bluuebunny/crossref_metadata_2025_split huggingface dataset:
Waterflood Induced Fracture Modeling in West Salym Field
Authors: Aniskin Alexander , Chmuzh Irina , Sakhibgareev Rushan 
Published: February 2011

Abstract
Waterflooding is a common practice recovery method in West Siberia oil fields. SPD started water injection in Dec 2005 and, since then, there are more than 100 injectors operating in the field. It is well established already that a successful waterflooding can only be achieved with a proper well and reservoir surveillance and management. Field observations indicate that injection is taking place under fracturing conditions. In order to manage and control this process SPD has put a surveillance plan in place which include performing regularly (modified) Hall-plot analysis, temperature and production logging (TLP/PLT), pressure fall-off (PFO) tests, and step-rate tests.
The case study, presented in this paper, describes the approach of induced fracture modeling of one of injectors in the field. An in-house coupled fracture/flow simulator (FRAC-IT) is used for this purpose. First, data assimilation/history match is performed by calibrating FRAC-IT simulation model with the fracture size and BHP data based on PLT/PFO analysis. This covers the historical period of injection. Subsequently, forward simulations are run to predict fracture sizes for a number of future infill and waterflood pattern conversion scenarios. Finally, since water quality influnces on fracture dimensions and containment, recommendations related to injection water quality specifications are made.
An important outcome of the study is establishing an approach and the workflow required for modeling induced fracture for complex field operations.
Viscoelastic Surfactant Diversion: An Effective Way to Acidize Low-Temperature Wells
Authors: Toseef A. , Beaman D. J. , Birou P. 
Published: February 2011

Abstract
A gel-based, crosslink-diverter system has been the fluid of choice for a wide range of temperature applications for carbonate acidizing treatments in Qatar. Recent field experiences with acidizing low-temperature wells (100 to 140 °F) indicated the need for a chemical diverter system that develops viscosity rapidly enough to divert acid in a continuous pumping stream.
A viscoelastic surfactant- (VES) based acid-diverter system was selected for a trial treatment because of its attributed phenomena of viscosity generation. Viscosity development for this system is a function of divalent cations generated as a result of HCl acid reaction with carbonates. Laboratory tests were performed to evaluate a viscosity profile for viscosity development versus acid spending. It was established that using 15% HCl mixed with the VES system would provide sufficient reaction rates at these low temperatures to generate an adequate amount of the divalent cations for rapid viscosity development. Formation fluids act as breakers for the VES gel. Treatment guidelines were developed based on the sensitivity of VES systems to iron content, corrosion-inhibitor concentration, and incompatibility with emulsified acids.
Field application of the system showed promising results by providing better acid diversion for these low-temperature wells compared to the gel-based crosslink diverter. Downhole-pressure plots confirmed the rapid viscosity development as predicted from the lab tests. Field mixing and pumping guidelines were developed for further application of the system based on the learning from these field applications.
This paper presents various guidelines for successfully using the VES-based diverter system in low-temperature wells for effective acid diversion. Lab-test procedures and results to serve as a guideline for such applications are discussed. Case studies are shown to demonstrate the effectiveness and success of carbonate acidizing treatments using VES systems for diversion in low-temperature wells.
Technology Implementation in ADCO
Authors: Laws M. S. , Attardo A. J. 
Published: February 2011

Abstract
Technology implementation is becoming increasingly important in ADCO as fields mature, higher reserves recovery is expected and improved performance is needed. ADCO has recently implemented a new process to more efficiently and effectively implement those subsurface and drilling technologies that could add the most value to ADCO. Following engagement sessions with all of the Subsurface and Drilling Teams, fifteen strategic technologies were identified that have pan ADCO benefits.
Implementation of these technologies was then energised by setting up organizational units or with the creation of dedicated Technology Focus Groups (TFGs) with clearly defined Terms of Reference. As most of the technologies are being facilitated through TFGs, which are new organizational concepts for ADCO, this will be the focus of this paper. The TFGs are made up of a cross section of staff from ADCO, as well as Service Companies, charged with ensuring that the best interests of ADCO are considered during implementation planning and field trialling of technologies.
Initial results are encouraging. The TFGs are already establishing themselves and gaining acceptance as a means of sharing knowledge across ADCO as well as facilitating technology implementation. Indeed, a number of key technologies have already been progressed to the pilot stage, which is much faster than our previous experience.
Each selected technology is being sponsored by a Senior Manager and a Corporate Executive oversees Technology Implementation across ADCO.
The purpose of this paper is to describe the process and strategy that has been set up in ADCO to mature and deploy subsurface and drilling technologies. It also provides an overview of progress made to date with implementing this strategy.
Case Studies of Successfully History Matched Reservoir Simulation Models using a Powerful Optimiser being of Limited Predictive Value
Authors: Kathrada Muhammad , Carter Jonathan N. 
Published: February 2011

