bluuebunny/crossref_metadata_2025_split huggingface dataset:
Established Knowledge Management (KM) Communities of Practice: Moving Across the KM Product Life Cycle
Authors: Burress Charlotte , Paylow Kevin 
Published: October 2009

Abstract
Communities of practice (COPs) are a sub-set of knowledge management (KM) that provide a channel for people to interact and collaborate to achieve common goals. Benefits of COPs include global problem solving, leveraging best practices, time savings, and identifying future leaders. Since the global adoption of COPs and KM efforts in our industry, most companies have seen a rapid decline in community activity after initial deployment resulting in KM becoming a failed corporate initiative. In the product life cycle, these communities did not make the jump from the introduction to the growth phase. Some KM efforts and COPs do survive to the growth phase; however these established communities are not progressing along the life cycle curve due to little or no continual growth in activity levels and early adopters representing the bulk of users. The challenge for established COPs is to not just sustain activity levels but to create value for more users which will thus enhance the COPs’ significance to the global organization.
This paper discusses the effects of several methods used to progress COPs along the product life cycle, moving users from casual bystanders to active participants in discussion. Specifically, adopting Web 2.0 technology provides new ways to engage users to define value-added content, leverage social networking, and embrace collaboration. In addition to implementing new web-based technologies, a full-time knowledge transfer facilitator or knowledge broker fosters the growth of the community. Lastly, over time established COPs tend to gel around certain employee populations, and the knowledge broker must break these arbitrary barriers and engage other users in the organization such as supply chain management or laboratory personnel. With the combination of these methods, the COPs have been shown to progress along the product life cycle with increased adoption and added value for the organization.
Development of a Geomechanical Reservoir Modelling Workflow and Simulations
Authors: Bostrøm B. 
Published: October 2009

Abstract
A Geomechanical Earth Model (GMEM) is wanted for every field development and should be maintained for the life-time of the field. These models are needed in order to contribute to safe and optimum drilling and production in depleting and complex reservoirs. This strategy is only possible if an automated workflow is developed.
Links between the stress simulator Abaqus and the geological software Irap RMS and between Abaqus and the reservoir simulator ECLIPSE are established in order to have; (1) faster and better generation of geomechanical reservoir simulation models, (2) to better account for geomechanical effects in the reservoir simulation and 4D feasibility studies. Abaqus scripting interface is used to link Irap RMS and Abaqus. The link consists of a set of Python scripts that rebuilds the reservoir geometry in the CAD, meshing and visualization program Abaqus/CAE. This is believed to be a unique feature of the developed workflow as opposed to earlier developments that reuse the reservoir grid. In addition, a link between Abaqus and ECLIPSE is developed transferring reservoir pore pressure data, initial porosity and degree of water saturation between ECLIPSE and Abaqus through the file system. Verification and demonstration of capabilities of the developed workflow is done using a faulted North Sea oil and gas field.
Technology for Determining Reservoir Pressure from Mud Log Gas Improves Mature, Tight Gas Asset Performance: A Case Study of Ada Field, North Louisiana
Authors: Lapierre S. G. , Prine B. H. , Pickrel H. M. 
Published: October 2009

Abstract
A mature tight gas field in North Louisiana that experienced dwindling performance and erratic predictability spurred the creation of an alternative technology that boosted production rates and minimized completion costs. An average production rate uplift of 108% shown on three wells resulted from modifications to mud logging operations; careful interpretation and integration of data; and the addition of new, proprietary transforms. The resultant technology provided a variety of useful information with little or no additional cost or mechanical risk.
When conventional wireline technology proved both technically and economically unsuccessful, an alternative technology was needed to determine reservoir pressure from mud log gas with sufficient resolution to support zone selection, completion design, and the identification of bypassed pay. This document describes the proprietary technology and a variety of specific applications employed by the development team. Production logs and conventional pressure measurements demonstrate the performance increases achieved by incorporating this technology into the development program.
How to Avoid Shale Intervals in the Grane Reservoir by Utilizing Real-Time Geosteering Data and Openhole Sidetracking
Authors: Bakka Marit , Rønning Johan Knut , Sæbø Asbjørn , Jensen Kåre , Sæverhagen Erland , Erichsen Cato 
Published: October 2009

