bluuebunny/crossref_metadata_2025_split huggingface dataset:
Recovery Optimization Strategy for Thin Oil Column Reservoir with Large Gas Cap: Case Study of Gunung Kembang Field
Authors: Febrianto Dwi Hudya , Aimar Amritzar , Afandi Tomi , Setiawan Dadan , Handayani Ricky SW 
Published: October 2008

Abstract
Effective exploitation of the thin oil rim in the Gunung Kembang field is particularly challenging because of the huge size of the overlaying gas cap, and the thickness of the oil rim varying between 25 to 40 feet gross pay interval, not to mention the sizeable water aquifer underlying the reservoir. Horizontal wells were implemented since 1992 to enhance oil recovery by reducing gas and water coning, nevertheless, oil recovery still remain around 3%. As the pressure is depleting, horizontal wells revealed to pose higher risk than before, just like in the second stage of horizontal drilling in 2004, where water breakthrough and total loss occurred. The plan to add more horizontal wells to add recovery was coincided with POD commitment to deliver gas by gas cap blow down.
This paper presents a team effort to formulate optimization strategy for maximizing oil recovery and revenue while delivering gas as committed in POD. Integrated reservoir characterization that comprises of carbonate depositional study, and reservoir simulation was conducted to best manage not only the drilling location but also number of wells and production strategy for next horizontal wells.
Carbonate depositional study using existing logs and core data revealed the best oil potential zone in Baturaja formation in terms of porosity and permeability. Meanwhile, reservoir simulation grid was aligned with the zonation from carbonate deposition model, after that the performance of existing 10 wells was history-matched to develop an improved strategy. Sensitivity analysis conducted demonstrated that locating horizontal oil wells in the upper oil rim near the gas oil contact proved to be the best strategy for depletion of the oil rim.
Among five scenarios developed, one final scenario was selected to accommodate both oil recovery optimization and gas cap blow down. This scenario includes eight additional horizontal oil wells while utilizing their produced gas to accommodate gas commitment, without drilling another gas well. Oil recovery is expected to rise to about 8% while gas is being delivered according to POD.
X-O-T Technology for the Treatment of Crude Oil Emulsions
Authors: Nahmad David G. , Kmiec Isabela , Nasir Awalludin , Udau Isrom 
Published: October 2008

Abstract
SCOMI Energy in cooperation with PETRONAS Carigali Miri Crude Oil Terminal (MCOT) implemented a pilot project to demonstrate the effectiveness, technical and economical, of the emulsion treatment technology known as X-O-T for emulsion resolution and crude oil recovery.
A typical emulsion was drawn in batches from Emulsion Storage Tank into Scomi's system. This emulsion was processed on a continuous flow basis through a custom designed system in order to break "resolve" the emulsion and separate its constituents for further disposal or storage of the oil as "dry oil".
X-O-T is a proprietary process utilized to break emulsions of hydrocarbons/water/solids. The process is based on a series of chemical reactions that interact with other reagents releasing heat and neutralizing the non-covalent forces that form the bonds between the substrate and the wetting agents making it feasible to separate the components of an emulsified mixture of minerals, water and hydrocarbons.
A mechanical process for separating the emulsion constituents is needed.
The results of the processing of this emulsion were very promising. All solids contained in the initial emulsion were removed from the mixture; some of small particles in the colloidal size range were transferred directly to the recovered water.
The emulsion was resolved up to 92% to 98% leaving a small tough invert emulsion that contained no solids and a high concentration of heavy hydrocarbons. Recovered solids were "dry" and had hydrocarbon content around 15%. Recovered water was treated using ionic polymer. The result rendered clean water.
This technology can prove to be very economical not only for oil recovery, but also as preventative maintenance. The removal of all solids from this stream can strongly impact the tank farm operations budget by reducing downtime, increasing storage capacity and removing expenses such as tank cleaning and sludge processing.
Dynamic Modelling of CO2 Injection in a Closed Saline Aquifer in the Browse Basin, Western Australia
Authors: Yang Qingjun 
Published: October 2008