Abstract
History matching production data using finite difference reservoir simulation models has been and will always be a challenge for the industry. The principal hurdles that need to be overcome are finding a match in the first place and more importantly a set of matches that can capture the uncertainty range of the simulation model and to do this in as short a time as possible as the bottleneck in this process is the length of time taken to run the model. Particle Swarm Optimisation (PSO) is a class of evolutionary algorithms that have shown much promise over the last decade. Essentially a swarm of agents are allowed to search the solution hyperspace keeping in memory each individual’s historical best position and iteratively improving the optimisation by the emergent interaction of the swarm. This method draws parallels from the social interaction of swarms of bees, flocks of birds and fish shoals. An intrinsic feature of PSOs is their local search capability. A sequential niching variation of the PSO has been developed, viz. Flexi-PSO, which enhances the exploration and exploitation of the hyperspace and is capable of finding multiple minima.
This study looks at the implementation of Particle Swarm Optimisation in history matching finite difference simulation models. The method is applied to two synthetic case studies (one based on a real field model) to find multiple distinct history matches. The resulting matches are then forward predicted to gauge their effectiveness in matching the truth case prediction.
Production Behaviour of Gas Hydrate Under Hot Sea Water Injection: Laboratory Case Study
Authors: Nengkoda A. , Budhijanto B. , Supranto S. , Prasetyo I. , Purwono S. , Sutijan S. 
Published: February 2011

Abstract
In 2004, Indonesia has discovered 850 trillion cubic feet (tcf) of potential gas hydrate deposits as alternative energy to fuel oil at least in two locations, in South Sumatra's southern waters extending to West Java (625 tcf) and in the Sulawesi sea (233.2 tcf). The laboratory and simulation production behaviour of gas hydrate under hot sea water injection as alternative of Indonesia hydrate production, have been done under laboratory condition with combination of synthetic hydrate and porous sediment. Some flow assurance challange issued also have been investigated. These preliminary study are to investigate the temperature profile distribution, operational parameters and flowing characteristics of the dissociated gas and water from hydrate in porous sediment systems under synthetic hydrate and experimental setup. The experiments have been conducted by injecting hot sea water where composition is near to Indonesian sea water characteristics with different temperatures and rates. The result find that the gas production rate increases with time until reach maximum, and then it begins to decrease. The injection water temperature and rate, as well as the hydrate content in the synthetic sediment, all influence the energy ratio of thermal stimulation production. The high temperature sea water injection found potentially creating scale problems.
Sub-surface and Surface Integration to Sustain Gas Production in a Field, Peninsular Malaysia Operations, PETRONAS
Authors: Hadi Sriyanta , Osman Azmee B , Hasnan Zairinda Bt 
Published: February 2011

Abstract
A Field is an offshore field located at offshore of Peninsular Malaysia, facilitated with an integrated oil and gas processing plant, water injection facilities and gas lift infrastructure. The field was brought to oil production in end of 2001 and achieved the peak production of about 120 Mbopd in 2005. In early of 2002, it started gas production at an initial rate of about 300 MMscf/d which is currently maintained at about 300–350 MMscf/d. The crude oil production peak was followed by a moderate decline over the next three years. Besides crude oil and gas production, the field also produces condensate as by product while producing gas. It was recognized that a proactive field management strategy was required in order to minimize any further production decline as the field production forecast showed a declining trend. Since A Field is one of major gas contributors, its gas production sustainability is very important to fulfill the gas demand in the region. The current gas sources in A Field are natural gas reservoir as the main source and the associated gas from oil production. It was recognized that subsurface and surface integrity is the key success for sustaining A Field gas production. The integration is important to ensure proper planning and execution for gas development within the A Field area as well as sustaining the crude oil production. There are several alternatives to maintain gas production. The analysis presented here describes the use of an integrated approach involving multi-disciplines to achieve the most suitable decision and maximize value creation focusing on A gas sustainability.
A Proven Approach Towards Plant Piping Integrity Management
Authors: Aljaberi Manea , Kamel Hasan 
Published: February 2011

