be analyzed are odor regulation, licensing requirements, and control of nitrogen oxides and volatile organic compounds to minimize the formation of atmospheric ozone.

This paper alerts oil and gas operators to the potential for additional clean air requirements in the future including the establishment of maximum achievable control technology ("MACT") for the control of hazardous air pollutants.
Emergency Preparedness for the Small Oilfield Contractor
Authors: Reavis H. C.
Published: December 2007

Changes in the oil and gas industry have been dramatic in recent years. Operators have consolidated field office facilities and downsized staffing at many of their remaining facilities. As a result, operators are turning to independent contractors as a method of controlling both peak personnel demands and selected production functions. With these changes in the business environment, the role of the specialized contractor has been greatly expanded. Tasks once performed by operator employees are now ongoing services provided by the contractor. Their performance can often be exemplary until a major emergency occurs. Emergency response can no longer be considered a secondary issue. Every contractor, small or large, must be equally prepared for an emergency. Their ability to address emergency incidents will have a direct effect in their success.

This paper is a presentation of the actual learning experiences of one oilfield contractor confronted with the task of emergency preparedness, more specifically a small contractor. Oilfield service contractors commonly employ field personnel who work for extended periods of time without direct supervision. These employees may singularly or collectively float between sites or anchor one site. Operating sites might be localized or spread over a vast geographical area. Because of the uniqueness of their situation, direct supervision is minimal and the employees will shoulder greater responsibilities and authority. The contractor must evaluate operating conditions and develop an approach which will achieve the optimum results.
Reclamation of Soil Affected by Oilfield Salts: Investigation, Assessment, Planning and Implementation
Authors: Evans G. B. , Barck J. A.
Published: December 2007

From well sites to water collection systems and disposal facilities across the U.S., salt in produced waters and waste residues has affected agricultural and range soils and shallow groundwater. Increasing concerns about these effects by producers, surface owners, trustees, and regulatory agencies suggest the need for realistic approaches to assessment and management of saline materials generated by the oil and gas industry. Salt impact assessment and management approaches have received much attention by agriculturalists, especially in irrigated desert regions, and these methods and tools can be adapted to the unique needs of the oil and gas industry.

This paper demonstrates salt assessment and management principles as applied to a typical site. Rapid quantification of the environmental setting and extent of impacts, using tools such as electromagnetic inductance (EM), accurately and inexpensively provides the basis for management decisions. Reclamation goals are then determined, accounting for the resource capability classification of soils and groundwater and the effects of local agricultural practices. Site specific reclamation alternatives are evaluated, supported by simple laboratory treatability screening of standard and innovative soil amendments. These efforts and associated cost analysis provide a basis for the development of an appropriate reclamation plan. Remedy selection attempts to optimize costs by taking maximum advantage of site conditions, natural forces, and time. Reclamation then results in return of the land to agricultural production.
Aquifer Exemptions: Wise Use of Environmental Protection Resources
Authors: Freeman Bill , Arthur J. Daniel , Mullican Jerry , Roberts Paul , Warner Don , Litzen Lori
Published: December 2007

The competition between ever-expanding environmental regulations and the ongoing decrease in environmental protection resources has prompted both regulatory agencies and industry to more closely examine the use of these limited resources. In the underground injection control (UIC) program, technical and managerial professionals from industry and government must at times evaluate whether or not certain ground water aquifers should be protected. If an aquifer exemption is clearly justified, the operator should not have to protect it, hence conserving valuable environmental protection resources. However, some state and federal agencies would prefer never to approve an aquifer exemption even though some are justified. This is apparent as the variations regarding how aquifer exemptions are processed by agencies seems largely to be resulting from the lack of clear guidance on aquifer exemptions and the lack of understanding for the term "reasonably expected" as intended by EPA and Congress. Because of the lack of positive instruction from state and federal agencies and a general lack of awareness on industry's part, the aquifer exemption process continues to be somewhat esoteric and often times misunderstood.

