bluuebunny/crossref_metadata_2025_split huggingface dataset:
Application of Deep Hydraulic Jet Perforating to Enhance Oil Production in Thin Reservoir with Bottom Water
Authors: Xu Suxin , Luo Weiguo , Zeng Fanhua , Gu Yongan 
Published: January 2012

Abstract
Exploitation of thin oil reservoirs with bottom water is a difficult task. Oil production rates are decreased rapidly because of water coning and inapplicability of stimulation methods such as fracturing, in many instances which makes wells have to be suspended or abandoned even at low levels of recovery. In this paper, deep hydraulic jet perforating technique (DHJP) is presented which provides an effective way to exploit such kind of reservoirs. Also the strategy, equipments, and operational procedures of the deep hydraulic jet perforating are discussed.
Deep hydraulic jet perforating is different to the well-known hydrajet perforating (HJP). In the HJP, the typical penetration depths are 12.7–20.3 cm (Kritsanaphak, Tirichine & Abed, 2010) and the jet nozzle does not move during the process. For deep hydraulic jet perforating technique, the casing is windowed mechanically with high water-pressure and the formation is penetrated by the jetting, meanwhile, the nozzle driven by screw, keeps going further in the formation through the window. Thus, the extreme deep depth can be achieved to 2 m approximately depending on the formation characteristics, and stand-off of the tool inside the casing.
Compared with the most widely used conventional explosive shape-charge perforating, the advantages of deep hydraulic jet perforating include (1) creating superior connectivity between the wellbore and formation; (2) enlarging the oil contact area; (3) leaving less near-wellbore damage. Hence, deep hydraulic jet perforating can be a good alternative for well completion, formation damage removal and hydraulic fracturing.
Deep hydraulic jet perforating has been applied successfully in JS Oilfield for the thin formation with bottom water to enhance oil production. Totally 10 holes for two producers are penetrated in target zone and the effective hole depth ranges from 1.55 to 2.01 m. The production rates were doubled and the shut-in well is revitalized again.
Downhole Matched Solutions: Innovative Scientific Approach to More Efficient Assemblies
Authors: Barton Steven Paul , Baez Franklin , Gee Ryan 
Published: January 2012

Abstract
Selecting the correct motor and bit combination to drill specific formations is critical to efficiently attain the desired performance through a vertical, directional or lateral application. If the bit is too aggressive, it can stall the motor and significantly reduce the average rate of penetration (ROP). It will also increase the likelihood of premature failure of the elastomeric liner of the motor power section, or twist-off of internal components. If the bit is not aggressive enough, it will not make full use of the available motor power and the ROP will be sub-optimal.
A new generation of an intranet system matching tool has been developed, which enables the user to accurately match a drill bit to a specific motor design, in order to deliver a more reliable and greater degree of drilling efficiency. This new software tool incorporates an advanced logic regarding the configuration of the motor power section selected, and assesses this against the bit design based on the four fundamental bit performance indices: Aggressivity, Stability, Durability and Steerability. It also reviews key features of the bit, including length, gauge geometry, cutting structure and torque control component configuration.
This software comprises of an interface that uses an extensive database that contains logic tables which describe the multi-dimensional characteristics of the motor and the bit, combining two phases of the tool: first a selection of the ideal bit for an specific application, whether vertical, directional or lateral and secondly a matched configuration of the desired motor. The software also includes, a build-up rate predictor and interference fit guide.
A range of case studies have been compiled and clearly demonstrate the accuracy and versatility of this tool to allow improved drilling efficiency. This initiates the implementation of more advanced motor technologies.
Development of Experimental Techniques, Equipment and Thermodynamic Modelling for Investigating Systems with High CO2 Concentrations
Authors: Chapoy Antonin , Burgass Rod , Haghighi Hooman , Tohidi Bahman 
Published: January 2012

