bluuebunny/crossref_metadata_2025_split huggingface dataset:
Solid Expandable Tubulars Slim Well Design and Isolate Zones for Brownfield Redevelopment in Oman
Authors: Morrison W. , Sanders T. , Leuranguer C. 
Published: December 2007

Abstract
The Fahud water flood project is a major brownfield redevelopment project and a key component to PDO's future production plan. Key value drivers for the successful project delivery are selecting the right recovery mechanisms for the target reservoirs and achieving low-cost well delivery through standardization and technological innovations.
The pilot program, which consists of drilling 39 vertical wells in PDO's Fahud field, commenced in April 2004 to gather data on four Natih target reservoirs. The data will be used to identify applicable recovery mechanisms for future field development. The recovery methods under review include the following: Water floodGas-oil gravity drainage (GOGD)Combination GOGD and water floodCombination GOGD and depletionCombination GOGD and gas flood
Natih is a stacked layered reservoir. Natih A and C were developed by water floods in 1972–1980. These wells were unsuccessful due to early water breakthrough through fractures and karst parts of the reservoir. From 1984 to 1998 certain reservoir sections were developed by GOGD with 200+ development wells drilled. Since 1997, water flooding has been used to produce different zones in the Natih reservoir. Most of the drilling during this time consisted of horizontal wells with single or dual laterals.
Although horizontal wells, in particular dual-lateral wells, provide excellent area data coverage, they also Provide ambiguous production data from single zones.Do not allow observation of reservoir behaviour in over-and underlying zones.Are costly to enter (hoist/coiled tubing).Present a challenge to manage flow profiles.
These issues led to the consideration of implementing alternative well designs.
This paper will discuss the well planning, wellbore preparation and successful application of solid expandable tubular technology. These systems, combined with swelling elastomers, slim the well design and provide reliable isolation of the Natih sub-units to allow independent testing of the zones. The paper also presents the completion design planned for the test program and long term production.
Recent Material and Geometrical Changes in Impreg Technology on Turbine Drive Lead to Reduced Drilling Costs in Hard Rock Application
Authors: Heywood C. , Currie A. , Robson D. , Casey P. 
Published: December 2007

Abstract
Oman's principal LNG producer is Petroleum Development Oman and their largest producing field is the Saih Rawl Field. Rigs are currently drilling in the reservoir section on the Saih Rawl Field as part the development activity on this field. The Saih Rawl Field is an important producer of the Sultanate of Oman's gas reserves. These deep gas wells have an average TD of 5000m. The reservoir zones are in Barik and Miqrat sandstones at 4500 and 4900m TVD, respectively.
The formations in the 8-3/8" section are made up of sandstone, siltstone, shale and dolomite. The Barik, Al Bashair, Miqrat and Amin formations in the 8-3/8" section are extremely hard (up to 30,000 psi unconfined compressive strength - UCCS) and abrasive. These difficult formations have traditionally been drilled with a mixture of roller cone and turbine driven impregnated diamond bits. The roller cone bits deployed in the past lacked durability. The initial impregnated bits faced ROP, durability and float equipment drill-out challenges.
Six years of material research, development, and testing on impregnated bit materials has culminated in a 260% increase in durability and a 5% increase in ROP in these formations during the past year using innovative new impregnated diamond bit designs. In addition new cutting structures and innovative bit head geometries for drill out of float equipment have allowed consistent successful drill out of the 9-5/8" shoe track displacing the use of rock bits in this application. Together these advances have reduced the time taken to drill the 8 3/8" section by an average of 10 days. This has results in an average cost saving of $430,000USD in time and materials in the 8 3/8" section. These performance advances have contributed significantly to the reduction in average well drilling time from 90 days in 2004 to 68 days in 2005.
These developments in impregnated bit technology have been extended to applications in Saudi Arabia, Algeria, Syria and Venezuela.
Application of a Light Rig in Deep Exploration Drilling Operations in Nigeria
Authors: Okwa H. , Azoom I. , Omini E. 
Published: December 2007

