bluuebunny/crossref_metadata_2025_split huggingface dataset:
Use of Environmentally Acceptable Invert Oil Emulsion Mud in SSB/SSPC
Authors: Hashim H. 
Published: December 2007

ABSTRACT
A five well trial with Environmentally Acceptable Invert Oil Emulsion Mud (EA-IOEM) has been carried out in the Balingian area offshore Sarawak during 1985 and 1986. The trial was initiated after an unsatisfactory outcome of a field test programme with KCl/polymer muds.
Two appraisal and three development wells with planned deviation angles ranging from 45 to 58° were selected. The trial was carried out in the 12¼" and 8½" hole sections.
The objectives of the trial were to eliminate drilling, evaluation and production problems caused by poor hole conditions which were experienced in high angle wells drilled with simple water based mud (WBM).
A suitable base-oil for the trial was selected to meet the following three criteria: a high flash point, a low kinematic viscosity and a low toxicity.
The experience gained in the field trial has been successfully applied to the Erb West infill drilling programme to solve the zonal isolation and drilling problems experienced in this area with WBM.
The paper addresses the operational, petrophysical and geological aspects of the trial and includes recommendations on cost and consumption estimating.
Underwater Work by Remotely Operated Vehicles (ROV's) Technology Development and Operational Experience
Authors: Batten C. J. 
Published: December 2007

ABSTRACT
This paper describes experience with respect to underwater work carried out by Remotely Operated Vehicles (ROV's) on the North West Shelf Development Project, North Rankin "A" field located 135km off the North West coast of Australia. The field is operated on behalf of the joint venturers by Woodside Offshore Petroleum Pty Ltd. Installation of the platform and trunkline was completed in 1982 and from this date all underwater work has been carried out by ROV. Typical work includes detailed pipeline and platform inspections, underwater support for the installation of gravity anchors and associated guy wires, general construction support, underwater cutting, marine fouling removal, scour protection installation and pipeline stabilisation.
Information presented in this paper is applicable to all phases of offshore oil and gas production that requires work to be done underwater e.g. exploration drilling, construction, operational inspection and maintenance. The paper describes special tooling procedures and systems developed to perform the above work. Also presented are new information and statistics associated with bulk marine fouling removal by purpose designed/bui1t remotely operated equipment.
The paper concludes that significant underwater work can be performed cost effectively without exposing men to risks associated with the underwater environment and shows that a much larger slice of the underwater work "pie" can be achieved by ROV than has previously been generally accepted.
Specific data related to time/costs associated with performance of significant aspects of the work are presented.
Reservoir Water Control Treatments Using a Non-Polymer Gelling System
Authors: Chan K. S. 
Published: December 2007

ABSTRACT
A new non-polymer in-situ gelling system has been developed for reservoir water control treatments. This paper includes the results of a series of key laboratory tests in characterizing this system for practical well treatment designs.
The system comprises two to three chemicals which are readily soluble in most field mix waters and seawater. The fluid has a low viscosity close to that of the water, and can be pumped at any rate. The treatment is a simple single slug injection process using ordinary field mixing and injection equipment. In the rock formations, the injected fluid system forms a semi-solid gel which will transform into a solid phase after a time period. Typically, the treated formation permeability reduction is 50 folds or 98%.
The microscopic pore blocking efficiency as tested by core flow experiments can be correlated with the gel strength which is expressed in term of gel extrusion pressure gradient (psi/ft) as measured by a core plug test. This enables the treatment fluid penetration requirement calculations using the near wellbore pressure gradient values during the production or injection as input data instead of a blind assumption on a certain radial penetration.
Excellent fluid flow selectivity in the water-out layer has also been demonstrated by many laboratory bi-core flow experiments modelling a typical two-layer reservoir.
The Progressing Cavity Pump in Europe: Results and New Developments
Authors: Gaymard B. , Chanton E. , Puyo P. 
Published: December 2007