The purpose of the UIC Program as mandated by Congress is to protect underground sources of drinking water (USDW) being used in public water systems, as well as to protect potential USDWs where there is a reasonable likelihood that these sources will be needed in the future. However, Congress did not intend for EPA to protect all potential USDWs. If it was reasonably expected that a potential USDW could not be used in the future as a public water system, protection of that aquifer would not be required. In fact, EPA affirmed that it would be a misallocation of resources to seek to protect as drinking water sources aquifers which in fact would not be used by public water systems. To ensure that such aquifers would not be protected, EPA developed an aquifer exemption process under 40 CFR 144.7 and 146.4 by which aquifers could be evaluated for their potential use as future public water systems. Government and Industry should utilize the aquifer exemption process as much as possible to ensure that the wise use of limited environmental protection resources is accomplished. The Clinton Administration appears to also endorse this position. In an April 1994 Letter to Congressman Earnest J. Istook on the domestic oil and gas industry, President Clinton stated: "we intend to help on the cost side… by reducing unnecessary and inefficient costs and regulations. I have challenged federal agencies to eliminate regulatory overkill and to attack regulatory barriers and subsidies here and abroad".
Brine Handling and Disposal by Reinjection
Authors: Knowles D. W. , Boytim R. G.
Published: December 2007

Opportunities to reduce the cost of brine handling and disposal by reinjection in the gas and oil producing industry have been identified in an ongoing study sponsored by the Gas Research Institute and managed by ENSR Consulting and Engineering. Gas and oil fields operated by many production operating companies across Texas and Louisiana have been studied. To date, the East Texas portion of the study has been completed and includes seven companies, nine producing fields and 30 brine disposal stations. The study has focused on operating cost variations, state of the art technology in practice, and the most effective operating practices. Results from the East Texas study area are presented and include the following topics:

Surface Equipment Water Treatment Disposal Wells and Reservoirs System Monitoring and Control Environmental Compliance Operating Costs Improvement Opportunities
Preparation of Naturally Occurring Radioactive Material (NORM) for Hydraulic Fracturing Disposal: A Case Study
Authors: Fletcher P. A. , Cornette C. A. , Sustala D. R. , Dolence T. W.
Published: December 2007

This paper presents a case history of ARCO Oil and Gas Company's (AOGC1) Naturally Occurring Radioactive Material (NORM) injection project that was conducted offshore in the Gulf of Mexico. The unique aspect of this project is that it was performed entirely offshore, using drill cuttings injection equipment. This project involved grinding and injecting approximately 1300 bbls of various NORM. Discussed in the paper is the historical regulatory considerations, reservoir selection and permitting process, pre-frac design process, the washing, grinding and injection process, and on-site data frac analysis and fracture post-mortem.
Optimising Water Injection Performance
Authors: Paige R W , Murray L R , Martins J P , Marsha S M
Published: December 2007

In recent years, major advances have been made in understanding injection well performance. In particular, the impact of fracturing, thermal stress effects and water quality are far better understood, as a result of both improved theoretical understanding and from detailed analyses of field data.

This paper reviews our current understanding of the processes which control the performance of injection wells, including the effects of produced water quality, taking examples mainly from the Prudhoe Bay and Forties oil fields. Techniques for predicting and optimising injector performance under a variety of circumstances are discussed, together with the implications for waterflood management.
An Innovative Secondary Recovery Approach for a Marginal Reservoir
Authors: Clark T. J. , Hanafy H. H.
Published: December 2007

The Younis Lower Rudeis reservoir is operated by the Gulf of Suez Petroleum Company (GUPCO) in a remote area of the Gulf of Suez, Egypt. Younis has repeatedly been considered a waterflood candidate due to a decrease in reservoir pressure from the initial 1932 psi to the current estimate of 492 psi in 1993. But based on decline curve analysis and structural mapping, primary recovery was expected to reach nearly 50 percent of the 44.6 MMBO original oil-in-place (OOIP). Under the assumption that Younis produces with an efficient gravity drainage depletion mechanism, waterflooding potential was considered low. Furthermore, Younis is nearly 16 Km from the nearest waterflood facility, and pipeline costs were considered prohibitive based on both low incremental reserve potential and depressed oil prices.