Abstract
The upsurge in drilling activities in 2004, occasioned by the strong oil prices resulted in a challenging rig market situation such that operators have to plan well in advance to be able to get a rig for the next well campaign. For desperate operators, the only option is innovation or new technology and unusual risk taking.
An operator in Nigeria recently adapted a light work over rig of 800 horsepower and 320,000lbs pulling capacity to drill an exploration to 11,000 ft. This was operating the rig at beyond its capacity.
Minor modifications were made to the rig to enable the running of casing strings, and operations monitored with the help of wells software, resulting in the successful drilling and abandonment of the A-1x well. The result was a 30% savings of the budget well cost contributed mainly from the slimmer design and lower rig rates of the light 800 hp rig. It is also noted that the light rig was moved in 8 days compared to 23 days planned with the heavier rig.
The paper highlights the detailed planning and execution of the drilling phase of the A-1x well and how the capacity issues were addressed leading to the estimated savings of $2million.
Gas Injection Programs in PERTAMINA West Java to Obtain Better Recovery: Field Screening, Laboratory and a Simulation Study
Authors: Gunadi B. , Suarana I. P. , Marhaendrajana T. 
Published: December 2007

Abstract
Most of oil fields managed by PT PERTAMINA (PERSERO) are considered as brownfields and the oil produced only from primary recovery stage. To get better recovery of oil in those brown fields, it is necessary to have a long term project such as Enhanced Oil Recovery (EOR). Some screening criteria had been completed to select appropriate method which could be applied in certain field. In this study, we present gas injection program in West Java to obtain better recovery of the mature field/brownfield. The gas injection program include natural gas such as ethane, propane and CO2 flooding.
The viability relates mainly to the availability of CO2, the structure complexity, and finally the achievement of the Minimum Miscible Pressure (MMP). In the Jatibarang Field, it is not an issue of gas and CO2 availability since gas and CO2 sources are available in the field itself, and near by fields.
The Jatibarang Field primary recovery is only 16.2%, and the current reservoir pressure is as low as 500 psia. The reservoir performance shows the driving mechanism in this zone is very weak water influx. Therefore a Waterflood and/or EOR Program need to be evaluated to increase oil recovery.
Based on the screening criteria for oil fields in West Java, there are several possible CO2 flood candidates, one of which is the Jatibarang Field. A fluid compatibility test was conducted using Jatibarang Field fluids, from current to initial conditions. The fluid properties of current and initial conditions were compared and analyzed using numerical simulation. Then an appropriate fluid model was selected to represent the reservoir conditions. Regression and fine-tuning of the equation of state resulted in the fluid characterization for this study. Tuning of the EOS should give a fluid model that closely matches the lab test results.
Reservoir pressure is very important when it comes to designing gas and CO2 floods, as it is usually far below the MMP, as was the case in the Jatibarang Field. Based on the fine tuned fluid model, several gas and CO2 processes (immiscible and miscible flooding) were evaluated for the Jatibarang Field. These also included evaluation of different compositions of the natural gas and CO2 gas.
The best tuning of EOS will give the fluid model that closely matches the lab test results. and then the fluid is applied to the compositional reservoir simulation. More than 25 alternatives of gas injection is studied using the compositional simulation. The best recovery is combination of water injection, CO2, ethane and propane flooding (% incremental oil recovery).
World's First MRC Window Exits Out of Solid Expandable Open-hole Liner in the Shaybah Field, Saudi Arabia
Authors: Al-Jeffre A. M. , Al-Dossary A. S. , Zhou S. , Al-Hajji A. A. , Al-Khanferi N. M. , Al-Jaafari S. M. 
Published: December 2007