ABSTRACT
The first part of this paper is a reminder of the principle and the design of the Progressing Cavity Pump. It recalls the Moineau principle on which the pump works, describes the various parameters which define the pump and determine its performances. It shows the configuration used for oil production and indicates the range of practical performance that can be expected.
The second part describes the results of three years of operations in Europe. It states the practical characteristics and advantages of the Progressing Cavity Pump as they have been observed and sometimes suggested by various users.
The third part deals with two recently developed pump models which broaden significantly the area of operation of the Progressing Cavity Pump:
– The first one is a large capacity pump for high productivity and/or high water cut wells. – The second one is a high pressure pump for the production of high viscosity crude.
The presentation of the high pressure pump includes a discussion of the effects of high viscosity on the pump operation and of the solutions offered to optimize this operation.
Residual Oil Saturations Determined by Core Analysis
Authors: Kennaird T. 
Published: December 2007

ABSTRACT
Residual oil saturation determined by several laboratory techniques on core plug specimens from a variety of lithologies in the Asia-Pacific region have been correlated to porosity, initial water saturation and permeability. To some extent, residual oil decreased with increasing initial water saturation and decreasing permeability. For the same mean hydraulic radius Kϕ residual oil left after gas-drive was much higher than that for a water-drive. On the average, residual oil saturation from steady-state water-oil relative permeability data were higher than those from the unsteady-state floods. This is an apparent reflection of the fact that steady-state floods are typically conducted at lower flow-rates than unsteady-state floods.
A Computer Aided Reservoir Engineering (CARE) System: From XY Plots to 3D Animations
Authors: Matsumoto M. 
Published: December 2007

ABSTRACT
An advanced graphic post-processing system has been developed. The principal feature of this system is an three-dimensional(3D) expression of the whole reservoir phenomena as engineering animations. This system can show the distribution of parameters of the reservoir simulations by forming colored-transparent iso-value surfaces in the 30 space and the dynamic changes of the parameters by moving the surfaces smoothly with interpolation of the data between calculated time steps. Furthermore, it can create a contour map on an arbitrary cross section of the reservoir. The system is applicable to presentation and instruction as well as to result evaluation.
Waterflood Development of the Guntong and Tabu Fields
Authors: Hui S. K. , Pillai H. 
Published: December 2007

ABSTRACT
Two oil fields which are characterized by weak natural pressure support and unfavorable rock properties were planned for waterflooding by Esso Production Malaysia, Incorporated. This paper documents the collection and analysis of data for selection of an optimum waterflood pattern. Included will be discussions on parameters that affect short and long term water injectivity, extensive use of numerical models to compare alternate waterflood patterns, on-site production/injectivity. tests to validate predictions and injectivity enhancement methods. With a going-in development plan for an inverted 7-spot waterflood pattern, the final optimum plan was assessed to be a combination of 5-spot and peripheral injection.
Infill Development in an Old Field
Authors: New K. T. C. , Slik P. , Tan B. C. 
Published: December 2007

ABSTRACT
The Seria field, onshore Negara Brunei Darussalam on Che North Western coastline of Borneo, South East Asia, has been in production since 1930 and up to now some 34% of STOIIP has been produced by 760 wells.Ultimate Recovery, estimated from extrapolation of performance is 39% of STOIIP.
This paper outlines the approach followed in planning of infill drilling and presents recent experience for the Seria West (SW) block and three other blocks of field.
Infill drilling overall is expected to increase the ultimate recovery of the Seria field to 43% of STOIIP.
Enhanced Oil Recovery in Malaysia
Authors: Yassin A. A. M. 
Published: December 2007