Abstract
Plant piping integrity management is considered as a big challenge for upstream/downstream operators worldwide because of the complexity of plant piping loops and the resources required to build and maintain solid inspection database. Statistics from two upstream operators indicates that majority of leaks within operating plants occurred at plant piping loops rather than main static equipments and with majority of operating facilities exceeding its intended design life (40 years), the Middle East upstream/downstream industry is expected to see a higher rate of failures in the coming years unless a paradigm shift is made in plant piping integrity management. Hence it is essential to focus integrity initiatives on plant piping in order to achieve higher overall plant integrity status, without ruling the need for integrity management for other plant equipments. This paper is presenting a unique structured approach towards plant piping integrity management which was deployed by two upstream Operators in the period from year 2004-2008 and from year 2007-2010 respectively. The piping integrity management approach presented in this paper is based on multidisciplinary engineering team consisting of process, CAD-draughting, Corrosion, Inspection, NDT, Piping, Mechanical, Maintenance data management disciplines. The approach was proven to enhance plant integrity status by evidence from failure statistics trends which are presented in this paper. Several challenges were faced during the implementation; the case studies discuss how the two Operators overcame these challenges and developed a systematic integrity review using existing Computerized Maintenance Management System ERP package. Nevertheless, the implementation of this approach enabled the two Operators to identify weak design specifications (e.g. piping support design) and supported the upgrade of the piping specification to avoid reoccurrence of the frequent failures. In the two case studies, the Operators were leading a rehabilitation program addressing non-integral piping systems over the entire facilities. The piping integrity management approach discussed in this paper is generic in nature and can be applied by any upstream/downstream operators in the world with high rate of success. It is expected that this topic will be of a big interest to all upstream/downstream operators in the region and possibly worldwide. The results of the implementation of the subject approach confirmed suitability of this approach in enhancing plant piping integrity, and therefore overall plant integrity status.
The Application of ESPCP in China Offshore Oilfield
Authors: Feng Bao , Meng Weibin , Li Anxia , Zhang Xiaocheng , Li Liangchuan , Wu Bingchang , Li Xin 
Published: February 2011

Abstract
ESPCP is a combination of Progressive Cavity Pump (PCP) and Electric Submersible Pump (ESP) motor as an artificial lifting system in oil & gas industry. So ESPCP has also integrated the advantages of both PCP and ESP. It is considered as the most suitable artificial lift system for some special oil quality or well conditions, such as high viscosity oil, sandy oil, deviated or horizontal well and offshore platform. Besides, the PCP’s energy saving has also well reserved in ESPCP.
Sanyang Co. Ltd. began its researches and developments on ESPCP since 1996, and now it succeeds to supply 2 series of ESPCP for 7" casing (150 serial) and 9 5/8" (200 serial) casing. And over 150 sets of ESPCP units have been tried and applied in different well conditions in CNOOC (China National Offshore Oil Company), SINOPEC (China Petroleum & Chemical Corporation) and CNPC (China National Petroleum Company) offshore oil fields. These successful cases have covered the viscosity 100~8000 mpa.s, inclination angle at pump depth 20~86°, pump depth 900~1800m, flowrate 20~240 m3/d, and the average life span is over 400 days.
The key point of ESPCP system is the reliable downhole mechanical transfer system (including the motor reducer) and the PCP elastomer suitable for high speed running. Sanyang Co. Ltd. Cooperated with PCM had successfully solved these technical bottlenecks of ESPCP syste,. This paper will discuss the advantage, technical highlights, the technical specifications and case stories of Sanyang-PCM ESPCP.
When Unconventional Becomes Conventional
Authors: Stefik R. , Paulson K. 
Published: February 2011

Abstract
British Columbia has seen near exponential growth in the areas of the Horn River and Montney unconventional shale gas plays situated in North Eastern B.C. (figure 1). The original gas in place volume for the Montney and the Horn River basins have not been formally calculated but have been estimated at more than 500 Tcf and continues to be revised upwards as new and more refined information is obtained as development takes place. The Cordova Embayment and Liard Basin, east and west respectively of the Horn River Basin, are at early stages of assessment but promise additional massive gas-in-place values.
Approximately 5 years ago, industry experts were predicting a drastic reduction in viable gas production from the Western Canada Sedimentary Basin, and North America in general. Market predictions were favouring investment in import terminals for liquefied natural gas (LNG) where gas from offshore suppliers could be imported and moved through the North American transportation grid to market. Regulators were anticipating an influx of LNG facility applications as well as a myriad of infrastructure modifications to handle the resulting new flow regime.
In five short years, this dire future has been completely reversed due to the advent of economically viable methods to access gas trapped in shales and similar tight formations. At the current rates of production and exploration, there are more than 20 year of gas reserves in BC, reversing a previous decline, as shown in Figure 2.
British Columbia is ideally positioned to provide gas to North America with ready access to a number of major gas transportation pipelines including systems operated by TransCanada Pipelines, Spectra Energy Gas Transmission and the Alliance Pipeline. Many of these systems are undergoing significant capacity expansions to accommodate the influx of gas from these new plays.
This paper will explore the challenges posed to regulators in moving rapidly from conventional vertical well developments to unconventional multi-well pads consisting of multiple fracture stimulated horizontal wells.
The Potential for Slot Closure, Screen Damage, and Collapse of Liners in Thermal Horizontal Wells
Authors: O'Rourke J. C. 
Published: February 2011