Abstract
The Grane reservoir consists of massive turbidite sand deposits with intercalated shale bodies related to deformation of the reservoir and encasing shales. When drilled, these shales often become unstable after some time, resulting in packoff and collapsed hole, leaving planned produced intervals unrecovered. To maintain oil production from the Grane field, wells are drilled to compensate for declining production. Different strategies to stabilize the shale intervals have been unsuccessful.
Real-time geological information collected while drilling are interpreted and used to understand the shape and extension of the unstable shale bodies in the context of the seismic data. This interpretation is based on azimuthal resistivity and gamma as well as extra deep reading resistivity. Using this information, the drilling system is pulled back into the sand section in front of the unstable shale and an openhole sidetrack is performed. Based on the updated interpretation of the geological data gathered while drilling through the shale, the new wellpath is designed to avoid the shale interval and penetrate reservoir intervals farther out.
Openhole sidetracking is performed using the main 3D rotary steerable system (RSS) drilling bottomhole assembly (BHA). No cement plugs, ramps or kickoff BHAs are required, resulting in significant time savings. This method is proven on a number of wells and is today a part of standard well-planning on Grane.
The applied method is so far the most efficient way to increase the length of the productive intervals and has proven to be a reliable and low-risk operation with a high probability for success. This paper will describe how the combination of real-time geological information and possibilities to perform openhole sidetracks are systematically used to increase the reservoir sections on Grane.
Multicomponent Advisory System Can Expedite Evaluation of Unconventional Gas Reservoirs
Authors: Wei Y. N. , Cheng Kun , Holditch S. A. 
Published: October 2009

AbstractProducing natural gas from unconventional gas reservoirs (UGRs) is currently very important to the energy mix in North America and will be of increasing importance to the global energy industry in the coming decades. Currently, most of the expertise in UGR development resides in the United States. There is a need to make the expertise and technology required to drill, complete and stimulate UGRs more accessible to the engineers outside of North America who need this information. It is also important to capture knowledge and use it for the training of young engineers. To begin addressing these issues, we have developed the UGR Advisor.We define our advisory system as a detailed, multi-component computer program designed to provide advice, recommendations, and/or best practices for a broad array of issues that arise in developing a UGR. We first begin the process by determining an analog reference basin (or formation to) the target basin (or formation). A reference basin is a basin in North America that produces substantial volumes of unconventional gas and has a large volume of information about the basin in the petroleum or geologic literature. A target basin is the basin that we are currently interested in evaluating or developing.Once the basin and formation analogs are found, UGR Advisor can be used to obtain advice on how to drill, complete and stimulate the target formation. We have used the petroleum literature to determine best practices and have developed logic to provide advice to the user that is compatible with the published best practices. We have combined knowledge from the petroleum literature and interviews with experts with detailed calculations to build the program, which includes subroutines that evaluate the formation, recommend drilling schedules, suggests completion and production practices, and estimate economics, all from a single-input system for data collection.
Drilling and Evaluation Technologies Extend Operating Limits in Challenging High-Pressure Deepwater Environments
Authors: Denham Waitus , Donadieu Brian , Lee Ernest , Mathur Rohit , Srinivasan Ananth 
Published: October 2009

Abstract
With the world's dependence on hydrocarbon-based energy sources driving global demand, new drilling opportunities require technological innovation to increase efficiencies and optimize production. Some newer drilling operations, particularly in the deepwater arena, involve extreme environments such as ultra-high pressures and demand different approaches to ensure flawless execution. This paper presents the variety of challenges, critical success factors, and lessons learned when drilling these ultra-high pressure wells in the Gulf of Mexico's demanding waters. With downhole pressures approaching 30,000 psi and escalating rig costs, the need for dependable rotary steerable systems (RSS) along with advanced formation evaluation technology is needed now more than ever.
With well depths surpassing 30,000 ft below the mudline and increasing water depths, ultra-high-pressure requirements present a new and challenging frontier for both operators and service companies. These new environments demand advances to existing technologies’ operational limits to endure such pressure extremes, while also accurately positioning the wellbore in the reservoir and obtaining critical geological information as the well is drilled.
A recent example in this pressure regime in the deepwater Gulf of Mexico will be reviewed. In cases, pressure limits of the currently available technology are extended while successfully meeting drilling and evaluation goals. Emphasis is placed on the need for operators and service companies alike to focus on thorough pre-job planning while paying close attention to complete system pressure ratings, high-pressure tool inventory management and detailed reviews. As always, communication is one of the critical success factors to ensure success.
The drilling and evaluation technologies delivered real-time formation pressure and geological information, along with continuous directional control, allowing operators to make vital decisions while drilling. This real-time decision-making capability reduced the time required to execute casing point selection and subsequent sidetrack plans.
Additionally, by following an application-based philosophy to technology selection, critical drilling and evaluation questions were answered in real time, reducing risks for nonproductive time (NPT) in these extreme environments. The case results showcased the ability to set a new performance standard, extend the conventional operating envelope, and deliver answers while drilling.
Coupled 3D Numerical Investigation of Hydraulic Fracture Cleanup for Both Slickwater and Gelled Fluids
Authors: Wills Hector A. , Miskimins Jennifer L. , Kazemi Hossein 
Published: October 2009