Before concluding that Younis had no future potential, GUPCO commissioned a reservoir/facility engineering team to study the reservoir development potential. First, reservoir simulation would be used to improve the understanding of the depletion mechanism and the original oil in place. Second, simulation would be used to determine the potential for waterflooding. Third, if waterflooding potential exists, the team must find a way to economically develop the incremental reserves.

The reservoir simulation work clarified the depletion mechanism in Younis, and indicated a significant potential for waterflooding exists. History matching of the historical reservoir performance discovered that a much larger reservoir volume is actually present than mapped, and that ultimate recovery will actually reach only 22 percent of the OOIP. Furthermore, while gravity segregation of gas is occurring, significant unrecovered oil reserves will remain downdip of the current producers. Waterflooding could aid recovery of this downdip oil.

With expected reserves from the waterflood project to total 5.3 MMBO, the facility engineers were challenged with providing up to 6000 BPD of water to the platform. An innovative technique was ultimately designed to install all needed equipment on the Younis unmanned platform for a remote waterflood. Since surface injection is expected to occur under a vacuum due to the low reservoir pressure, inexpensive equipment would be used to withdraw water from the Gulf, treat and filter, and deliver to the injection well at the required rate.
Alliances and Partnering: A New Relationship Between Oil/Gas Producing Companies and Service Companies
Authors: Gazi Naz H. , Hottman W. E. , Logan Jerry L. , Verrett R. C.
Published: December 2007

The current state of the energy industry finds both operating and service companies squeezed by lower prices and higher costs. Investment in exploration, equipment, and technology has been severely restricted. many operators are responding to these harsh market conditions by re-engineering their work processes and focusing on core business activities.

Re-engineered work processes encourage operators and service companies to work closely together. This motivates both to eliminate duplication, simplify processes, increase efficiency and capitalize on combined expertise to enhance production and optimize total system cost.

Alliances and partnering are based on mutual trust and the commitment to add value to both organizations. Aligning interests is fundamental in establishing a lasting and mutually beneficial relationship.

This paper presents an overview of these new relationships. The benefits and concerns of changing from traditional bidding agreements to new business arrangements between producing companies and service companies is discussed.

Evaluation criteria for potential candidates, how to structure an alliance or partnering agreement, and a discussion of the key issues in the application of incentive contracts is presented.
Oily Drilled Cuttings - A Pro-Active Approach to Protecting the Environment
Authors: Holt Charles A. , Prewett Harry , Mansour Sayed
Published: December 2007

Oil base drilling fluids are imperative to the success of GUPCO’s Gulf of Suez drilling operations. Protecting the environment while utilizing these environmentally unfriendly drilling fluids has proven to be a challenge. This paper describes how GUPCO championed this challenge.

Early attempts to drill the reactive shale and low pressured-high permeability sands exposed in the lower Tertiary with water base drilling fluids resulted in wellbore instability, differential sticking, and loss of hole. These drilling problems were all but eliminated with Oil Base drilling fluids (OBM). Furthermore, OBM provides the lubricity that is essential to the success of high angle, horizontal, three-dimensional, and long reach wellbores, which are becoming the norm rather than the exception at GUPCO.

GUPCO drilling has pursued several means to satisfy drilling needs and environmental concerns; 1) slurrification and downhole injection of OBM cuttings, 2) hauling OBM cuttings to shore for disposal, 3) utilization of OBM alternatives.

Slurrified cuttings have been injected below surface casing via the annulus between surface and intermediate casing strings, or in the case of the SIDKI re-development project, an injection well was drilled. Injection guidelines, procedures, and injection results are presented in the paper.

Oily cuttings have been collected in containers on the rigs and hauled onshore for disposal. Drilling rigs in the GUPCO fleet have been modified to handle the OBM and properly collect the oily cuttings. The paper describes the rig modifications for zero discharge of oily cuttings, including the oily cuttings collection process.