AbstractThis paper presents results of dynamic modelling of CO2 injection in a closed saline aquifer in the Browse Basin, Western Australia. The storage capacity of CO2 in this type of aquifer is ordinarily greatly limited due to the rapid pressure buildup during injection. This study shows how closed systems, including faulted or lithologically confined reservoirs, may be made suitable for larger volumes of CO2 storage. Based on the analysis of radial flow models, the inability of the reservoir to accommodate displaced water was considered to be the main reason for the rapid pressure increase. Simulation results show that producing brine from the reservoir can greatly relieve the injection pressure and increase the storage capacity. Under an optimum injection-drainage strategy, the risk of CO2 breakthrough at the drainage well can be decreased and the cost of draining brine can also be reduced. The studied site is estimated to be able to contain at least 20 years of CO2 injection, at an injection rate of 1 million tonnes per year, before breakthrough of CO2 at the drainage well. With this type of drainage strategy, more "closed system" geological sites could be made available for storing CO2.
Lithological and Petrophysical Core-Log Interpretation in CO2SINK, the European CO2 Onshore Research Storage and Verification Project
Authors: Norden B. , Förster A. , Vu-Hoang D. , Marcelis F. , Springer N. , Nir I. Le 
Published: October 2008

Abstract
The storage of carbon dioxide (CO2) in saline aquifers is one of the most promising options for Europe to reduce emissions of greenhouse gases from power plants to the atmosphere and to mitigate global climate change. The CO2SINK project is a R&D project, mainly supported by the European commission, the German Federal Ministry of Education and Research, and the German Federal Ministry of Economics and Technology, targeted at developing an in situ laboratory for CO2 storage. Its aims are to advance the understanding of the processes involved in underground CO2 storage, evaluate applicable monitoring techniques, and provide operational experience, which all contribute to the development of harmonized regulatory frameworks and standards for CO2 geological storage.
The preparatory phase of the project involved a baseline geological site exploration and the drilling in 2007 of one injection and two observation wells, as well as the acquisition of a geophysical baseline and geochemical monitoring, in Ketzin located near to Berlin, Germany. The target saline aquifer is the Triassic Stuttgart Formation situated at about 630–710 m (2070–2330 ft), that is made of siltstones and sandstones interbedded by mudstones. A comprehensive borehole logging program was performed consisting of routine well logging to which an enhanced logging program was added for one well that record nuclear magnetic resonance and borehole resistivity images predominantly to better characterize the storage formation. A core analysis program carried out on reservoir rock and caprock included measurements of helium porosity, nitrogen permeability and brine permeability. Carbon dioxide injection started in 2008 and will last for about 2 years.
The paper focuses on the integrated approach of combining lithological and petrophysical data from both laboratory and well logging analysis predominantly for the reservoir/storage section of the Ketzin site. This method was successfully applied in two wells with extensive core data. In the third well, where few core data exist, the section was characterized successfully by analogy.
Regional Pore Pressure Modeling Strategy at Tiger Shoal, GOM, USA
Authors: Stafford T. W. , Goode R. W. 
Published: October 2008

Abstract
Accurate prespud pore pressure prediction is key to well planning and drilling execution on the deep (&gt; 18K ft) HPHT gas wells of the Gulf of Mexico (GOM) shelf. These predrill pore pressure predictions are a key part of the general subsurface hazard assessment. A pore pressure prediction strategy that combines petrophysical, geophysical, 1.5-D hydrodynamic basin modeling and centroid effects was developed for use in the Tiger Shoal deep gas exploration and development drilling program at Flatrock.
Unique Solution for Fracture Isolation Resolves Water/Gas Breakthrough Challenges in a Horizontal SlimHole Well
Authors: Al-Mumen Adib A. , Al-Umran Mohammed I. , Agrawal Pradeep , Jorgensen Thomas , Smith Peter E. 
Published: October 2008