ABSTRACT
Whilst the incremental oil potentially recoverable by the application of enhanced oil recovery (EOR) processes can only be reliably estimated by a detailed study of each reservoir, in order to provide an early guide to the scope for EOR in Malaysia, a preliminary survey has been carried out. The approach in this preliminary survey was to develop a set of screening criteria for the various processes being developed and to use these criteria to identify possible candidate reservoirs. The potential for incremental oil recovery was then determined by applying factors obtained from the assessment studies referred to above or from published sources.
The review of EOR potential within Malaysia has suggested that only a small number of reservoirs are unsuitable for EOR and there is substantial scope for increasing the yield from known light oil and gas condensate reservoirs. The possible contribution that could be made by individual processes is fairly evenly distributed between polymer floods, surfactants, carbon dioxide and nitrogen or hydrocarbon gas.
The enforcement of strict conservation measures and depletion control had change the development strategy by integrating EOR into conventional method of production with an early implementation of EOR in order to maintain the viability of EOR projects.
Effectiveness of Enhanced Safety Management
Authors: Waterfall K. W. 
Published: December 2007

Abstract
Sarawak Shell Berhad (SSB) and Sabah Shell Petroleum Company (SSPC) are oil and gas exploration and production Companies working under a Production Sharing Contract (PSC) for PETRONAS. They operate or control the activities of Drilling-Rigs, Barges, vessels and approximately 100 Production Facilities offshore Sarawak and Sabah. Additionally they operate three onshore oil and gas terminals to treat the products prior to export.
Current production levels are in the order of 200,000 bbl/day of oil and 1000 million scf/day of gas. The Company employs some 3,000 Company personnel and approximately 2,600 contractor employees. With this spread of activities and this number of people there are many areas and operations being conducted on a daily basis which have the potential for accidents to occur. Whilst the programme and procedures stated in this paper are generally applicable throughout the Shell Group the references to Shell should be construed in this context as being relevant to SSB/SSPC activities only.
Shell has always been conscious of the need for improved safety and reduction of the risk of accidents throughout its operations and in 1984 it embarked on an intensive campaign of Enhanced Safety Management (ESM), which is modelled on the approach taken by Du Pont Organisation. Du Pont are the world renowned leaders in Safety Management and extensive use was made of their Safety Consultancy Division to establish Shell's ESM Programme. This programme has brought about a major improvement in Safety performance which is both sustainable and ongoing. Experience has shown that we can summarize the essentials of ESM to be.
Corporate Safety's Responsibilities and Duties to Petronas Offshore Facilities
Authors: Coleman H. R. , Salleh I. A. N. 
Published: December 2007

ABSTRACT
In July 1986 PETRONAS approved establishment of a Corporate Safety Group with responsibilities for:
Initiating development of safety policies, procedures and guidelines. Implementing and monitoring same. Acting as official spokesman and liaison with Public and Third Parties.
Corporate Safety's area of responsibility is total. That is, safety must begin with design at the conceptual stage, including: developing design specifications and standards, participation in construction and in acceptance inspections, in operations by participating in the development of operating procedures for personnel safety and in the development of guidelines on safety matters related to Inspection and Maintenance. This paper will highlight the areas of Corporate Safety's involvement and support them with appropriate and logical reasons.
Development Planning of the F6 Gas Field in Central Luconia, Offshore Sarawak, Malaysia
Authors: Wee P. Y. , Liew S. L. 
Published: December 2007

ABSTRACT
Development of the Central Luconia gas fields, located offshore Sarawak, started in 1982. To date three gas fields have been developed, Ell, F23 and the third and largest gas field, F6, which came on stream in January 1987. The daily production rate averages some 1000 MMscf/d.
The gas is delivered via a single 36" trunkline from Ell to the Malaysian LNG liquefaction plant for the manufacture of LNG at approximately 6 million tonnes per year for a period of 20 years. Gas is also distributed to the ASEAN Bintulu Fertilisation plant for the production of urea and ammonia, and to Sarawak Electricity Supply Corporation for power generation.
This paper describes the 3D simulation study that has been carried out for the F6 field which forms the basis for the development planning of the field. The plan proposed a total of ten producer and one observation well to be drilled from the drilling platform F6DP-A located near the crestal part of the field.
Despite the large reservoir areal extent of about 168 km2, it is expected that the field can be adequately drained from a single platform with ten producers.
The main uncertainties which may affect the field performance are the transmissibility of a tight argillaceous layer which may separate the gas bearing part of the field into two zones and the possibility of water drive. The likely impact of these uncertainties on the development plan and gas recovery has been addressed in the simulation study.
Taking the above uncertainties into consideration, recovery factors are estimated to be between 61% and 75%.
Jerneh Gas Field Development Planning
Authors: Thambydurai R. , Mustapha A. F. , Mueller K. H. , Dixon M. R. 
Published: December 2007