Due to the environmental concerns associated with OBM, water based inhibitive mud systems have been attempted in the GOS. Cationic Brine Fluid (CBF) and Partially Hydrolyzed Polyacrylamide polymer (PHPA) drilling fluids have been utilized as OBM alternatives. The results and conclusions are included in the paper.
Three Dimensional Geologic Modelling of a Fractured Reservoir, Saudi Arabia
Authors: Luthy S. T. , Grover G. A.
Published: December 2007

A geological assessment of a large carbonate reservoir in Saudi Arabia shows that it is a Type 2 fractured reservoir in which fractures provide the essential permeability. Intercrystalline microporosity, found within the basinally deposited mudstones and wackestones, is the dominant porosity type. Near-vertical, east-west-oriented extension fractures are preferentially localized in low-to-moderate porosities associated with stylolites. Porosity/fracture density relationships, combined with the results of structural curvature mapping, yielded a 3-dimensional model of fracture density. Fracture permeability and fracture porosity distributions were generated by integrating fracture density modelling results with average fracture aperture information derived from well test data. Dramatic differences exist between matrix- and fracture-related porosity, permeability models that help explain observed production behavior within the field. These models are being used by reservoir and simulation engineers for daily reservoir management, history matching, and long-term development drilling planning.
Middle East Reservoir Characterization Improved by Data from Horizontal Wells
Authors: Nurmi Roy , Wiltse Elliott , Sapru Ajay
Published: December 2007

Middle East reservoir development using horizontal wells is no longer restricted to problematic reservoirs. Although the basic geometry of most major fields is generally well known, the detailed variations of individual reservoir zones often are not sufficiently well defined to predict what will be encountered by a horizontal well. Structural variations often result in long intervals of the horizontal wells not being within target reservoir zones. However, geosteering techniques and a closer integration of all data gathered during drilling provide more optimum placement of horizontal and extended reach wells.

Undiscovered compartments with original pressures and oil saturations are being revealed in and around major reservoirs, thus, adding new reserves or better developing an existing reservoir. The permeability barriers and reservoir compartments are being defined by horizontal well testing. However, it is also important in some cases to avoid high-permeability thief zones and/or open faults to decrease water and/or gas production which has often been misinterpreted as coning. Data from horizontal wells allow better definition of the attitudes of fractures and faults and their hydraulic character. In most cases horizontal wells are drilled so as to intersect more fractures however in a few cases the wells are drilled to avoid open fractures and/or faults.

3-D seismic surveys are revealing more complexities within the average reservoir. Horizontal wells are showing that there are complexities invisible even to 3-D seismic. Quality seismic is still invaluable for planning horizontal wells, however, good geologic analyses, measurements while drilling and intermediate logging are often necessary to make adjustments to the well trajectory during drilling. The strengths and limitations of standard well logs, production tools, and testing equipment made for vertical wells need to be understood when used in the horizontal section so as not to misinterpret the potential of a reservoir zone. Even how geoscientists think about the reservoir is changing because of the "lateral thinking" being experienced during studies of standard horizontal well applications. Thus, new applications continue to increase for this relatively new petroleum industry technique.
Slim-Hole Drilling and Innovation Enable the Development of the October Nezzazat, a Marginal Field in Egypt
Authors: Hassan I. , Mansy A. , Cook B. S. , Leggett R. B.
Published: December 2007

The Gulf of Suez Petroleum Company(GUPCO) has recently used "slim-hole" drilling technology to enhance the economics of developing a marginal field by significantly reducing drilling and development costs. Drilling costs have been reduced by approximately 20%. Risks have also increased with slim-hole technology, but are within manageable levels. In order to ensure a deep point of injection is maintained, small but difficult-to-fish gas-lift equipment has been installed inside of a 5-inch production liner. To date, no corrosion has been observed in the October field which would weaken the slim-hole bottomhole assembly and prevent future recovery of the packer and tubing. Sidetrack flexibility has also been reduced with the smaller tubulars.

The October Nezzazat field is located offshore in the Gulf of Suez and is penetrated by wells which were drilled to the prolific Nubia formation. Independent development of the Nezzazat field using conventional drilling and completion technology has not been possible due to less favorable economics. Historically, the Nezzazat has been developed by recompleting watered-out downstructure Nubia wells. Nezzazat development timing has therefore been subject to Nubia depletion. Wellbore placement in the Nezzazat has in the past been wholly a function of Nubia development requirements.

