bluuebunny/crossref_metadata_2025_split huggingface dataset:
Managing Offshore Process Plant Integrity
Authors: Edmondson J. N. , Findlay K. 
Published: December 2007

Abstract
Loss of hydrocarbon containment accidents present the greatest threat to the offshore workforce. Hence it is imperative that the highest standards are maintained with respect to the design and operation of offshore process plant. The Offshore Safety Division (OSD) of the UK Health and Safety Executive, the British health and safety regulatory body, has undertaken a series of theme audits examining the management of offshore hydrocarbon production facilities. The focus for the audits was the adequacy of the safety management systems in place to control hydrocarbon containment and included both design and operational aspects. The paper discusses the principal findings from the audits and describes actions required to further improve process plant integrity management over the lifecycle of an offshore installation.
Crew Resource Management for Offshore Production and Maintenance
Authors: Flin R. , O'Connor P. , Mearns K. , Gordon R. 
Published: December 2007

Abstract
This paper describes a project sponsored by 13 companies and the HSE (OSD) to apply a form of human factors training called Crew Resource Management (CRM), which is widely used in aviation, to the training of offshore platform teams. The aim of the project is to design and evaluate the training to improve safety, productivity, and to reduce down time on offshore installations. A prototype course has been developed with support from a major operator who is sponsoring the project. The training is delivered over two days, and consists of six core topics (situation awareness, decision making, communication, team working, fatigue and stress) established from the findings of our own research concerning human factors offshore and our own experience of designing CRM courses for offshore emergency response teams. Feedback from the courses was generally positive, however, more work is required to tailor the course specifically for offshore teams.
Simulation Analysis of Lean Alternating Rich Gas Injection in a Massive Turbidite Reservoir
Authors: Beare P. , Cockin A. 
Published: December 2007

Abstract
Stranded gas and environmental concerns are leading more operators to consider gas reinjection which, if poorly planned, could lead to a loss in reserves. This paper reports on extensive compositional simulation studies which were performed on a high permeability turbidite reservoir to investigate ways of obtaining benefit from the injection of an apparently immiscible gas stream.
A lean alternating rich horizontal gas flood scheme, using separator streams, was identified as being attractive. The ratio of lean to rich gas was examined and an optimum identified which allowed the greatest volume of lean gas to be sequestered into the reservoir whilst increasing recovery by 10% OIIP above a base waterflood for the reservoir studied.
In addition, sensitivities were performed to investigate the impact of geological uncertainties, the use of water as a buffer, and varying injection rates and total injection volumes.
This paper illustrates that the latest high definition geology and simulation models can now unlock the potential of such novel gas injection schemes. In the past, models were too coarse and numerical dispersion dominated the process. This effect was investigated in the grid refinement sensitivities that were done in preparation for this project.
Chemical Gas Shut-Off Treatments in Brunei
Authors: van Houwelingen J. 
Published: December 2007

Abstract
In BSP layered reservoirs where thin oil rims are overlain by gas caps, oil production can be severely hampered by high gas/oil ratios. The negative consequences include reduced oil rates and oil recovery, early shut-in of production wells, environmental pollution resulting from excessive amounts of flared gas, loss of energy drive, downstream processing constraints and problems.
Oil production can be improved by means of a gas-blocking foam barrier in the near wellbore area.
The Gas Shut-Off (GSO) foam treatments can be applied through tubing by means of bull-heading and are therefore especially suitable where selective placement using straddle packers is not possible. A wet foam is injected non-selectively in oil as well as gas bearing sand layers. However, the wet foam will only develop into a barrier of dry foam as a result of the high shear from free gas in the gassed out layer(s). This effect allows wet foam placed in the oil layers to be back produced relatively quickly.
Key success factors for application of foam barriers are the optimum control of placement of the barrier-forming material and selection of the foams with the maximum gas-blocking ability. Selecting suitable foamer systems can only be done by means of laboratory flow tests at the prevailing reservoir conditions due to the interaction of the foam forming surfactant with its interfacial environment.
Handil Field: Three Years of Lean Gas Injection Into Waterflooded Reservoirs
Authors: Gunawan Sugianto , Caié Didier 
Published: December 2007