ABSTRACT
This paper is a review of the field development plan for the Jerneh gas field, located offshore east of Peninsular Malaysia. The major design steps in the development process are discussed which include gathering of required geological and reservoir data from delineation wells and subsequent studies to evaluate reservoir performance, production and processing facilities. The result of these studies is a development plan which incorporates forty wells and two producing platforms.
Condensate Production Optimization in the Arun Gas Field
Authors: Risan R. M. , Abdullah S. , Hidayat Z. 
Published: December 2007

ABSTRACT
In the Arun Field, Mobil Oil Indonesia Inc. (MOI) has implemented a condensate production optimization program on its Supervisory Control and Data Acquisition (SCADA) system. This program has been proven successful in improving stabilized condensate production by up to 3% or 3200 BPD at 2,270 MMSCF daily average separator gas flowrate.
The Variable-Rate Reservoir Limits Testing of Gas Wells
Authors: Blasingame T. A. , Lee W. J. 
Published: December 2007

ABSTRACT
This paper presents a new method of estimating drainage area size and shape from production data (bottomhole pressures and flowrates) for gas wells. This method is rigorously based on theory presented earlier for the slightly compressible liquid case and requires a computer program to iterate on gas-in-place until the gas flow and material balance equations are satisfied.
The component equations and analysis technique are strictly applicable only after the initial pressure transient has reached the outer boundary. The gas flow equation that we present is an approximation for variable-rate, post-transient flow, but it has provided excellent results for all of the cases investigated. These results imply, as was also noted for the liquid case, that as long as the changes in flowrate do not dominate the influence of the outer boundary, this method should give acceptable results. Currently, this method is only derived for single-phase gas flow and does not consider the effects of geopressured gas reservoirs or non-darcy flow.
Nitrogen as a Low-Cost Replacement for Natural Gas Reinjection Offshore
Authors: Hanssen J. E. 
Published: December 2007

ABSTRACT
As part of R&D efforts to evaluate nitrogen for pressure maintenance and EOR offshore Northern Europe, nitrogen miscibility with selected reservoir fluids as well as its diffusion properties have been investigated and compared to those of natural gas. Custom-built equipment includes slim-tube and cell-to-cell miscibility apparatus and a diffusion apparatus, all operating at typical reservoir conditions. Measured minimum miscibility pressures (MMP's) range from 32 to 55 MPa [4600 to 8000 psi]. With near-critical volatile oils from one reservoir, both nitrogen and methane were found to develop miscibility at saturation pressure. This apparently is the first such case known for nitrogen, and the lowest MMP value reported for nitrogen with a North Sea fluid. For another North Sea reservoir fluid, MMP was found to depend strongly on the amount of intermediates in the oil, and a significantly higher MMP measured for nitrogen than for methane. The new data were used to improve a previous MMP correlation for vaporizing gas drives. Predictions by this correlation indicate possible nitrogen miscibility with several North Sea reservoir fluids. Hitherto unavailable diffusivity measurements for the nitrogen-methane binary have been performed at reservoir conditions. Results indicate that serious errors in diffusivity may be introduced if lower-pressure data are used to extrapolate to reservoir conditions.
To complement the experimental work, a critical review of previous onshore nitrogen field application and various offshore process suggestions has been performed, in the perspective of nitrogen replacing produced-gas reinjection.
Use of Boundary Element Methods for Stochastic Optimisation of Gas Field Deliverability
Authors: Wadsley A. W. , Ferguson W. I. 
Published: December 2007