Abstract
In this communication we present experimental techniques, equipment and thermodynamic modelling for investigating systems with high CO2 concentrations, including gas reservoirs with high CO2 content and/or CO2-rich systems from capture processes. The experimental equipment consists of high pressure (1,000 bar) equilibrium cells operating over a wide temperature (-80 to 200 °C), GC, chilled mirror and Laser Hygrometer for water content measurements. A thermodynamic model based on Cubic-Plus-Association (CPA) equation of state has been used in modelling phase behaviour of CO2-rich systems. The hydrate-forming conditions are modelled by the solid solution theory of van der Waals and Platteeuw. The reliability of the thermodynamic model was evaluated using vapour – liquid equilibrium data.
CO2 is a partially polar compound present in many hydrocarbon reservoirs. Its concentration in some hydrocarbon reservoirs is very high, demanding accurate experimental data and thermodynamic modelling. Another important application is modelling phase behaviour and properties of CO2-rich systems from capture processes for transportation and storage.
The results show that the developed model, combined with a reliable database, is a powerful tool for modelling complex systems. The resulting thermodynamic model is able to conduct various calculations, including; gas solubilities in aqueous and non-aqueous phases, water content in CO2-rich systems, hydrate stability zone in the presence of methanol and/or glycols, dehydration requirements for preventing hydrate formation in gas or CO2-rich phase, and a large number of other calculations. The results of the predictions are compared with experimental data, demonstrating reliability of the techniques developed in this work.
CO2 coming from capture processes is generally not pure and can contain impurities such as water. In a typical gas sweetening unit, the acid gas stream will be saturated with water. The presence of water can result in ice and/or gas hydrate formation at low temperature conditions and cause blockage.
Optimizing Asset Lifecycle Maintenance Using A Streamlined RCM Method
Authors: Pangawijaya Eric 
Published: January 2012

Abstract
Description:
How often an asset fails and its associated cost depends on the quality of the maintenance program adopted by the asset owner. Most organizations use a CMMS (Computerized Maintenance Management System) best suited to the size of the project and assets to be maintained. In larger organizations, the choice of CMMS most often defaults to a standard package used across all their assets.
During the initial stages of a project lifecycle, the key functions for maintenance are often driven by the OEM in order to comply with the warranty clauses of their equipment. With time and better understanding of equipment behavior, the CMMS needs to be optimized to match the operators’ goals for their asset.
The control of maintenance functions is a complex problem. The time scales and functions vary, as does the complexity of decision-making. The complexity is caused by numerous output factors, such as safety, availability, reliability, quality and longevity. Each of these factors is in turn influenced by numerous input factors.
Ten Year Evolution and Field History of Design Changes for a Torque and Drag Reduction Performance Drilling Sub
Authors: McCormick John E. , Evans Chad D. , Kirkpatrick Cameron 
Published: January 2012

Abstract
The need for advances in the robustness and versatility of downhole tools is increasing as well geometries become more complex. With more challenging wells being drilled everyday even the most advanced tools need to be improved upon. This is typically where research and development (R&D) engineers play a vital role. They work closely with operations personnel to create and constantly improve downhole tools. As service companies typically are the R&D arm of the oilfield, tools and improved designs are primarily market driven. This paper will explore the development of a mechanical friction reduction tool (MFRT), which is sometimes necessary in ERD and complex geometry wells to overcome torque and drag limitations.
A tool starts as a concept that will overcome an obstacle when drilling or completing a well or ensure the safety and cost effectiveness of an operation. The R&D engineers take this idea and develop it into a first generation tool. They then meet with their managers, fellow engineers and operations managers to discuss the concept, the functionality, and the technical and financial viability of the tool. The engineers then go back and refine the design of the tool, after which is scheduled another design review meeting. This process undergoes several iterations, with more technical and managerial personnel involved each meeting, until a final design is agreed upon. This design review process is intended to manage the progress of the design, keeping check on the financial, functional, and implementation aspects of the tool.
Once the first articles have been manufactured and field trials run, these tools are run commercially. Close watch is kept on the use of the tools and any issue and need for improvement are addressed by the design team. Constant assessments of the tool’s performance are carried out. This paper describes the development of a tool over a ten year period using the MFRT as a case study. We look at specific changes made to the tool, why these changes were implemented, and field trial results for the different modifications.
Investigation of Indigenous Bacteria in Water-dissolved Natural Gas Fields for Preventing Microbial Clogging of Injection Wells
Authors: Wakizono Ryo , Sugai Yuichi , Sasaki Kyuro , Higuchi Yasunori , Muraoka Noriyuki 
Published: January 2012