The recent application of creative and innovative ideas have helped accelerate the development of the October Nezzazat field. Since most of the October platforms have been fully-drilled and since setting a platform to develop the marginal Nezzazat field was economically prohibitive, additional slots were added to platforms which could support the additional loads in order to drill the marginal Nezzazat wells. Further, since gas-lift compression is limited at the October production complex, any additional drilling would have resulted in a re-allocation of available gas-lift gas. This would take lift-gas from existing wells and defer the full production impact of the new wells. As an alternative, less-expensive shoreline compression was installed and gas-lift gas was delivered offshore by injecting through an existing, under-utilized pipeline. Finally, with less-expensive slim-hole completions, the October Nezzazat field may now be developed independently of the Nubia formation resulting in greater production and reserves from the Nezzazat.
The Planning of The Drilling and The Rig Upgrading for The HPHT Pre Khuff Well
Authors: Rose Richard
Published: December 2007

In 1992 ADMA OPCO (Abu Dhabi Marine Operating Company) started the detailed planning of a deep HPHT vertical exploration well that was to be drilled offshore Abu Dhabi on behalf of ADNOC (Abu Dhabi National Oil Company). Relevant offset data was not available. The nature of the well dictated that an optimised casing design would be required, and that significant rig modifications would be needed to satisfy the requirements of the well. This paper outlines how those challenges were achieved.
Wire Line Formation Pressure Testing and Sampling: Field Applications In Saudi Arabia
Authors: Douglas Adrian A. , Al-Daalouj Abdulla I.
Published: December 2007

Recent developments in the technology of wire line formation testers has lead to new applications which would not have been possible with the previous generation of tools.

This paper describes the field applications of the Modular Dynamics Tester (MDT*) in Saudi Arabia. These applications include obtaining pure formation water samples in areas of unknown water resistivity in order to aid electric log interpretation, and performing vertical permeability tests using a multiple probe configuration of the tool.

The analysis of vertical permeability tests has shown that a new analytical modeling technique, known as pressure-pressure formulation, brings significant improvements to the interpretation of transient pressure data because it eliminates the need for any direct measurement of flow rate.
Integrated Interpretation of Galvanic and Induction Measurements by Inversion Methods
Authors: Mezzatesta A. G. , Eckard M. H. , Payton C. C. , Strack K. -M.
Published: December 2007

Accurate estimation of residual and movable hydrocarbon requires precise estimation of the formation resistivities in the flushed and uncontaminated zones. The estimation of formation resistivities is commonly done by interpreting the data provided by galvanic (mainly laterolog) and induction devices. Different physical principles govern these devices. In galvanic tools, the voltages being measured are related to the surface charge densities at the interfaces between adjacent media of different resistivities, whereas in induction tools, the voltage induced in a measuring coil results from the magnetic fields due to alternating currents flowing in the surrounding formation.

Conventional interpretation methods of electromagnetic measurements use approximate and independent techniques for galvanic and induction logging measurements. These techniques provide some means to correct the resistivity measurements for borehole, shoulder, and invasion effects. Since the charts are typically designed for the interpretation of the measurements that correspond to a single suite of logs, individual results may differ when different sets of measurements available in a particular borehole are used in the interpretation. The interpretation, i.e., finding an earth model consistent with all measurements, is then left to the skill of the log analyst.

A simultaneous inversion of galvanic and induction data considers a single earth model, consisting of a distribution of resistivities, that is consistent with the two types of measurements. The inversion process also provides statistical results that help the log analyst assess the quality of the interpretation results. Combining measurements based on different physical principles also improves the resolution of the estimated formation parameters, such as resistivities and invasion depths.

This work demonstrates how the interpretation is improved by using an algorithm that simultaneously considers all available resistivity measurements. The work also shows the importance of the inversion process in extracting the information content from the data in cases that would not be possible by using conventional interpretation methods, as well as the use of statistical results to assess the quality of the interpretation. Several field cases are presented that show the importance of unified interpretations in improving the accuracy of the formation resistivity estimation, and the enhancement of radially and vertically layered earth models that result.
Computer Assisted Operations In Petroleum Development Oman (Pdo)
Authors: Al-Hinai S. H. , Mutimer K.
Published: December 2007

Petroleum Development Oman (PDO) currently produces some 750,000 bopd and 900,000 bwpd from some 74 fields in a large geographical area and diverse operating conditions. A key corporate objective is to reduce operating costs by exploiting productivity gains from proven technology.