Abstract
The giant Handil field comprises of more than 500 hydrocarbon accumulations, in structurally stacked and compartmentalized fluvio-deltaic sands.
Most of the accumulations consist of a large column of saturated oil underlying a gas-cap, trapped in reservoirs with good rock properties, and have been produced by water injection or strong natural water drive.
In 1995 five reservoirs, representing nearly 1/5 of the field's total OOIP and which had reached their final stage of waterflood development - 58% of the total oil in place had already been produced - were submitted to a further development with lean gas injection to increase the ultimate oil recovery.
To date, after 3 years of gas injection, the recovery factor for these 5 reservoirs has increased by 1.2% of the oil initially in place and the project is considered both a technical and an economical success.
The predominant drive mechanism with lean gas injection have been confirmed by field data. The previous decline of oil productionhas been stopped and the oil rate is now stabilizing. The main monitoring challenge has been the control of gas cycling for most of the producers, particularly during periods of higher injection rates to compensate low injection periods imposed by gas availability.
The very close monitoring of the wells and reservoirs performance, the numerical simulation and material balance studies, have helped to better understand the mechanisms involved and have to led a revised and more efficient policy to maximize oil production.
The experience gained and the analysis of this 3-year old project gives the confidence to pursue the extension of the lean gas injection development to others reservoirs of Handil field.
Air Injection - Cost Effective IOR Method to Improve Oil Recovery from Depleted and Waterflooded Fields
Authors: Surguchev Leonid M. , Koundin Alexander , Yannimaras Demetrios 
Published: December 2007

Abstract
In the past air injection has found a wide application as a recovery method of heavy oil. Air injection into light oil reservoirs is a different process than heavy oil combustion. Significant increase in light oil production under air injection can be achieved with enhancement to the economics. The main agent of the process is air which can be regarded as an inexpensive and easily available. A total consumption of 5 to 10% of the remaining oil in place can be expected to maintain a propagation of the in-situ oxidation process. The flue gas and steam generated at the combustion front are stripping, swelling and heating contacted oil. The light oil is displaced at near-miscible conditions with complete utilization of injected oxygen. The process can lead to a high recovery within a relatively short period of time. The process can potentially result in all remaining oil in place being produced. The propagation of the combustion and displacement fronts in the reservoir can be sometimes uncertain. Monitoring and control of combustion front movement is important.
The potential of air injection process for an offshore field in the North Sea was evaluated. A simulation reservoir model accounting for chemical reactions, stochiometry and thermal aspects of the combustion process was used. History match simulations of the combustion tube experiments calibrated the fluid description in the simulation model. Application of air injection as primary, secondary and tertiary oil recovery process was evaluated. The simulation results showed a high efficiency of air injection if applied at a late stage of field production. Secondary air injection potential to improve oil recovery after depletion was estimated at 10% of STOOIP in comparison with secondary waterflooding, while tertiary air injection was estimated to improve waterflooding by additional 5% of STOOIP. Air injection in the light oil reservoirs at late or mature production stage will increase oil recovery at low extra cost and extend the economic life of the fields.
Application of Hydrocarbon Gas Miscible Flooding for Water Flooded Reservoir
Authors: Shimizu T. , Takahashi K. 
Published: December 2007