Abstract
A well in the Shaybah Field was recently worked over by converting the existing 1-km horizontal section to MRC (maximum reservoir contact) well with a total reservoir contact of 18,443 ft. The objectives of the workover program were to improve well productivity by maximizing the reservoir contact as well as to install solid expandable liner as a conduit for downhole flow control system in the future.
The original horizontal section was first extended by 6,462 ft, before running expandable liner. Installing a 1,008 ft 5–1/2" expandable liner in near horizontal section encountered considerable difficulties in this well, first with liner stuck, then experiencing stuck expansion cone during the final stage of liner expansion. After these problems were finally overcome, top of expanded liner was successfully pressure tested. Two laterals were sidetracked successfully out of the expandable liner (Lateral - 1 = 4,615 ft and Lateral - 2 = 7,366 ft) to access additional flow contribution from the reservoir.
This paper describes the experiences and lessons learned from hole preparation, running and expanding expandable liner, window exits of expandable liner, and subsequently drilling two 5–1/2" laterals.
Reservoir Evaluation Program Planning in HPHT Environments
Authors: Guillory C. M. 
Published: December 2007

Abstract
Reservoir evaluation is a significant challenge in the HPHT environment. With current technology, the ability to assess rock and fluid properties is very limited. Utilization of an assortment of MWD, wireline, geochemical, and gas logging technologies is necessary when attempting to fully assess reservoir properties. All of these evaluation tools have significant limitations and proper well and evaluation program design and planning is critical. Success is often dependent on making several measurements and having contingency plans developed in the planning stage of the evaluation program. Actual HPHT well evaluation planning and execution examples, as well as, current tool limitations and future technology requirements are reviewed.
Review of the Recent API PRAC Project Attempt to Evaluate the ISO DIS 10400 Failure Assessment Diagram Through Full Scale Testing of Pipe Containing Surface Imperfections
Authors: Moore P. W. , Prideco Grant , Maldonado J. G. 
Published: December 2007

Abstract
On going work by ISO TC67 SC5 Workgroup 2b to modernize the performance property equations of ISO 10400 / API 5C3 identified the need to begin research in an attempt to validate the Failure Assessment Diagram equations that incorporate variables of environment and retained surface imperfections in tubulars. A detailed research project proposal was drafted and submitted to the American Petroleum Institute (API) for consideration in their 2002 research budget. API approved and launched the research project which assembled the materials and conducted tests for two and a half years. Tubular manufacturers donated tubes, processing, inspection, and premium threaded end-caps, which greatly leveraged the API research funding. A consortium of Oil company operators, a metallurgical laboratory and tubular manufacturers donated post-fracture laboratory analysis of test samples that failed in an H2S environment in order to further enhance the understanding of the failure mechanisms. This paper identifies why the attempt to validate the environmental fracture equations for sour environments failed, one area where the project was successful, and enumerates the reasons why this type of research is recommended.
Improving Completion Viability in HPHT Completions
Authors: Carter T. S. 
Published: December 2007

Abstract
Environment – Assisted Cracking (EAC), also referred to as stress corrosion cracking, is a growing problem for oil and gas producers given the increased incidence of drilling in HPHT areas. It is a complex issue that is attributable to the interaction of sensitive, stainless steel metallurgy under applied or residual stress, with the various clear brine packer fluids used in today's critical completions. Applications of standard corrosion tests and experiments have generated very few of the answers needed to help producers predict how various combinations of tubular metallurgies and fluids will perform together in the well. Much more specific empirical data is needed to understand the mechanisms causing these failures, and how they can be avoided.
In an effort to find the difficult answers, two leading manufacturers of martensitic stainless steel tubulars, and clear brine fluids JFE and TETRA, have joined their technical resources to scientifically examine the phenomena of stress corrosion cracking. The technical alliance, which is called the ChemiMetallurgy™ research program, has developed an accelerated EAC test methodology that replicates known tubular failures that have occurred in the field over the past few years. Lessons learned have permitted extensive testing of multiple combinations of metallurgies and packer fluids to determine their interactions under actual well conditions.
By early in 2005, the testing protocol will have conducted more than 3000 tests gauging the interactions of more than 16 fluid combinations with 6 different chrome tubulars. These tests are being run under high stress, varying temperatures, with the additives, gases, and typical formation fluids that would be found in a well.
The testing to date has delivered some interesting surprises. Of special relevance is the importance of subtle differences in fluid and metal composition upon their susceptibility to EAC. Indications are clear: small differences can promote significant cracking consequences.
Results of these studies matching fluid with metallurgy not only minimize the risk of failure in the field, but also provide compelling economic benefits. Given a choice of several equidensity fluids that have been tested to be EAC compatible with specific tubulars, a fluid can be selected for use based on lower cost and/or other performance considerations.
Thermal Management of Closed Volume Spaces in Subsea Production Equipment
Authors: Beall Scott , McMillan Chris , Reinås Lorents 
Published: December 2007