Abstract
Liners in horizontal thermal wells do occasionally have production inflow problems and fail. Published literature exists on the risks and design issues related to the effects of thermal expansion on slotted liners in horizontal wells. This paper investigates two areas of liner behaviour that seem to have been somewhat overlooked. It examines: (1) the potential effects of thermal expansion or contraction on screened liners and (2) the effects of thermal contraction on slotted and screened liners.
Upon injection of steam, horizontal liners will expand or contract and be subject to compressive or tensile axial stresses. Whether the stress is compressive or tensile depends on when the formation closes in on the liner. If it closes in before the well is steamed, the stress will be compressive; if it closes in after steaming the stress will be tensile.
This paper examines the effects of shear force from the formation on the screens of liners both in expansion and contraction. It would appear that to some extent the shear or tearing forces on screens are self-limiting making them more resistant to tearing than might be expected.
The paper also examines effects on liners of tensile forces caused by contraction and cooling. Tensile forces on liners can approach and exceed yield under common operating conditions. The liners are then susceptible to slot closure and collapse.
Limits on operating conditions are presented to reduce the risk of such failures. Suggestions for further R&D on the subject are also made.
Characterization, Modelling and Simulation of the Fractured Najmah-Sargelu Carbonate Reservoir, Umm Gudair Field, West Kuwait
Authors: Matar S. , Ghilardini L. , De Groen V. , Le Maux T. , SinghaRay D. , Al-Shamali A. 
Published: February 2011

Abstract
The Najmah-Sargelu reservoirs of the Umm Gudair field in West Kuwait are tight, oil-bearing carbonate reservoirs in which production is mainly achieved through a well-developed multiscale fracture network. Developing such complex reservoirs implies the building of accurate matrix models, the fine static and dynamic characterization of fractures and the correct representation of both matrix and natural fractures into simulation models. In this paper, we present such a multi-disciplinary approach based on the integration of geological, petrophysical, geophysical, and dynamic data and where state of the art techniques in seismic characterisation, sequence stratigraphy, fracture modeling and simulation have been used.
The matrix model of the reservoirs was primarily developed based on the analysis of well data involving a core description and petrophysical interpretation. It was finalized by integrating the results of a detailed sequence stratigraphic analysis and a lithological characterization from seismic. The fracture characterization was based on the analysis of static and dynamic data and built upon the results of a former regional study. Large-scale fractures were identified with the help of seismic attributes and seismic facies map. Three sets of small-scale diffuse fractures were also characterized based on borehole image interpretations. Their occurrence is controlled by the shale content of rocks. Finally, the dynamic characterization of fractures using production data, well test and flowmeter data concludes on the critical impact of fractures on fluid flow in the reservoirs. Based on these results, a 3D Discrete Fracture Network (DFN) model of the reservoirs was built. It was calibrated against well test data in order to assess the hydraulic properties of fractures.
Both fine matrix model and fracture model were upscaled and combined to build a dual porosity simulation model. The history matching process enabled to better constrain both fracture network porosity and the matrix-fracture exchanges. It was then used to optimize the future development plan of the Najmah-Sargelu reservoirs. Classical production strategies such as depletion, water or gas injection were first tested. The type, number and position of new wells were then optimized.
Ensuring Well Integrity in HP/HT Wells: Brunei Case Study
Authors: Taoutaou Salim , Luangkhot-Bonnecaze Alanh , Dondale Aaron , Jain Bipin , Abdullah Nazri 
Published: February 2011

Abstract
Zonal isolation and long-term cement integrity in the high-pressure/high-temperature (HP/HT) environment are critical to optimizing production and minimizing future well intervention and replacement. In addition, the well stresses vary over a large amplitude during construction, testing, and production of such wells. There is, therefore, significant value in avoiding failure of the cement sheath.
In 2007, Total E&P Borneo commenced an HP/HT caMPaign in Block B offshore Brunei to drill development wells with deeper exploration sections. These HP/HT wells are the most technically challenging for well cementing in terms of preserving long-term well integrity; these wells are exposed to high temperatures exceeding 165°C, pressures exceeding 69 MPa resulting from different operations, including production. Cementing these wells using conventional cement and practices has proven not to be effective. This leads to the introduction of new technologies and newer cementing techniques to ensure long-term seal of these wells.
This study identifies first the risks associated with cement sheath failure under downhole stresses. Then it discusses the successful implementation of a solution that ensures a complete zonal isolation of these HP/HT wells, consequently avoiding unnecessary and costly well intervention.