Abstract
Preventing water or gas breakthrough and equalizing flow is one of the primary challenges of producing from horizontal slimhole wells. This paper will present a "first-of-its-kind" concept in which swellable packers were used to isolate a water-producing fracture to prevent/delay water/gas breakthrough and equalize flow across a 3–7/8-in. horizontal open hole. The water-producing fracture was encountered during drilling of the slimhole horizontal in a naturally fractured carbonate reservoir. Prior to the introduction of swellable technology to the oilfield, satisfactory solutions for isolation in open hole slimhole wells had not been available. Although swellable technology was new to the area, after careful analysis of the situation, the operator and the service company decided to use four swellable packers to compartmentalize the hole.
The completion configuration was successfully run, and the well was brought into production at good rates and with a low water cut.
The Development of a National Gas Separation and Sub-sea Multiphase Flow Loop Facility
Authors: Amin Robert , Pack David 
Published: October 2008

Abstract
The past decade has seen oil and gas exploration and development move into a new phase as hydrocarbon reserves are increasingly found in remote locations, with a large number in the deepwater environment. This change has produced the need to develop sub-sea based technologies that are flexible, durable and simple in the face of high capital and operating costs.
Sub-sea developments produce greater flow assurance and intervention challenges.
Solutions are needed to address the low seawater temperature conditions that lead to problems within trunklines, such as hydrate formation / plugging, wax precipitation and sand accumulation. The long distances that are involved in remote location developments limit the effectiveness of existing technologies to minimise the problems.
Sand/Well Vacuuming Technology with Concentric Coiled Tubing: Best Practices and Lessons Learned from Over 600 Operations
Authors: Li J. , Crabtree A. , Kutchel M. , Diaz J. , Reyes W. , Dugarte R. , Peña L. 
Published: October 2008

Abstract
Sand production is a common problem with unconsolidated formations. It is very challenging to successfully remove formation sands with conventional methods in a large deviated wellbore with a low pressure gradient formation1.
Since 1995, a technology combining concentric coiled tubing (CCT) with a jet pump has been developed and used to remove both the drilling fluids and solids. Initially it was developed for horizontal heavy oil reservoirs where pressures are low and viscosity is high, without placing hydrostatic loads on the reservoir. The job data from more than 600 sand/well vacuuming operations worldwide has been compiled into a database.
This paper reviews the well information and the key operating parameters: maximum depth, bottom hole pressure gradient and pump rate. The engineering challenges, best practices and lessons learned for the sand/well vacuuming process are also summarized. Analysis of this data yields a better understanding about this vacuuming technology and provides good guideline for future practice.
Case histories are provided which demonstrate how to deploy the different sand/well vacuuming bottom hole assemblies (BHA), to; increase the penetration capacity with a jetting tool; entering multi-laterals with an entry guidance system; accessing small size holes with a micro-vacuuming tool; and to achieve extended reach under extreme conditions.
Post job analysis indicates CCT vacuuming technology reduces the skin damage and increases the production compared to non-vacuumed wells. Moreover, the details from sand and other fluid influx profiles obtained along the wellbore based on the analysis of the returns during the vacuuming process, could be used to evaluate well production and assist in formulating a management strategy.
Study and Application of the Technology of Subdivision Controlled Limited Entry Fracturing in Reservoir with Many Thin Layers
Authors: He Liu , Zhongguo Wang , Qingping Wang , Hongtian Yao , Jifeng He , Zhixin Wang , Shifeng Zhang , Jiachen Zhang , Zhiyao Li 
Published: October 2008