Abstract
Within the next decade, the potential for application of gas miscible flooding process can be enormous, particularly, in those reservoirs currently under waterflood. In general, reservoir pressures of these oil fields are maintained at relatively high pressure, which is favourable for application of gas miscible flooding. We conducted a feasibility study to investigate the application of hydrocarbon gas miscible flooding in an oil field in Middle East offshore area. This oil field has a plan to utilise the high pressure hydrocarbon gas produced from deeper gas formation beneath the target oil reservoir, as the injection gas. A series of laboratory tests, comprising of: (1) Phase behaviour tests, (2) Slim tube displacement tests and (3) Composite core displacement tests, were conducted to characterise the miscible process in the crude oil-injection gas system. With the help of phase behaviour tests such as swelling test and multiple-contact test, the equation of state (EOS) parameters were fine-tuned. The minimum miscibility pressure (MMP) was determined by the slim tube displacement tests and also a set of representative EOS parameters were successfully verified by simulating slim tube displacement performance. As the MMP is still below the current reservoir pressure, the composite core displacement tests were conducted to evaluate the displacement efficiency at the current reservoir pressure as the tertiary oil recovery after water flooding. The test results showed that more than 80% of residual oil after water flooding could be recovered. Finally, the compositional reservoir simulation studies for the sector model of the target oil reservoir were conducted and it too, indicated that hydrocarbon gas miscible flooding could be feasible in such a high water-saturation oil reservoir.
Dynamic Interaction Between CO2 Gas and Crude Oil in Porous Medium
Authors: Siregar S. , Mardisewojo P. , Kristanto D. , Tjahyadi R. 
Published: December 2007

Abstract
This paper is based on laboratory research which is focused on the potential applications of CO2 gas, existing in different reservoirs in Indonesia, especially in the D-Alpha Gas Reservoir in Natuna Sea. CO2 gas as an injection fluid into oil reservoirs has been a well recognized and well tested Enhanced Oil Recovery (EOR) method, because CO2 dissolves easily into oil, it reduces oil viscosity, and it can extract the light components in oil at sufficiently high pressures. The technical contributions that can be derived from this paper are: first, the cost of disposal of CO2 produced with natural gas can be saved, second, CO2 injected into nearby Natuna oil reservoirs will increase oil recovery of those reservoirs, third, the best method among several alternatives offered in this paper to maximize the benefit in recovering more oil can be selected. There were three objectives we wanted to achieve in these laboratory experiments. The objectives are to obtain oil recovery performance and to identify the interactions between fluids as a result of, first, CO2 dissolved in Water (carbonated water) Injection, second, CO2 slug and chase fluid injection, and third, CO2 injection with the addition of a surfactant slug and water into oil reservoir. The results showed that the cemented sand core delivered consistent results during the whole series of experiments. The sandpack has apparently altered during the experiments. The scaling coefficient calculations have shown that all displacement fronts are stable. All displacements have shown that oil recoveries with these methods are higher than with waterflood only. The observations on different displacement angle have shown that gravity plays an important role in the recovery process, so does CO2 gas concentration in injection water, CO2 slug size and surfactant concentration. It has been observed also that there are optimum values for those parameters, meaning that above those optimal, there is no increase in oil recovery. We conclude that these methods could offer alternatives in improving oil recovery, even after waterflood, also that the operation parameters should be optimized to maximize the benefit.
Field Test of the Indigenous Microbes for Oil Recovery, Ledok Field, Central Java
Authors: Yusuf A. , Kadarwati Sri , Nurkamelia Nurkamelia , Sumaryana Sumaryana 
Published: December 2007

Abstract
LDK132 was chosen to be implemented of MEOR technology using "huff & puff" method. Water and oil from Ledok Formation were taken at the wellhead. No LDK-132 core was available, only cores from LDK-209 and LDK-P1 were found. Core plugs could not be made from the former due to very tight conditions with the permeability of only 0.458 md. The latter with the permeability of 140 md was ready for the microbial core flooding (MCF) tests. A standard core (Clas-sach) from Scotland was also be used to compare with the native core's result. The MCF tests were conducted on reservoir conditions upon the native core gave an increase 12.58% of Sor, while the standard core yielded 21.22% of Sor. The first cycle, conducted on 8 July 1999, consisted of 135 barrels of microbes enriched with KKL-11 and M4+ media, were injected through annulus of LDK-132. The result showed an increased of oil production rate, from 8.18 BOPD before the injection to 12.27BOPD, hopefully, after the injection.
Resin Sand Consolidation In Baram Delta, Sarawak. Case Study On Resin Performance versus Internal Gravelpacking With Acid Prepacking
Authors: Karian Mohd Awallizam , Salleh Alias , Haron Jamaludin , Sura Mohamed Adzman Mohamed , Rashid Ruziean A. 
Published: December 2007