Automation is seen as a means of managing the rapid growth of well population and production facilities. The overall objective is to improve field management through continuous monitoring of wells and facilities and dissemination of data throughout the whole organization. A major upgrade of PDO’s field Supervisory Control and Data Acquisition (SCADA) system is complete providing a platform to exploit new initiatives particularly for production optimisation of artificial lift systems and automatic well testing using multi selector valves, coriolis flow meter measurements and multi component (oil, gas, water) flowmeter. The paper describes PDO’s experience including benefits and challenges which have to be managed when developing Computer Assisted Operations (CAO).
Facilities Engineering for a Full Scale Gas Injection Project
Authors: Saadawi Hisham
Published: December 2007

Bu Hasa field is the largest onshore oil field in the United Arab Emirates. In order to enhance oil recovery, a full scale pattern gas injection project is currently under construction. The project aims at injecting 150 MMscf/D (4.2 × 106 std m3/d) in 14 injection wells. The wellhead injection pressure is 5400 psig (372 bars).

This paper describes the surface facilities of the gas injection project and addresses the basic design concepts. The paper also outlines project implementation aspects.
Production Trap Improvements Using High-Efficiency Internals
Authors: Delavan D. P. , Wilson T. T.
Published: December 2007

Most of the Gas-Oil Separation Plants (GOSP) in Southern Area Producing of Saudi Aramco will be producing between 40% and 75% water cuts by the turn of the century. Many GOSPs will be producing more than twice the amount of water they were originally designed for. Consequently, modifications must be made to the GOSPs so that they will have the capacity to separate and clean up these large volumes of produced water.

The most attractive option is to improve the separation efficiency of the High Pressure Production Traps (HPPT) where formation water is first removed from the wellhead fluid. These traps have historically removed very little water from the wellhead fluid. However, the following modifications have proven to significantly improve the separation efficiency of the traps: Double the height of the weir, and raise the oil level from 40% to 65% full.Install a new inlet device to minimize the formation of foam.Install coalescing and foam-breaking internals to enhance oil/water coalescing and separation and to break the foam on top of the oil layer.
Horizontal Multiphase Flow Correlations for Large Diameter Pipes and High Flow Rates
Authors: Al-Ne’aim S. A. , Aggour M. A. , Al-Yousef H. Y.
Published: December 2007

The most widely used horizontal multiphase flow correlations have been tested against field measurements in order to determine the best correlation(s) for Saudi Arabian field conditions. A total of 450 field data points covering pipe sizes from 6 in. to 10 in., oil flow rates from 2200 to 25600 STB/D, water cut up to 60% and GOR up to 984 SCF/STB were used in this study. The standard Beggs and Brill correlation provided the best prediction considering all data combined. However, Dukler Case II correlation provided better prediction for the 6 in. pipes; and Beggs and Brill correlation was the best for the 8 in. and 10 in. pipes.
Role of Reservoir Simulation in Development and Management of Complexly - Faulted, Multiple - Reservoir Dulang Field, Offshore Malaysia : Holistic Strategies
Authors: Sonrexa Kartikay , Aziz Azly , Solomon G. J. , Bandai Malvinder , Embong Mond Khalid , Wahir Hashlm
Published: December 2007

The Dulang field, discovered in 1981, is a major oil field located offshore Malaysia in the Malay Basin. The Dulang Unit Area constitutes the central part of this exceedingly heterogeneous field. The Unit Area consists of 19 stacked shaly sandstone reservoirs which are divided into about 90 compartments with multiple fluid contacts owing to severe faulting. Current estimates put the Original-Oil-Li-Place (OOIP) in the neighbourhood of 700 million stock tank barrels (MMSTB). Production commenced in March 1991 and the current production is more than 50,000 barrels of oil per day (BOPD). In addition to other more conventional means, reservoir simulation has been employed from the very start as a vital component of the overall strategy to develop and manage this challenging field. More than 10 modelling studies have been completed by Petronas Carigali Sdn. Bhd. (Carigali) at various times during the short life of this field thus far. To add to that, Esso Production Malaysia Inc. (EPMI) has simultaneously conducted a number of independent studies. These studies have dealt with undersaturated compartments as well as those with small and large gas caps. They have paved the way for improved reservoir characterization, optimum development planning and prudent production practices. This paper discusses the modelling approaches and highlights the crucial role these studies have played on an ongoing basis in the development and management of the complexly - faulted, multi-reservoir Dulang Unit Area.
Improving the Performance of MARS Reservoir Simulator on Cray-2 Supercomputer
Authors: Li K. G. , Dogru A. H. , McDonald A. E. , Merchant A. R. , Al-Mulhem A. A. , Al-Ruwaili S. B. , Sobh N. A. , Al-Sunaidi H. A.
Published: December 2007