Abstract
The brine that has been produced from water-dissolved natural gas reservoirs should be returned into reservoirs after the resources have been extracted to prevent the subsidence. However, the re-injectivity of the brine declines gradually; therefore, re-injection wells should be maintained by backwashing treatments. Colloidal materials like biofilms can be observed in solid materials that have been produced by the backwashing from the re-injection wells.
Because the brine contains not only dissolved natural gas but also high levels of iodine, the iodine is also extracted from the brine chemically using sulfuric acid and oxidizing agent; therefore, re-injected brine contains sulfate and dissolved oxygen abundantly. These chemicals may stimulate the metabolites of microorganisms that have influences on the clogging; therefore, we considered the influences of these materials on microorganisms that may cause the clogging in this study.
Column experiments were carried out using sand and brine that were collected in the gas field. The columns that the brine including indigenous microorganisms, dissolved oxygen and sulfate was injected into were clogged significantly. Iodide-oxidizing bacteria, iron-oxidizing bacteria and sulfate-reducing bacteria were found specifically in clogged columns, suggesting these microorganisms had influences on the clogging. In particular, Iodide-oxidizing bacteria were also found in original brine; therefore, it was assumed to have an important influence on the clogging.
Iodide-oxidizing bacteria convert iodide into iodine that corrodes iron in the sand under the presence of dissolved oxygen. Iron (II) ion that has been eluted from the sand is oxidized to iron (III) ion by iron-oxidizing bacteria under the presence of dissolved oxygen. Iron (III) ion forms ferric hydroxide colloid in the brine and it causes the clogging of the porous media.
From these mechanisms of the clogging, we can suggest removing dissolved oxygen as the most feasible countermeasures for the clogging.
Reservoir Characterisation of the Low Permeability Siliceous Barmer Hill Formation, Barmer Basin, India
Authors: Chowdhury M. , Singhal M. , Datta S. , Sunder V. , O’Sullivan T. , Hansen P. A. , Burley S. D. 
Published: January 2012

Abstract
The Barmer Hill Formation is a Palaeocene lacustrine deposit occurring in the Barmer Basin of northwestern India. The lake developed entirely within the rift basin and its sediments comprise a complex of shallow to deep water deposits. In much of the northern part of the basin, the upper part of the Barmer Hill Formation is characterised by the presence of a finely laminated siliceous unit. Millimeter scale laminations in this unit consist of highly siliceous lithofacies, interbedded with organic material and subordinate clay. This syn-rift unit varies from 50 to 250 meters in thickness and is known to be hydrocarbon-bearing through much of the basin from numerous well penetrations. It is characterised by high porosities (25-35%) but low permeabilities (0.1-4mD). Hydraulic fracturing well operations in this reservoir had produced stabilized oil flows in the range of 30-250 BOPD demonstrating commerciality.
Detailed reservoir characterisation of this siliceous Barmer Hill Formation unit has been carried out in advance of planned field development and further hydraulic fracturing activities. Outcrop samples and subsurface core data have been integrated to understand the unusual properties of the reservoir. Scanning Electron Microscope (SEM) examinations of subsurface core samples reveal microcrystalline quartz (chalcedony) as the main mineral present, whereas equivalent outcrop samples are dominated by both Opal-CT and chalcedony and contain opaline diatom tests. This integration of core and outcrop data indicates that the siliceous unit was likely formed through diagenetic alteration of biogenic silica from opal-A through opal-CT to microcrystalline quartz. Early oil migration may have helped to preserve the porosity in the subsurface resulting in high porosity-low permeability reservoir properties unusual for microcrystalline quartz.
Geomechanical properties were assessed from bulk rock X-ray diffraction (XRD) information and core data to identify the most suitable intervals for hydraulic fracture initiation. This XRD data has been used semi-quantitatively to predict reservoir brittleness using a ternary plot of quartz-carbonate-clay abundance whereas geomechanical properties viz. Poisson’s Ratio (PR), Young’s Modulus (YM) and Unconfined Compressive Strength (UCS) of each units are estimated from wireline density-sonic log data and calibrated with core plugs to quantify the fracability of the units. The in-situ stress orientation is estimated from image log interpretation to predict fracture propagation orientation and aid optimal well placement.
This integrated workflow combining geological, petrophysical and geomechanical properties for reservoir characterisation is being applied to support commercial development of the hydrocarbon resources of this low permeability siliceous unit.
Sustainable Development with First CDM Project In Thailand E&P
Authors: Getwech Chiratthakan , Pornsakulsakdi Lawan 
Published: January 2012