AbstractChemical sand consolidation (SCON) is a type of sand exclusion which withholds unconsolidated formation from disintegrating and producing loose grains into the wellbore. The produced sand can lead to plugging off completion accessories and eroding surface facilities which eventually, over long period of time, will hamper production of a well. Most of the time, a well needs to be shut in and some oil reserves will be left behind the casing. It requires investment in bailing out the sand from the well or may be to the extend of incurring high investment to workover the well.Sand exclusion with internal gravelpacking (IGP) has been proven in Baram Delta field, Sarawak since early 60's. In early 90's, acidprepacking was introduced as part of gravelpacking job for better placement of gravels in the perforation tunnels. Historical performances show that the well has less skin than the conventional gravelpacking as the acid used can clean up the perforation tunnels and place the gravels inside them. The technique proved that the well flushed with acid prior to gravelpack job can sustain production much longer and at higher rate.There are many chemical SCON (e.g. phenolic, epoxy, and furan) available in the market, but the project team decided to use furan resin mainly due to its economic viability. At the end of 1998, furan resin was applied in one of the Baram wells and it had improved production rate and much less skin compared to the well using IGP in the same reservoir package. Sand treated with resin is capable of delivering about 1000 bopd from 15 ft. of perforation interval compared to only 400 bopd in 49 ft. IGP perforated interval in another typical well.In Baram Delta case even with snort perforation interval, the sand treated with resin can potentially deliver higher production than the sand controlled with IGP. The success of the pilot furan resin application are mainly due to the combination of a good drainage point selection, drilling practices, and cooperation between the production team and the project team during the production phase.
Study on the Mechanism: How Polyacrylamide Influences the Microscopic Properties of Produced Liquid
Authors: LiYan Qiao , Xiuhong Zhang , Fengling Zhao 
Published: December 2007

Abstract
The mechanism how polyacrylamide (PAM) influences the properties of produced liquid were investigated by means of the measurements of microscopic properties of oil-water interface. The resluts show that the presence of PAM results in significant increases of membrane strength and electrical property of oil-water interface, and decrease of interfacial tension. The tendencies of the variation were analysed and some suggestions on how to improve separation efficiency were proposed as well.
A Simulation-Based Spreadsheet Program for History Matching and Forecasting Shale Gas Production
Authors: Sawyer W. K. , Zuber M. D. , Williamson J. R. 
Published: December 2007

Abstract
This paper discusses the development and application of an Excel spreadsheet program for history matching and forecasting gas production from shale wells in the Appalachian, Michigan, or Illinois basin. The program is simulation-based and uses 1,000 to 3,000 simulation runs to a maximum time of 30 years. The simulation runs are made using a matrix of key reservoir parameters specific to the area of study. The output gas and water production from the simulation runs is incorporated into a worksheet in such a manner that any single forecast may be easily selected. The user selects a combination of input parameters from dropdown menus, and graphs of simulated gas and water production are instantly generated on the main worksheet screen.
Observed gas and water production data are entered into a separate worksheet for history matching and are plotted together with the simulated data. On the main worksheet, the drop-down menus are used to find the simulation input parameters that result in the best overall history match. Once a match is obtained, the user may easily export the 30-year simulated gas forecast for economic analysis.
This tool provides a simple method to quickly analyze short-term production data when no other means is available. Also, this tool can be easily adapted to different geological settings including shales, coals, and sandstones.
A Novel Lightweight Cement Slurry And Placement Technique for Covering Weak Shale in Appalachian Basin
Authors: Kulkarni S.V. , Hina D.S. 
Published: December 2007