The computational efficiency of a reservoir simulator–MARS–that is heavily used in Saudi Aramco, was significantly enhanced by improving the vectorization, parallelization and a key algorithm of the simulator. In particular, a state-of-the-art parallel linear equation solver was developed and implemented in the simulator. This new solver ran three to five times faster than the existing solvers. With the new solver and the other improvements in the simulator, the optimized code ran 1.3 to 1.8 times faster than the original code on a single processor and more than four times faster on four processors of Cray-2 supercomputer for typical Saudi Aramco reservoir models. This translates into great savings for the company since it, in effect, creates additional computational resources at no additional cost and improves the reservoir engineer’s productivity by shortening the job turnaround time.
Platform Evaluation Of An Offshore Field
Authors: Huang K. L. , Saleri N. G. , Al-Khowaiter A. O.
Published: December 2007

A numerical study of an offshore field was performed to evaluate the relative performance of horizontal versus conventional wells, and various well completion/ placement/production scenarios for a six-well platform.

The results presented in this paper are found to be counterintuitive. While horizontal/high slant wells showed delayed gas and/or water breakthroughs, the overall platform performance remained largely insensitive to well configuration (horizontal versus conventional). Well placement, completion interval, and production strategy after breakthrough were identified to be the critical parameters in determining the performance of the platform. The study results favour conventional completions for this particular six-well platform.
New Completion Design for Step Horizontal Well
Authors: Kikuchi Shuichi , Al Mansoori Bader
Published: December 2007

In ADMA-OPCO, step-horizontal drilling technology, is often adopted i.e two horizontal sections in different sub layers inter-bedded by an impermeable barrier. For this kind of horizontal well, the following requirements in the completion phase as well as during the life of the well are to be taken into account -:a) Effective isolation between different sub layers to cope with future water breakthrough, b) Selective stimulation, c) Leaving several options for remedial workover operations, d) The capability to production log. With view of these, a specific completion for the step-horizontal well namely "dual External Casing Packers (ECPs) plus port collar system" has been successfully developed. This paper presents the design process and discusses equipment selection, running procedures and precautions required for this unique completion.
Oil Base Mud in High Pressure, High Temperature Wells
Authors: Soliman A. Abou
Published: December 2007

ADCO’s experience while drilling the sixth deep Khuff well with water base mud to total depth of 21682 ft and a bottom hole static temperature of 465°F has highlighted mud related problems. The mud has shown gelation, barite sagging, sensitivity to formation water influx and possible instability at densities higher than 122 pcf. These problems were considered in the selection criteria of the drilling fluid for the seventh deep Khuff well which required a drilling fluid density of 110–140 pcf with stable HTHP fluid loss at temperature up to 465°F, capable to tolerate influx of Co2, H2S, and high salinity formation water.

Studies on various oil & water base muds were performed in various laboratories including ADCO’s, the Shareholders’ and the mud companies’. The development of stable water base mud was not possible. Oil base mud formulation was developed and has been used.

