bluuebunny/crossref_metadata_2025_split huggingface dataset:
Industry Guidance for Reporting Environmental, Health and Safety and Social and Economic Factors
Authors: Janus Bertrand , Murphy Helen 
Published: October 2014

Abstract
In 2015 IPIECA, API and OGP will publish the third update of the Oil and gas industry guidelines on voluntary sustainability reporting. Originally published in 2005, with the second edition released in 2010, this guidance document is the principal industry-specific framework for use by oil and gas companies reporting on environmental, health and safety, and social and economic performance. Since 2002, when the development process began, IPIECA, API and OGP have drawn on the very best technical expertise from within the industry to bring precision to indicator definitions and sustainability reporting protocols. This facilitates benchmarking and aggregation of data, enabling greater consistency with the aim of driving performance improvement across the industry.
Now, IPIECA, API and OGP are working on a third update which will revise some of the technical indicators for use in reporting sustainability performance. Industry reporting is continuously progressing and issue areas are not all at the same level of maturity or developing at the same pace. Indicators can evolve based on technical and/or industry developments, and alignment with external reporting frameworks as well as company needs and stakeholder interests.
The Global Reporting Initiative (GRI) produce the most widely used global cross-sector framework for sustainability reports and in 2013 released the fourth version of their guidelines. The updated framework contained a number of disclosures that have a low value-to-cost ratio for oil and gas companies to report against, particularly those related to remuneration and supply chain. Given these developments, it is essential to ensure that the Guidance continues to provide a robust framework for companies in the sector to guide the structure and content of their reports, particularly for new reporting organizations.
The 2015 edition will encompass a number of technical updates including: –providing more detailed guidance on Scope 2 and Scope 3 reporting of greenhouse gas emissions–maturing of specific elements (the Guidance contains three levels of elements: Common Reporting Elements that are well established; Supplemental Reporting Elements that enable greater depth of reporting; and Other Reporting Elements that are less established but emerging.)–update of indicators E6: Freshwater and E9: Discharges to water in light of current industry practices and external developments–possible addition of an indicator on decommissioning
This paper will outline the drivers for maintaining this industry guidance document, the update process undertaken and detail the specific technical updates to the 2015 edition.
Improved Reservoir Description from Pressure Transients
Authors: Tovar Raul 
Published: October 2014

Abstract
This paper describes an innovative approach to integrate pressure transients with numerical reservoir simulation models. The derivative plot, from analytical Pressure Transient Analysis, is used to aid history match pressure transients measurements directly into the production history matched numerical reservoir simulation model. Most often only the extrapolated pressure is explicitly (as a single point measure) incorporated for history matching the reservoir material balance. Characterization of heterogeneity and complex reservoir features such as barriers, and aquifers are subjectively incorporated or inferred in the simulation model from analytical solutions. Furthermore analytical techniques cannot account for all geometrical descriptions and are limited at describing multiphase flow and well interference.
This methodology expands on traditional reservoir simulation history matching by incorporating a stepwise approach in matching geological features on an already built conventional reservoir simulation model. An actual field example is discussed to illustrate on how this methodology populates properties away from the wellbore in terms of grid blocks based on the pressure diffusion regimes of the derivative plot rather than using averaged terms such as the analytical radius of investigation or matching it in a Cartesian plot. It consists of adjusting the simulation model sequentially: wellbore storage, near wellbore permeability (kh and skin), permeability away from the wellbore and boundaries to match the complete spectrum of the observed pressure derivative. Additional field examples illustrate the benefits of this methodology in the context of a multi-well development scenario: The presence of a gas injector that was initially interpreted as a closed boundary and the expected interference response between multiple producing wells.
With this approach an improved description and reduced uncertainty is obtained for the reservoir simulation model, providing a more accurate production forecast to estimate reserves, optimize the reservoir management plan and/or to evaluate additional development scenarios.
Fiber Optic DAS and DTS in Multicluster, Multistage Horizontal Well Fracturing: Interpreting Hydraulic Fracture Initiation and Propagation Through Diagnostics
Authors: Sookprasong P. A. , Hurt R. S. , Gill C. C. , LaFollette R. F. 
Published: October 2014