Abstract
Since the year of 2005 the output of new well has been basically from the tertiary infillers in Xingnan development block in No.5 Oil Production Plant, Daqing Oilfield Co., Ltd., where we mainly produce from the thin and poor quality oil layers of tabulated reservoirs (those reservoirs included in the reserve tabulation which was made at the beginning of Daqing Oilfield) and the untabulated reservoirs (those reservoirs excluded from that reserve tabulation). The intended zones often grow in reservoir groups of Sa II SaIII and Pu I. In such reservoirs, the sublayers to be perforated in are comparatively more, the thickness of sublayers is quite little and the perforated interval is very long, which is averagely more than 180m. Because the reservoir lithology, physical and oil-bearing properties are all comparatively worse than normal, the conventional limited entry fracturing technique can not meet the demand of stimulating such interlaminated reservoirs any more. So we advanced this technology at the following aspects:
We determined the recognition method to difficult-fracturing sublayers and the corresponding treatments by studying on the lithology and electrical characteristics of calcareous argillaceous layers in the interlaminated reservoirs. On the basis of the study on the regularity of interference between fractures from theory and the proof application of this regularity, we concluded the threshold value of the fracture spacing which would lead to inter-fracture interference. We also defined the delivery rate and sand amount to a single fracture/a single hole through both the theoretical estimation and on-site statistical analysis of the operational discharge and the amount of sand used.
Through the above researches, we not only created our own perforation designing method, but also established the criteria of selecting layer as well as the technical idea for this technology.
We successfully applied this improved limited entry fracturing technology to over 500 wells in reservoirs with many thin layers. As the results of this work, we not only reduced the operational cost of the limited entry fracturing technology but also gained ideal economic and stimulating effects. This improved limited entry fracturing technology is also applicable to the fracturing treatment in gas field.
Development of the Stybarrow Field, Western Australia
Authors: Hill Robin , O'Halloran Gerry , Napalowski Ralf , Wanigaratne Bimal , Elliott Alison , Jackson Mark 
Published: October 2008

Abstract
The Stybarrow Field is a moderate size biodegraded oil accumulation reservoired in early Cretaceous slope turbidite sandstones of the Macedon Formation in the Exmouth Sub-Basin offshore Western Australia. Excellent quality 3D seismic has enabled attribute mapping and probabilistic seismic inversion to be used to both estimate the net sand distribution of the reservoir and facilitate optimal well placement. The reservoir comprises excellent quality, but poorly consolidated, sand rich turbidites up to 20m thick. The field lies in &gt;800m of water and has been developed with four near horizontal gravel packed production wells connected to an FPSO via sub sea trees and flowlines.
Water injection is required for pressure maintenance and produced gas is re-injected into the nearby Eskdale oil & gas field, the oil leg of which is produced via a single horizontal well. Pressure support is required from field start-up due to lack of aquifer support. Horizontal production wells with high productivity indices are required for optimal drainage. Downhole sand control is provided by a combination of open-hole gravel packs and sand screens.
Key subsurface challenges were faced in the development of the relatively thin reservoir containing biodegraded 22° API oil with little or no aquifer support. Lateral reservoir variations have important implications for connectivity and therefore the optimal drainage of such fields.
The Stybarrow project involves a nine well subsea development and a double hulled FPSO, the Stybarrow Venture, with capacity of approximately 80,000 barrels of oil a day. Oil came on stream in November 2007 and nameplate production was reached within weeks of first oil. The Stybarrow and Eskdale fields which make up the project have estimated recoverable oil reserves of 60 to 90 million barrels and estimated field life is 10 years.
This paper documents a multidisciplinary approach applied during the appraisal, development and early production life of the field. Static and dynamic data on a variety of scales (i.e. seismic, well data, bed boundary resistivity modeling, inter-well interference testing and early production performance) have been integrated into detailed 3D geological models, which have enabled a greater understanding of reservoir connectivity, as well as a better estimation of ultimate oil recovery.
A Leading Model on Evaluation and Training Strategies for National Workforces in International Organizations
Authors: Grice Roger , Plato Kathryn , Zuniga Andres 
Published: October 2008