Abstract
PTTEP Siam Limited (PTTEPS), a subsidiary of PTT Exploration and Production Public Company Limited (PTTEP), has pioneered a Clean Development Mechanism (CDM) project that takes aim at recovering and then using associated gas from the oil wells of Thailand’s Sao Thian-A field. Situated in the S1 Concession area in Sukhothai Province, the Sao Thian-A field has produced approximately 1.5 MMscfd of associated gas and 1,900 BPD of crude oil. Without a CDM project, this associated gas, comprised primarily of methane with lesser amounts of other energy rich hydrocarbons, would have simply been continued to have been flared and more greenhouse gases would have been released into the atmosphere.
At its core, the CDM project involved the installation of a gas treatment system to filter out hydrocarbon droplets from the associated gas prior to its internal use and sale to external facility. The CDM Project has indeed helped the whole facility become more economically viable for further investment in similar such additional CDM units.
The CDM project was approved by the Designated National Authority of Thailand in December 2010. Key benefits of applying CDM to the overall Project included reduction of GHG emissions, which in turn, increased the global energy efficiency of the oil field; the reduction of non-renewable energy use; and the encouragement of best practice of associated oil management among oil and gas operators in Thailand. In addition to revenue gain from carbon emission reduction trading, this Project has fulfilled score-based criteria for national sustainable development evaluation: natural resources and environment, social, technology transfer and development, and economic growth.
This CDM application within a petroleum exploration and production project is Thailand’s first! If this Project receives final approval and is officially registered by the CDM Executive Board, it will no doubt encourage other operators in Thailand to initiate their own participation in this business.
History Matching and Permeability Increases of Mature Coalbed Methane Wells in San Juan Basin
Authors: Moore Robert L. , Loftin Debbie , Palmer Ian 
Published: January 2012

Abstract
We discuss detailed well history matches, from the San Juan basin, of coalbed methane (CBM) gas rates, water rates, and pressures. In the sweetspot (fairway) the matching includes permeability that increases strongly with depletion, and is assumed to be exponential, as indicated by independent well tests spaced over time. The permeability increases are well matched by the Palmer-Mansoori (P-M) model. We present statistics of permeability matching to field results by the P-M model in the fairway. First, initial cleat porosities are 0.05–0.17% and consistent with porosities derived from observed water rates. Large permeability increases are not consistent with large cleat porosities. Second, the permeability increase ratio, defined by the maximum permeability reached over the permeability at initial reservoir pressure, varies from 16–170. Third, the matrix shrinkage parameters agree with a recent lab measurement. Fourth, cleat-volume compressibility mostly increases with depletion, when matrix shrinkage becomes dominant and cleats open wider. Last, in many wells north-east of the fairway the perm increase with depletion was found to be similar to that seen in fairway wells. This again suggests cleat porosities less than roughly 0.3%.
At low reservoir pressures (&lt;300 psi), we find that the exponential permeability increase flattens. This we have interpreted as coal failure due to stress changes instigated by matrix shrinkage. In fact the P-M model for stress changes can predict the onset of shear failure with depletion, which generally agrees with the timing of the flattening. This adds validity to the general applicability of the P-M model in CBM plays. The modeling is important in being able to better forecast gas rates and estimated ultimate recovery (EUR) for CBM wells, which can remain profitable for decades.
Best Practices and Lessons Learned in the Construction and Maintenance of a Complex Gas Asset Integrated Production Model (IPM)
Authors: Amudo C. , Walters M. S. , O'Reilly D. I. , Clough M. D. , Beinke J. P. , Sawiris R. S. 
Published: January 2012