Abstract
The application of high-resolution fiber optic distributed acoustic sensing (DAS) and distributed temperature sensing (DTS) during multistage hydraulic fracturing has increased in recent years. However, fiber optic has been used for communication networks, surveillance, and monitoring and diagnosing wellbore integrity for quite some time. The technology has also been used to diagnose reservoir and well performance, e.g., production and injection profiling.
Optical fibers were placed in a small stainless steel tube, which was clamped to the casing while running in the hole in a horizontal unconventional gas well. The casing was then cemented in place, and fracturing treatments were completed by limited-entry techniques using the "plug & perf" process, resulting in multicluster (each stage), multistage fractures. Perforations were placed on the topside of the casing, oriented to avoid damaging the optical fiber (zero degree phasing, at 5 shots per foot, one foot per cluster).
This paper shares images and results from DAS and DTS data that allow for interpretation of fracturing treatments in multicluster, multistage horizontal wells. The images illustrate the dynamic nature of the spatial and temporal fluid distribution pertaining to initiation, propagation and arrest of hydraulic fractures during simultaneous stimulation of multiple clusters. First, fracture initiation appears not only during early time, as expected, but also late time initiation events may develop in previously dormant clusters. Second, propagation of multiple fractures can occur randomly within a cluster array, and these multiple fractures are sometimes in close proximity to one another. Third, dominant clusters are often observed during stimulation. Further, during the treatment cycle, the position of dominant cluster(s), within a given stage, may actually change. We leverage these observations with various other data sources in a modeling exercise to demonstrate the implications of unequal fracturing fluid distributions on propped fracture performance.
Low Impact Testing of Oil Field Access Roads: Reducing Environmental Impacts in Desert Ecosystems
Authors: Platt Frank Martin , Burnett David B 
Published: October 2014

Abstract
This project presents results from one part of the Disappearing Roads (DR), a multi-year project to design, test and evaluate multiple temporary and permanent road materials for use in harsh environmentally sensitive areas. DR is a critical component of the joint industry project Environmentally Friendly Drilling Program (EFD).
The DR project included a nationwide University competition sponsored by Halliburton to come up with potential designs as well as actual field trials of commercially available products, while the goal of the RPSEA sponsored portion of the project was to field test some of the products and designs identified in this competition.
The specific objectives of the RPSEA Project are: Identify new technology that can reduce or eliminate the impact of drilling operations on environmentally sensitive areas. Design an EFD system using most promising technology Include environmental stakeholders in the designs
After drilling operations are completed or suspended, roads are often remediated. This removal is intended to allow the recovery of the lands to a pre-use condition so as to minimize additional access. Experience has shown that such efforts pose difficulty, highlighting the complexity of potential long-term consequences of oil and gas operations. New systems have been tested to avoid this expense.
Tests have been performed in a desert environment in West Texas as well as a second test located in a moderate climate with significantly more rain to determine the optimum operational conditions for the materials used. The project evolved to include roads made from recycled well cutting, plastic composite mats and mats made from waste materials. As in all projects the viability of any method is measured by the cost and benefit relationship. If the road material reduces cost either for construction or in the case of remediation and disposal of cuttings it could be considered a success.
Composite Plug Milling Efficiency Improvement through Rheology Control - Lessons Learned from the Horizontal Completions in the Duvernay Shale
Authors: Huynh Darren , Medvedev Oleg , Hamid Saad , Anas Yossi 
Published: October 2014

Abstract
The Duvernay Formation in North Western Alberta holds an estimated 443 trillion cubic feet of gas and 61.7 billion barrels of oil. Horizontal wells are drilled and completed with multiple fractures to maximize the reservoir contact. The most common technique used for hydraulic fracturing in these wells is the plug n' perf method. Once the fracturing operation is completed, the plugs must be milled out using coiled tubing to restore wellbore access, as well as to put the well into production. While much emphasis is placed on improving fracture design and proppant placement in order to yield maximum production, optimizing the milling process typically focuses on mill bits, motors, and plug designs. Mill bit design and motor life have considerably improved as a result of intensive research and development in this field. New plug designs promise quick disintegration during milling. However, little attention has been directed toward understanding solids transportation and movement in the well bore. Rules of thumb are still commonly used to pump gel sweeps or determine the number of wiper trips needed when milling plugs or cleaning a well bore. As a result, current milling practices leave a significant amount of debris in the well bore, and pipe sometimes sticks due to cuttings or plug debris not transported to surface as a result of inadequate rheology. These risks not only jeopardize the safety of operations but incur extra completion costs.
In an effort to improve plug milling efficiency, a new technique was introduced during a well completion project in the Duvernay shale. The objective of this technique was to optimize the entire milling process while focusing on fluid rheology. This paper describes case histories comparing the results before and after the implementation of this innovative concept. It also outlines the benefits realized in terms of savings and the impact on project economics. The lessons learned and best practices developed during this process are shared to improve the understanding of milling process.
Deepwater Development Non-Technical Risks - Identification and Management
Authors: Reid David , Dekker Martijn , Paardekam Albert , Lewis Keith 
Published: October 2014