ABSTRACT
Optimum gas delivery contracts are those which maximise gas production whilst minimising penalties caused by insufficient well capacity to meet contracted demand. The method of stochastic simulation is described for predicting seasonal and daily gas demand together with techniques derived from the boundary element method for the modelling of reservoir deliverability performance. These two methodolgies are combined to give a robust procedure for the nomination of contractual gas delivery quantities.
Breakdown Procedures Designed to Minimize Naturally Fractured Reservoir Damage
Authors: Branagan P. T. , Wilmer R. H. 
Published: December 2007

ABSTRACT
Damage to natural fractures have been found to occur as a result of conventional completion techniques previously employed at the DOE Multiwell Experimental (MWX) Site. In an attempt to understand some of the damage mechanisms and find mitigating techniques that could be practically employed, a series of rather unconventional completion procedures were performed. These procedures were designed to utilize gases rather than aqueous-based fluids during the perforating and breakdown/ microfracturing process and were performed in several differing reservoirs. Previous tests at the MWX underscored the impairment to natural fracture flow capacity that resulted from liquid invasion during perforating, breakdowns or large scale stimulation. Thus, the use of gases during the initial connection into the naturally fractured reservoirs at the MWX was considered a natural starting point.
The completion techniques that were tested and that will be discussed employed nitrogen, N2, during dry hole perforating; as a fracturing fluid during simultaneous perforating and fracturing; and in an impulse remedial treatment. A test of a tailored pulse explosive technique provided useful operational information but inadequate wellbore preparation compromised an assessment of its effectiveness to create a multiple fracture set. The application of these unconventional techniques provided a very useful and unique set of test data and proved to be sufficiently effective in permitting the engineers to acquire positive pressure interference data during a subsequent well test.
Pre-Frac Interference Testing of a Naturally Fractured, Tight Fluvial Reservoir
Authors: Branagan P. T. , Lee S. J. , Cipolla C. L , Wilmer R. H. 
Published: December 2007

ABSTRACT
The data, analysis and simulation resulting from a three-well interference test performed in a tight, lenticular naturally fractured reservoir at the Department of Energy (DOE) Multiwell Experimental (MWX) site, near Rifle, Colorado,1 will be discussed. The test data, that includes bottomhole pressure measurements from a production well and two closely spaced observation wells, provides considerable evidence that reservoir gas production was dominated by flow through a layered, anisotropic naturally fractured system. The interference testing consisted of almost two months of continuous data acquisition that included the introduction of several pressure pulses from the production well and the subsequent observation of those reservoir pressure transients at the remote well locations.
A series of novel completion schemes using high pressure nitrogen gas and explosive fracturing were employed in the completion process of all three wells. The primary intent was to eliminate foreign liquids from entering the reservoir fracture system following perforation in order to minimize external intervention in the natural production process.
When wellbore storage effects were considered to negatively impact the data set, bottomhole shut-in tools were employed and virtually eliminated storage volume. Both observation wells made use of these shut-in tools throughout the entire test yielding an unobstructed pressure interference data set.
Infill Drilling Using Horizontal Wells: A Field Development Strategy for Tight Fractured Formations
Authors: Mercer J. C. , Pratt H. R. , Yost A. B. 
Published: December 2007

ABSTRACT
Gas production for a 10-year period was simulated for 16 vertical shot wells located in a 2,066-acre (8.36 × 106m2) area containing seven active vertical wells. The performance of several horizontal wells was simulated and the results were compared with that of the 16 vertical wells. Finally, the horizontal and vertical wells were compared to determine the best method for developing a virgin reservoir. As few as four unstimulated 2,000 ft (610 m) horizontal wells were found to produce 1.5 times as much gas as 16 vertical shot wells, and only two hydraulically fractured horizontal wells were needed to almost match the production of the four unstimulated horizontal wells. In a virgin reservoir, four unstimulated horizontal wells accounted for 95 percent of the total production from 23 vertical wells.