The well has reached its total depth at 20085 ft & a bottom hole temperature of 440°F after facing operational challenges requiring mud weight of 155 pcf to control the well and during which, the OBM choice proved to be a success.
GOS Hook Type Wells, Directional Planning, Techniques Applied and Problems Encountered
Authors: A/Azim Mostafa , Fahmy H. , Salem A. , Mansour Sayed
Published: December 2007

This paper addresses the various aspects of hook type wells introduced and drilled within GUPCO operations during the last two years. The first well of this category was October-G10, drilled in October 1992 from October "G" platform to a target point in the Nubia formation. Several wells of the same type have been drilled through 1993 and 1994. This group includes October-Hl, Ramadan 3–57, July 62–69 and SB 374-3. Drilling hook type well profiles has resulted in increased production and more reserve recovery. The driving force behind using this profile was the reservoir requirements where it was required to hit a target within few meters at a certain angle and direction.

Torque and drag models have been used to optimize well path planning, resulting in lower torque and drag values. Daily post appraisal of the drilling operations to monitor hole cleaning effectiveness. Combination of advanced steerable systems and PDC bits enabled GUPCO to drill these wells cost effectively.
Drilling Operations in the Mediterranean Concessions: Challenges for Drilling Engineers and Rig Personnel
Authors: Hussein Nasr K. , Alsayed Nabih A. , Abu Seif Mohamed A. , Shalaby Shouhdy A.
Published: December 2007

Exploration offshore Mediterranean in Egypt is getting more and more important due to gas reserve discovered by ΓEOC in Port Fouad, Baltim and Temsah concessions. This paper will discuss some of the challenges required to drill safely and economically through the overpressurized sensitive shales of Nile Delta basin. It also summarises the problems encountered while drilling the very high pressure wells in Port Fouad and Temsah concessions, such as: hole instability, mud problems, water and gas kick, overpressure detection, lost of circulation, casing setting depth and related design, running and cementing operations, environmental pollution, safety and logistic problems.

Experience gained from the past and undergoing drilling operations in offshore Mediterranean is included in this paper and it could be a support for future exploration and development in the area.
Integrated Reservoir Modelling of a Major Arabian Carbonate Reservoir
Authors: Benkendorfer J. P. , Deutsch C. V. , LaCroix P. D. , Landis L. H. , Al-Askar Y. A. , Al-AbdulKarim A. A. , Cole J.
Published: December 2007

This paper presents the results of an integrated reservoir management study of a large carbonate reservoir. Geostatistical and scale averaging tools were used to develop detailed geologic models and a simulation window model. The geostatistical simulation techniques generated realistic models of lithology, porosity, and permeability. The public-domain GSLIB software, with some custom programs for data manipulation and interactive variogram modeling, allowed for the timely and efficient construction of a multi-million cell geological model. A two-step approach to permeability modeling was successful; it allowed the straightforward integration of core and well test data and provided improved geologic models for use in history matching in flow simulations. Because of the large number of cells in the geologic model, the porosity and permeability models were scaled up for use in the simulation model. A calibrated power-law average approach to scale-up was found to work well.

The geostatistical tools used in this study are applicable to both siliciclastic and carbonate reservoirs. The two-step approach to permeability prediction is applicable whenever a significant difference exists between core-based permeability measurements and production-scale permeability. The authors suggest that such an integrated approach to reservoir management is widely applicable and yields good results.

This paper presents an overview of the methodology and techniques used to develop the geologic and simulation models for the area being studied.
Utilization of Horizontal Drainholes in Developing Multilayered Reservoir
Authors: Siddiqui Tariq K. , Al Khatib Hassan M. , Sultan A. Junaid
Published: December 2007

Drilling deviated wells in the Upper Zakum field did not allow to develop this field to its full potential. It is an offshore field, only a limited number of platforms are available. Therefore, it may become uneconomical to drill a large number of deviated wells for the full development of the reservoirs. Application of horizontal wells in this field helped in redeveloping the reservoirs.

Data were integrated from different petroleum engineering disciplines and analyzed to identify problems in the reservoirs. Horizontal wells played a vital role to resolve various problems faced in different parts of these heterogeneous reservoirs.

This paper reviews the field development strategy which was further refined with time as more horizontal wells were drilled in this field. Performance of horizontal wells have been compared and evaluated with the deviated wells. A brief discussion on drilling, completion, and stimulation procedures used for horizontal wells has also been included.

This study contributed to some extent in resolving reservoir problems ranging from enhancement of productivity index, development of reservoir flanks, and recovering un-swept oil from water flooded layers with the applications of horizontal wells