Abstract
This paper discusses the identification and management of non-technical risks for early phase, pre-sanction, deepwater oil and gas development projects. Supported by insights from global deepwater projects, the paper describes key "non-technical" issues that deepwater projects often face throughout their lifecycle, and provides a framework and process for building a deeper understanding of these non-technical issues such that they can be successfully integrated into ongoing venture management from start-up through final project sanction and beyond.
As the oil and gas industry pushes into deeper water, more complex environments and frontier unproduced plays/areas, the technical and non-technical risks related to appraisal and development of deepwater projects are likely to continue to increase substantially. While the technical challenges related to deepwater developments are significant, perhaps more significant and critical to the venture success are that the non-technical aspects of managing a new development in a frontier area are understood and incorporated at the onset.
The non-technical aspects of any deepwater venture cover and influence a vast spectrum ranging from internal organizational issues within and outside of the direct control of the project, to more broadly the external business environment which is often in flux. These wide ranging issues play critical roles is defining and affecting the stability of the project as it evolves over the typical industry 10 year+ project maturation cycle. Effective identification and management requires the venture team to:
Build a deep and robust understanding of the internal and external context for the project (technical and non-technical), Integrate all of these aspects into a credible framework within which the project can be safely and competitively delivered, Understand the interplay between project schedule and "stability" of the internal/external non-technical aspects of the venture, and, Develop appropriate risk mitigation and opportunity capture strategies for the highest impact non-technical aspects identified and play these out over the maturation of the project concept.
Based on experience, and with the help of examples, this paper discusses the criticality of non-technical issue identification and management in the formative stages of a project with the key goal of stabilizing the project and laying a solid foundation for future project decisions on route to project sanction.
Lithofacies Classification of Thin Layered Reservoirs Through the Integration of Core Data and Dielectric Dispersion Log Measurements
Authors: Pirrone M. , Battigelli A. , Ruvo L. 
Published: October 2014

Abstract
Distal turbidites consist of thin laminations (inch-scale) usually ranging from fine sand to clay-rich deposits and may represent major hydrocarbon reservoirs: conventionally, they are studied by means of a log-based binary modeling that discriminates productive and non-productive layers. Nevertheless, the binary model represents a major drawback when dealing with laminations in the silt grain-size range, as their allotment to either end-member can be extremely problematic.
This paper deals with a novel lithological facies classification approach that integrates core data and a high-resolution dielectric dispersion wireline log: its 1-inch vertical resolution and a related fit-for-purpose petrophysical model make the log tool's response suitable to describe the lithological heterogeneity of these reservoirs.
The approach is presented by means of a study performed on the cored section of a well drilled into a laminated gas-bearing Pleistocene reservoir in the Adriatic Basin. A core-based classification was first carried out using sedimentological descriptions, mineralogical analyses, cation exchange capacity measurements, routine and special core analyses, and a statistical investigation of grain-size distributions: this allowed the identification of four litho-facies ranging from hemipelagite to coarse silt. Next, a log-based classification was carried out with a multivariate statistical numerical technique (cluster analysis) run on the dielectric dispersion model output curves along the cored section of the well. In the end, a four-facies log-based classification was obtained that matches the core-based classification with an overall agreement in excess of 93%.
When compared to the conventional methodology, the presented approach shows the added value of identifying intermediate lithologies, thus leading to a more accurate quantification of the thickness of the potentially hydrocarbon-bearing net reservoir.
Developing an Integrated Sand Management Strategy for Kinabalu Field, Offshore Malaysia
Authors: McPhee Colin , Webster Craig , Daniels Gillian , Reed Chistopher , Mulders Frans , Howat Craig , Britton Alan 
Published: October 2014