Abstract
The design of Subsea production equipment for HPHT (15,000 psi / 350 °F) well applications require that HSE design consideration be given towards the management of closed volume spaces of incompressible fluids. A comprehensive thermal analysis of the tree system indicated that several areas could have the potential for pressure build up beyond the design rating of the equipment. For the area of greatest concern, a passive safety device was designed that provides overpressure protection in the event of an unplanned pressure build up.
This paper will discuss the methodology of the management of pressure build up in closed volume spaces due to thermal increases, with particular emphasis on the passive safety device used in the Christmas tree system for the Statoil operated Kristin field in the Norwegian North sea
Shell Exploration and Production Company List of Connections Tested for Well Service Pressures &gt;8000 psi Based on Standardized API/ISO Qualification Testing Procedures
Authors: Valigura Gloria A. , Cernocky Paul 
Published: December 2007

Abstract
Shell Exploration and Production Company (SEPCo) has spent millions of dollars since 1980 to qualify connections for well service pressure greater than 8,000 psi internal differential pressure. Prior to 1998, API RP 5C5(1) was used to qualify connections. Since 1998, SEPCo has been qualifying connections consistent with ISO 13679:2002(2).
These connections have been qualified by testing, by product line qualification, or through extrapolation/interpolation from fully tested connections. In light of the potential for corrosion on metallic surfaces or handling damage, SEPCo requires that the connections for wells above 8,000 psi have two different types of sealing mechanisms: a metal seal and an independent resilient seal. Qualification and usage of tested connections with two proven seals has resulted in only four connection issues in wells (all attributed to incorrect rig make-up) over the last 20 years.
The actual connection test data are the property of the thread design company. For details of any of the test protocols and results, the appropriate thread design company should be contacted.
Rejuvenation of a Mature Oilfield Involving Polymer Flooding by Successful Tapping of Undrained/Unswept Oil: A Case Study
Authors: Yomdo S. , Talukdar B. N. 
Published: December 2007

Abstract
Zaloni Barail Second Sand (Well 27 Block) reservoir in Zaloni oilfield was discovered in 1957. For pressure maintenance, peripheral water injection was initiated by injecting water into the acquifer in 1973. Polymer flood project was undertaken in this reservoir in December 1975, which was a relatively new concept at that point of time, especially taking into account the depth of occurance (around 2650 metres) of hydrocarbon accumulation.
The current recovery from the reservoir is estimated to be around 42% of oil originally-in-place. In order to increase ultimate oil recovery, comprehemsive multi-disciplinary integrated studies were carried out in 2003 to re-define opportunities. Subsequently, an infill well drilled in this reservoir in July 2004 produced around 45 m3/day almost clean oil. Positive result obtained from the successful tapping of undrained / unswept oil in the reservoir, thus extending its producing life, has encouraged drilling of additional infill wells not only in this reservoir, but also in select undrained areas nearby.
Dykstra Parsons Water Flood Theory Adapted to Chemical Flood Modelling
Authors: Morrison G. R. 
Published: December 2007

Abstract
The method of Dykstra-Parsons, originally developed to model water flood performance, has been adapted to screen reservoirs for their Chemical / Polymer Flood suitability. Firstly, this paper summarises Dykstra-Parsons’ Theory alongside an automated method of tuning reservoir layer properties to [pre-chemical] water flood performance. (Methods of determining both layer permeability and oil-phase relative permeability end-points, from water-cut development, are presented.) Secondly, this paper describes the adaptation of Dykstra-Parsons’ Water Flood theory to model both chemical flood and post-chemical flood production performance. Permeability adjustment, mobility control, and alkaline-surfactant flood models are discussed.
Cross-SAGD (XSAGD)—An Accelerated Bitumen Recovery Alternative
Authors: Stalder J. L. 
Published: December 2007