Abstract
Cementing of casings over weak formations has always been a challenge, especially in the case of multiple zone completions where the zones are spread over large intervals.
Devonian Shale wells in Appalachia model similar difficulties. Frac gradients as low as 0.30 psi/ft are common in these naturally fractured zones. Cement fill-ups of up to 3500 feet are required to allow for up to 7 stage completions. Commonly, these wells have been cemented using two stage cementing or by planning for a squeeze after the primary cement job.
A lightweight cement blend was introduced in 1997 to achieve the entire fill-up with the primary cement job only. This blend provides the flexibility of density alterations from 11.0 to 14.0 lbs/gal (ppg) and is extremely easy to mix and pump. Another advantage of this blend is its ability to achieve gellation very quickly in spite of its high water content. A silicate component in the slurry efficiently ties up the excess water.
The job design utilized to place a long cement column across the weak and naturally fractured shale has proven to be very critical. A minimal amount of water pumped ahead ensures lowest possible hydrostatic pressure for the bottom most shale zone.
A single stage cement job offers several advantages. Cost savings in excess of $ 10,000 per well can be realized if the desired cement fill can be successfully obtained with a single stage job. Elimination of the stage tool and the ability to run frac baffles are the major contributors to the cost savings.
Through February 1999, this lightweight slurry was used to cement 65 wells. The available data indicates that sufficient cement fill was obtained to cover all the desired zones in more than 60% of the wells. The success rate increases to 78% if certain avoidable factors are eliminated. Cement fill-ups of as much as 4300 feet have been obtained with this slurry.
Practical Methods to Improve Storage Operations - A Case Study
Authors: Brown K. G. , Sawyer W. K. 
Published: December 2007

Abstract
A case study is presented in which a storage operator in the northeast US used easily obtainable data to: (1) accurately quantify both existing and potential deliverability of the reservoir; (2) identify bottlenecks in downhole and surface facilities that reduce maximum deliverability; (3) resolve inventory issues by determining the effective reservoir pore volume; (4) demonstrate the feasibility of turning the working gas volume multiple times per season; and (5) determine the optimum horsepower requirements to turn the working gas volume multiple times per season. All of this was accomplished by analysis of inexpensive and easily collected data.
The general optimization process used is outlined and discussed, as well as the limitations of the approach. The value of this optimization process is demonstrated by presenting field case histories that review the results of the optimization process and the implications to the storage operator.
Multilateral Tieback Insert Provides a Low-Cost, Sealing Multilateral Junction
Authors: Lindvall Jonas , Hengeveld Bas , Al-Asmi Moghrob , Chadwick Robert , Dewey Charles , McGarian Bruce 
Published: December 2007

Abstract
The Amin Field in Southern Oman is an excellent example of how multi-lateral technology catapulted an oil field from being an unattractive development to a highly attractive investment in the budget constrained late nineties. Despite being discovered in the mid seventies, development of the Amin Field did not really take off until horizontal drilling had secured a firm foothold, and only then with the assistance of multi-lateral technology. During the development of the Field the multi-lateral design was continually technically and economically optimized. This optimization, however, led to the unexpected plugging of the lower lateral by shale which ingressed through the milled casing window from the overlying cap rock. This in turn led to unsatisfactory economic performance of the streamlined multi-laterals and prompted immediate action. The Tieback Junction Sleeve (TBJS) was developed and tested primarily to combat the shale ingression and to provide a sealing multi-lateral junction. To date, extensive yard testing of the system has been undertaken and three complete TBJS systems have been run and tested in the Amin Field. All indications suggest that shale ingression have halted and that the junction is truly sealing.