Abstract
The Kinabalu oilfield is currently producing 14,000 bopd from a peak of 40,000 bopd in 1998. Present field rejuvenation plans include drilling and completing new infill and development wells from both an existing and a new platform. Most platform wells are currently producing sand and none have been completed with sand control. Sand production has caused erosion issues and lost production due to the need for regular separator clean outs, and is a key risk factor for both existing well integrity and new well completion design. A multi-disciplinary team was tasked with determining the causes of sand production, and to develop a fit for purpose sand management strategy for this mature, brownfield redevelopment.
A coupled geomechanical/sand failure model was employed to assess sand failure, and to evaluate alternatives to sand exclusion completions. The model was calibrated using existing well sand production data, then run for the proposed new wells to assess the potential for sand production over the remaining field life. The model confirmed that sand production is closely linked to reservoir depth, completion type, well inclination and, most importantly, depletion level.
An objective screening process was developed to rank sand control options. This considers existing and proposed well completion architecture, facilities design/limitations, and recognises inherent data uncertainties. The systematic sand management methodology allows a consistent, objective and transparent view of benefits and risks across the different system aspects. Key selection criteria were utilised rather than arbitrary decisions based on limited and often unaudited data. The process ensured a best practice, fit for purpose, and structured sand management solution.
In light of the currently low levels of sand production and the challenges associated with remedial or retro-fitting sand control, optimised surface sand management will continue to be the preferred solution for all existing wells.
Predicted sand production in most new wells is manageable. Some wells targeting shallower or weaker sands would normally be sand control candidates, but re-thinking the completion design, optimising surface sand management procedures, managing drawdown and BHFP levels, and taking advantage of favourable stress vectors through oriented perforation can extend the sand free well operating envelopes over life of well production and depletion conditions, reducing or deferring the need for sand control in all but the highest sanding risk reservoirs.
Increasing Oil Recovery from Long Horizontal Wells Using Advanced Lower Completion Systems
Authors: Joseph P. , Galimzyanov A. , Nazarenko P. 
Published: October 2014

Abstract
Horizontal openhole wells are becoming common in current field developments. The main advantage of horizontal wells is that they increase drainage area, resulting in improved recovery. However, horizontal wells produce some challenges. Frictional pressure drop from toe to heel and breakthrough anywhere in the well due to permeability variation along the horizontal section lead to water or gas coning toward the heel of the well. To manage and overcome these challenges in horizontal wells, the industry developed advanced lower completion systems.
Existing completion technologies used in these long wells are typically passive systems. These systems, which include inflow control devices (ICD) designed with torturous paths or orifices, have limited ability to manage water breakthrough that leads to lower ultimate recovery. Hydraulic systems use inflow control valves (ICV) that can be actuated from the surface. The number of available wellhead penetrations limits the number of ICVs that can be deployed within the completion string. Electric systems with multiple active flow control devices (AFCD) on a single tubing encased conductor (TEC) can address the water breakthrough issue economically in extended-reach wells. The single TEC line requires only one penetration at the tubing hanger.
This paper evaluates and compares the cumulative oil production for ICD, ICV and AFCD devices. Input data from multiple wells was used to compare the oil production of systems incorporating these devices over a period of a few years. Near-wellbore simulations and data analysis clearly show the increased oil recovery potential of using completion systems with AFCDs. This system on a single TEC can be installed to compartmentalize a long horizontal well into more than 20 isolation zones. The compartment is created by an openhole packer, and each zone typically has at least one AFCD. Each AFCD can achieve ON and OFF positions and various intermediate choking positions. Choke settings can be customized to specifications. Each AFCD can be selectively actuated to a choke position remotely from the surface to control water-producing zones.
Completion systems with AFCDs are poised to give the industry the ability to remotely control water breakthrough and optimize production in long horizontal wells. This paper shows how different types of completion technologies can help accomplish real-time wellbore equalization that leads to increased oil recovery. An intelligent completion system with these active flow control devices provides our industry complete control of a field through proactive and reactive reservoir management, increasing the ultimate recovery rates.