Abstract
The decision to utilize a proportion of the natural gas reserves of Peru for export purposes and as a valuable foreign currency source was a momentous occasion in the economic evolvement of the country, for with it came the single largest inward investment of $3.8 billion in the history of Peru. The new company, PERU LNG S.R.L. (PERU LNG), would be responsible for developing gas reserves, building a 408-kilometer natural gas pipeline, constructing new storage and export facilities, and of course the LNG plant itself. PERU LNG is a partnership between Hunt Oil Company of Dallas, TX (Project Leader, 50%), SK Energy of South Korea (20%), Spain's Repsol YPF (20%) and Marubeni of Japan (10%). Compania Operadora de LNG del Peru (COLP) is the operating company of PERU LNG. COLP is responsible for constructing the LNG plant and gas supply pipeline, as well as for the plant and pipeline operation and support services.
Although some reference will be made to technical aspects of the project, the main purpose of this paper is to illustrate the approach adopted relating to the training of Peruvian technicians and operators for the new LNG plant. The plant situated at Melchorita will have a capacity of 4.4 million tons per year and will be operational in Q2 2010. COLP (the Company) is initially employing an experienced expatriate workforce with phased replacement by trained Peruvian workers over a ten year period. The strategy and methodology adopted to achieve over 90% Peruvian nationals within the company workforce by 2020 makes up the main body of this paper.
A critical piece of building a sustainable operation in Peru is the integration of Peruvians into the workforce. Workers require proper training to meet regulatory requirements and to ensure work is performed in a competent manner that meets technical, legal and other requirements adopted by the project. Work performed without appropriate training may result in legal non-compliance, non-conformance to applicable quality and performance standards, delays, additional cost, environmental, health and social risks. The Company considered training a critical component to the project and explored several options for delivery of training.
Effective Engineering Decision Matrix Lead to 2-fold Improvement in Gas Well's Productivity
Authors: Nwoke Linus A. , Akinrinmade O. Goke , Ekiyor-Katimi Theophilus P. , Alaka Collins O. , Cookey Mina S. 
Published: October 2008

Abstract
A gas well completed across 60ft interval (with External Gravel Pack (EGP) as sand exclusion option) was successfully tested to 66MMscf/d against 100MMscf/d design potential due to 3rd party barge handling capacity limitation. Production fell far below expectation when the well was hooked-up to the gas plant with maximum production of 20MMscf/d at 100% maximum choke opening. This necessitated a workover to replace suspected faulty Tr-ScSSSV.
The post re-entry performance following the replacement of the Tr-ScSSSV was also poor as the well could only deliver 53MMscf/d at 100% choke opening. The poor performance was suspected to be as a result of near-wellbore damage, caused by the LCM-pill that was used during the re-entry. Integrated Production Modelling (IPM) simulation using various sensitivities on FTHP, skin factors and screen plugging predicted that the poor performance was more from surface than from subsurface issues. Requests to investigate the surface network got initial pushback as the flowline was pigged before hook-up. The popular steer was to acidize the near wellbore region for skin damage removal. Production gain predicted by PROSPER model simulation if the predicted skin damage is removed was however marginal. In an attempt to address the issues, a multi-disciplinary team to tackle the problem starting with the less expensive surface network clean-up drew a decision matrix.
Dismantling and inspection of the flowline connections to the variable choke housing revealed the source of the poor performance. Materials that were used during the flowline laying/pigging (marine rope and hand gloves) were left in the flowline, creating secondary choke (restriction) along the flowline initially and later pushed down to the choke inlet. The removal of these materials left in the flowline and the clean-up of the choke improved production from 53 to a realistic production potential rate of 127MMscf/d at 100% choke opening. The production rate increased to 150MMscf/d at 98% choke size as the well cleaned up after seven months.
This paper demonstrates how good PROSPER modelling, integrated decision matrix and persistence on sound engineering practice led to improved gas production, meeting gas supply commitments and eliminating further unnecessary expenditures ($600,000 on stimulation). Delayed gas recovery was eliminated by this effort, needless to mention the accelerated revenue from the gas supply attributed to this improvement. The paper concludes with Integrated Decision Making Strategy, Value of Success and Recommendations for future interventions.