Abstract
Steam Assisted Gravity Drainage (SAGD)1 has become the preferred in-situ recovery concept for Athabasca bitumen. However, to maintain steam-trap control, rates are limited by the close vertical spacing between the parallel horizontal wells. In Cross-SAGD (XSAGD) the injection wells are perpendicular to the producing wells. Sections of the wells near the crossing points are either restricted from the start, or are later plugged, to achieve a significant rate and thermal efficiency advantage over SAGD, especially in cases where low pressure is required.
Health, Safety and Environmental Risk Mitigation for a Thermal Oil Recovery pilot Facility in Trinidad
Authors: Khan F. , Sinanan B. , Jokhoo R. , Innis F. , Ramlogan V. 
Published: December 2007

Abstract
Enhanced Oil Recovery projects are strategic investment initiatives planned when oil prices are high enough to support economic profitability. The Upper Morne L'Enfer (UMLE) pilot thermal project, within the Forest Reserve oilfield in Trinidad, is the current thermal EOR activity. Within the last ten years, health, safety and environment laws and regulations have evolved and are now more stringently applied and practiced. The Forest Reserve field houses many sensitive forested environments. The surface operations include clearing and construction of a site for fluid storage, testing and the generator.
During the project-planning phase, an Environmental Impact Statement (EIA) and a Hazard Operability (HAZOP) Study were conducted to acquire Environmental Management Authority and Ministry of Energy and Energy Industry approvals and address potential safety and environmental risks associated with the project. Baseline data was extracted from an Environmental Impact Assessment that was recently conducted for drilling sixty wells in the same area.
Integrating the environmental baseline into the HAZOP study served to identify and rank both potential environmental and safety hazards, which in turn permitted Petrotrin to prioritize risk mitigation strategies. All parties involved in the risk assessments agreed that the team approach used in the HAZOP study permitted a more efficient and effective forum to identify and mitigate both safety and environmental risks as compared to combining results from individual assessments.
This paper describes how the project's potential safety and environmental risks were assessed and mitigated. The success in minimizing the risk associated with these hazards serves to demonstrate that oil and gas operations can coexist with sensitive environments.
Cyclic Mechanical and Fatigue Properties for OCTG Materials
Authors: Kaiser T. M. V. , Yung V. Y. B. , Bacon R. M. 
Published: December 2007

Abstract
Much of the design basis for well structures subjected to high amplitude cyclic loading is based on material assumptions that extrapolate strength properties from uniaxial, monotonic tests to conditions where cyclic, multiaxial stresses are imposed. This paper shows results from cyclic testing on common Oil Country Tubular Goods (OCTG) materials and demonstrates the difference between physical behavior measured under cyclic loading conditions and theoretical behavior extrapolated by numerical modeling of uniaxial, unidirectional test data. Modeling theories for plastic deformation are discussed, along with their limitations and relevance in a cyclic loading environment. The implications of these limitations for design choices in thermal wells also are discussed.
Fatigue properties for the high-amplitude, low cycle application of thermal operations have not previously been investigated in much depth, in particular for OCTG. Along with characterizing cyclic mechanical properties, the tests discussed here also were used to assess the low-cycle fatigue properties of steel commonly used for in thermal well casings. Consistent fatigue results were produced, which, applied in the context of analysis results using representative cyclic mechanical properties, provide a basis for estimating fatigue life for specific cyclic deformations. Depending on scenario assumptions, substantial statistical variation in fatigue life can be expected, so exact fatigue life predictions are not anticipated. The primary value in such modeling capability is the assessment of mitigation options for extending well life when casing deformations are indicated.
The paper also discusses some practical implications of the difference between actual material behavior and idealizations used for modeling purposes. An example application of the cyclic material behavior and fatigue life prediction is also included.