Abstract
This paper presents the results a systematic study on fracture cleanup using a two-phase 3-D numerical simulation model specifically developed for this purpose. Previous simulation models consider that the hydraulic fracture is already created and the state of pressure and water saturation around the created fracture (invasion profile) could be replicated by a controlled waterflood. For our work we adopted a different perspective where the invasion profile around the fracture is directly linked to the leakoff of fracture fluid during creation. In other words, a fracture growth model have been linked directly to a finite difference simulator.
All simulations are performed in three stages. First, a fracture creation period is applied, second is a shut-in period and finally, a flowback period. In all these three stages the link to/from the reservoir is through source terms, which varies according to the simulation stage. During fracture creation and shut-in, the created fracture is considered one layer and acts as a boundary condition for the reservoir; then for flow back the fracture is discretized on the z direction to enhance the resolution in the fracture medium. Relative permeability curves for the fracture medium and reservoir medium, are based on real laboratory data. Cases were run for both slickwater and gel-based fracturing fluids.
A base case analysis based on a low permeability sandstone reservoir is shown, followed by sensitivities that include: applied pressure drawdown during production; shut-in time between fracture creation and production; interfacial tension between the gas and aqueous phases; placement of perforations across the entire producing interval versus the upper portion of the reservoir; and different gel concentrations. Results show the pressure drawdown, shut-in times, and perforation placement all have significant effect on fracture face damage and clean-up potential.
Critical Poroviscoelastic Anisotropic Evaluation of Anelastic Strain Recovery Test
Authors: Hoang Son K. , Abousleiman Younane N. 
Published: October 2009

AbstractThe importance of accurate determination of in-situ maximum and minimum horizontal stress orientations and magnitudes can never be over-emphasized in geomechanics-related operations in the oil and gas industry. In this paper, the Anelastic Strain Recovery (ASR) test is revisited, and for the first time, the analytical solution for the relaxation evolution of recovered cores from deep wells is extended to fully cover the poroviscoelastic nature of formation rocks, i.e., viscoelasticity of not only the porous matrix moduli but also the grain bulk modulus, as well as a realistic description of the coring, retrieving, and testing processes, i.e., practical time-dependent stress and pore pressure boundary condition evolution instead of the common Heaviside step unloading used in previous studies. Furthermore, the solution also incorporates material transverse isotropy which is frequently encountered in sedimentary formations yet regularly overlooked in previous works. The study identifies several key parameters for accurate determination of in-situ horizontal stresses from ASR test and serves as a reference for future operations.
Causes of Severe Magnetite Formation During Underbalanced Drilling and Practical Mitigation Strategies
Authors: Ezzat A. M. , Ezell R. G. , Turner J. K. , McNealy R. , Mason S. 
Published: October 2009

Abstract
While drilling underbalanced with potassium chloride (KCl) brine and injected nitrogen generated by a membrane filter, black precipitate and heavy scale deposits on the drillstring were observed. The brine was treated with phosphate ester and an amine-based inhibitor at the optimum pH range to mitigate corrosion. A robust onsite monitoring program of the fluids’ properties and the inhibitor concentration was carried out to help ensure proper control of corrosion during the underbalanced drilling (UBD) operations
Analysis of scale-like deposits scraped off the drillstring was predominantly magnetite with trace amounts of siderite and KCl. Little to no scale was seen on the drillstring below the nitrogen injection point indicating that the injected gasses seemed to be a contributor to the issue.
Examination of the drillstring surfaces beneath these scales and API corrosion rings did not exhibit metal loss or pitting indicating these scales were not consistent with corrosion. Further, scale formation continued to be observed as drilling continued under nil oxygen conditions when cryogenic nitrogen was employed and oxygen levels of less than 1% were maintained. Laboratory and field engineers were deployed to collect samples of the brine used for drilling, the scale deposits, solids recovered at the shale shaker screens, and the fluid returns from the wellbore. The precipitate was mostly amorphous iron oxide with magnetite (i.e., combination of Fe (II) and Fe (III) oxides that is ferrimagnetic in nature).
This paper will present the field and lab data generated which helped in discovering the root cause of the problem and developing practical solutions.
The Systematic Application of Root-Cause Analysis to Failures of Intelligent-Well Completions
Authors: Beyer Eric , Barrilleaux Mark , Hother John , Keates Tom 
Published: October 2009