Abstract
Petroleum Experts’ Integrated Production Model (IPM) suite of software is widely used in the E&P industry especially for project evaluations that require integration of both surface and subsurface models. There is evidence in the literature to show diverse applications in field development planning, integrated forecasting, surveillance and production system optimization. Perhaps less reported are the lessons learned and best practices in using the IPM software. This paper focuses on these issues using Chevron’s IPM model for some of its largest gas fields.
The Non-Operated Joint Venture (NOJV) Subsurface Team began developing an IPM model for one of its biggest gas assets in 2005. With explicit modeling of critical components like compressors, dozens of wells and reservoir tanks, platforms, fluid characterisation, gas-water contact movement, pipelines, sub-sea manifolds and separators, this is arguably the largest and most complex IPM model in Chevron. The model continues to play a critical role in Chevron’s effective capital stewardship of the gas asset. The need to maintain the credibility of this model cannot be over-emphasized, and the model has undergone several phases of enhancement to ensure that it continues to meet business objectives.
This paper describes some of the best practices and lessons learned in constructing and maintaining a complex IPM model. It is intended as a resource for IPM practitioners. Examples cover all aspects of the IPM from the non-technical (e.g. framing the problem, case definition and naming convention) to the technical (e.g. model construction, model maintenance, software limitations, constraint violations, production optimisation and quality assurance checks).
The Successful Planning and Implementation of High Angle Deviated HPHT Well Testing in the Sour Naturally Fractured Gas Reservoir: Case Study of S-3 Well
Authors: Akbar Dino , Simanjuntak Timur M , Kristianawatie Nova 
Published: January 2012

Abstract
In the oil and gas industry, reservoir pressures exceeding 10,000 psi and temperatures exceeding 300°F are categorized as high pressure and high temperature (HPHT) reservoirs1. Testing and design for HPHT wells require special equipment and treatment, including the use of technology that can withstand high pressure, high temperature, H2S and high CO2 content.
S-3 gas well is a high deviated (inclination: 88°) well with open-hole completion. Pressure and temperature of S-3 well are estimated at 10,625 psi and 408°F respectively. Based on gas chromatograph analysis, the H2S content is around 100 – 250 ppm and CO2 content around 30%.
Due to low matrix permeability indication around S-3 (&lt;5md), a Modified Isochronal Test (MIT) test was chosen for S-3 to shorten testing times. Pressure, rate and temperature were measured using surface recording equipment due to the availability of tools that meet pressure and temperature rating. Static reservoir pressure was predicted using Cullender and Smith method. Nodal analysis software and WHP vs BHP relationship from S-1 well is used to calculate IPR and Deliverability curve. Permeability and skin factor was estimated from drawdown analysis.
This paper presents the history and a case study of S-3 well testing, including planning, testing design, execution, data analysis, interpretation, and lessons learned from the well. This will be beneficial for designing the next well-testing and optimizing similar HPHT wells.
Finally, as a result of S-3 well testing, it was found that AOF from pseudo pressure function was around 155 MMscfd, kh 3315 md.ft, while the total number of skins was 29. There is also an indication of fracture occurrences around S-3.