Abstract
When a producing well fails, the engineering team needs to diagnose the failure quickly, in order to determine the best course of remedial action. This is particularly important with an early-life failure when other wells are still being installed using the same design, raising legitimate concern that the failure may be repeated in those other wells. In practice, diagnosis of a failure when evidence is incomplete, and even inconsistent, can lead to conflicting or incorrect conclusions. A systematic method of root cause analysis forces the discussion to converge on a useful outcome. This paper illustrates how such a method was applied, using a fault-tree structure, to analyze failures in two subsea multizone intelligent completions.
The objectives of the analysis were to -
understand the failures as fully as possible; determine what steps are needed to prevent the failures from recurring on subsequent installations; determine what other tests may be useful to help understand the problem.
The work started by collecting and reviewing the evidence (written reports, and links to knowledgeable people), and defining the symptoms of failure. Then Fault Trees were constructed from all the potential failure modes that fit the symptoms of failure (in this example, 32 in total). These were then used in a structured workshop session to review all those potential failure modes. Those that did not fit the evidence were discarded, in this example leaving just 4 Possible Causes by a process of elimination.
The detailed review of processes and controls required to understand the circumstances of failure was found to be a useful way of identifying improvements to Engineering Processes (documentation control, specification and engineering management) in addition to design and operational issues.
Extra tests were then identified to confirm each Possible Cause, providing further elimination. A structured comparison to find analogues in other similar projects provided further insight. Finally, further characterisation tests and other actions were identified to help avoid future failures. Specific recommended actions (in this example, 32 in total) were identified to address the Possible Causes and so prevent the failures from recurring on subsequent installations.
A FMECA constructed during the well design phase was also consulted to determine any correlation between the failure modes identified therein and the observed failures in the two zones. The conclusions from the FMECA were also examined to identify whether there were any outstanding recommendations or remedial actions.
The study showed that a systematic application of root cause analysis, using fault trees as the underlying structure, can be very effective in focusing engineering effort on resolving the important issues and avoiding time-wasting distractions.
Field Cases: Nonisothermal Behavior Due to Joule-Thomson and Transient Fluid Expansion/Compression Effects
Authors: App J. F. 
Published: October 2009

Abstract
Field cases illustrating nonisothermal behavior due to Joule-Thomson expansion and transient fluid expansion/compression effects are presented in this paper. Nonisothermal effects are particularly noticeable in high drawdown completions due to Joule-Thomson expansion of the reservoir fluids. Depending upon the pressure range and hydrocarbon composition, Joule-Thomson expansion can result in either a heating or cooling effect. At high pressures, Joule-Thomson expansion normally results in an increase in temperature for oil and gas reservoir fluids compared to a temperature reduction for low pressure gas. Field cases of high drawdown completions are presented; the first is a high pressure oil production test in which a temperature increase of 10°F was observed for a 6,000 psi drawdown and the second is a low pressure gas production test in which a temperature reduction of 38°F was recorded for a drawdown of 3,080 psi. The pressure and temperature profiles for each case were simulated with a 1D radial thermal simulator capable of modeling thermal effects due to Joule-Thomson expansion and viscous dissipation. Nonisothermal behavior is also observed after rate changes due to the rate of fluid expansion or compression. These nonisothermal effects, or temperature "jumps", are transient in nature and the direction of the temperature change depends on whether the fluid is expanding or being compressed. The most noticeable illustration of a temperature jump is at the commencement of a buildup. A field case is presented and modeled with a thermal simulator to illustrate this nonisothermal behavior.
Perforator Performance Study Determines Optimum System and Achieves Field Performance Projections
Authors: Rook Melvyn , Haggerty Dennis , Manning Doug , Quattlebaum Clinton 
Published: October 2009

Abstract
The selection of the appropriate perforating gun system provides an essential element of maximizing the potential recovery of an oil or gas field. Perforating guns are often selected with minimal knowledge of the likely downhole charge performance, which commonly includes API 19B Section I test data that evaluates only cement penetration among competing systems. Unfortunately, cement penetration does not always correlate to the penetration in a downhole environment or inflow potential.
A study was recently conducted to evaluate the charge performance in downhole conditions for a gas reservoir in a perforation flow lab (PFL) based on API 19B Section IV1 methods to identify the best performing charge design for a 3-3/8-in. 6 spf gun system. The study evaluated the effects of cement sheath thickness and casing wall material (hard stainless steel vs. carbon steel). The magnitude of pressure in the simulated wellbore was varied to compare slight underbalance with high underbalance to determine the effect of offline perforating limitations. In addition, the separate testing variable of target core diameter was investigated and resulted in a dramatic effect on the perforator performance.
These testing results identified the optimum gun system for use in the Talisman Bunga Orkid gas field. The productivity estimates derived during the charge evaluation were used to validate inflow models, which to date closely match actual production.
An advanced evaluation of perforating systems can provide valuable insight into what is not always intuitive from available published cement penetration data and can be used to further advance production models. The parameters used in the models should be well understood to confidently predict the perforation hole size, penetration, and flow performance.