bluuebunny/crossref_metadata_2025_split huggingface dataset:
Brown Field Optimisation to Maximize Gas Recovery in Muda Central Field of Joint Development Area, North Malay Basin
Authors: Setiawan A. S. , Simatupang M. H. , Rachmadi A. , Jiraratchwaro C. , Pushiri M. F. Mohd 
Published: November 2016

Abstract
Finding an opportunity to expand the recoverable reserves in a brown field is always a challenging task. A robust reservoir characterization and dynamic synthesis are vital to provide a proper understanding of the field. The objectives of this project are to maximize gas recovery through 3D reservoir modeling works, to evaluate un-connected hydrocarbon volumes, production improvement, and prudent reservoir management.
Muda Central field (MCF) has been producing for more than 5 years with 40 production wells. Therefore, the production data is an essential input to assure the quality of the model. The geological-facies modelling was constrained by seismic attributes as quantitative soft data after calibrating to well data. The high uncertainty of reservoir presence in the model was assessed by combining sand distribution and porosity variation. Material balance analysis was used to select a base-case static model in order to reduce the iteration process during the history match. History matching was performed with a reasonably good match to calibrate the model.
The results of dynamic simulation indicated some potential undrained hydrocarbon areas that are promising for future development. As a result, one well was proposed to appraise and prove the existence of disconnected hydrocarbon volume as recognize in the seismic attributes. The well was drilled a year later to prove the hypothesis. The drilling result demonstrates that the initial hypothesis is proven by pressure data and fluid sampling. The reservoir pressure is still un-depleted and the level of CO2 content is different compared to the existing producing wells. This finding provides an opportunity for future development in the vicinity of the existing producing platform as well as a different development scheme in the area of the appraisal well. The additional benefit of this work is to assist with prudent reservoir management.
A comprehensive model of MCF demonstrates a best practice, collaborative interaction between geophycisist, geologist, and reservoir engineer. This study successfully proved disconnected hydrocarbon volume, which translates into a future development plan to optimize MCF reserves.
Downhole Water Sink Technology Improves Recovery and Rates from Strong Water Drive Reservoirs in North Kuwait – A Pilot Case Study
Authors: Anthony E. , Al-Mosaileekh S. 
Published: November 2016

Abstract
Maximizing recovery from strong water drive, permeable reservoirs in North Kuwait usually require a combination of approaches. Implementing partial perforating techniques across the oil column above the oil/water contact and installing tubing sizes that secure maximum natural flow life cycle are presently utilized to extend the natural flow life cycle in strong bottom- and edge-water drive reservoirs. Limiting production rate at or below critical coning rate, and conversion to Artificial Lift when the water cut increase forces cessation of natural flow, further improve the ultimate recovery of oil from these reservoirs.
In pilot Well-A, approximately 55% of the oil column above the Oil/Water contact was perforated on initial completion. Within 6 months from initial completion, the Watercut increased from 0% to 53%, then gradually increased to 74% over the next four years of natural flow life. Before the natural flow ceased completely, the well was worked over to install the innovative Downhole Water Sink completion. This completion design comprised of a very short perforated interval at the original depth of the Oil/Water contact and with another perforated interval across a highly permeable aquifer below the layer of interest. A shrouded ESP with Y-tool assembly was then installed, able to generate a drawdown just below the original OWC that is greater than the drawdown across the originally perforated interval.
This pressure sink created at the OWC controls the further development of the water cone around the wellbore thereby increasing the maximum coning rate, in addition to accelerating and increasing the ultimate recovery from this water-drive completion. The excessive water that is usually produced to surface, and processed along with the oil, is now significantly reduced since most of it is now re-directed to a deeper non-oil-producing aquifer. Though the watercut is never eliminated at the oil perforations, the natural flow life cycle is extended, and thereby the ultimate recovery considerably improved. Actual % improvement is yet to be determined since the watercut of the produced fluid at surface has not yet risen to the level that causes cessation of natural flow.
This pilot application of the Downhole Water Sink technology to this North Kuwait water-drive reservoir opened up immense opportunities for comparable recovery improvements in similar and even larger water-drive reservoirs in other Assets within the company. Where reservoir pressures are insufficient to maintain natural flow, a dual ESP system is already designed to lift the oil column using the same Downhole Water Sink principle.
Geomechanical Aspects of Waterflooding: Setting Strategies and Operational Limits for Containment
Authors: Khodaverdian Mohamad , Rahim Helmi , Seli Phyllis , Morphy Paul , Dasgupta Ayan , Odedeyi Olalekan 
Published: November 2016

Abstract
Waterflooding is often planned for unconsolidated sand reservoirs for pressure support or production enhancement. Injections may be carried out under "matrix" or "fracture" conditions. Despite the typically high permeability and high porosity nature of unconsolidated sand reservoirs, global experiences suggest that water injection in such formations is not trouble free. Under matrix injection significant injectivity decline due to formation plugging could be encountered within the first few years or even months of the injector start up, particularly in the absence of fine filtering of water. Injection under fracture conditions may be considered to avoid formation plugging and injectivity decline. However field evidences suggest that "fracture" water injection in unconsolidated soft reservoirs could lead to high pressures, potential loss of containment and failure of sand control. The consequence of severe injectivity loss for either injection strategy is early injector abandonment or replacement of expensive wells and production deferment or loss of waterflood reserves.
Considering the above limitations for different injection strategies, it is paramount that geological settings, formation type, rock mechanical properties and consolidation levels are considered in selecting water injection strategy, well completion and topsides filtration design in field development planning. Even with these considerations it is often not possible to confidently predict the performance of water injectors in unconsolidated sand, particularly under fractured conditions. There is no widely accepted theoretical understanding of the fracturing process in soft formations and therefore the predictive capabilities for modelling injectivity are quite limited.
This paper presents the geomechanical factors considered for selecting the waterflooding strategy for a particular deepwater, unconsolidated soft sand reservoir in offshore Sabah, Malaysia. The actual decision making process was based on an integrated approach between various subsurface and engineering disciplines. However, due to the unconsolidated formation settings, as well as the faulted nature of the caprock and reservoir, geomechanics played a critical role in devising the waterflood deployment strategy and setting operational limits to ensure containment. The work involved comprehensive geomechanical modelling of the waterflooding process in the reservoir using both analytical and 3D numerical modelling. Global experiences of waterflooding in unconsolidated formations were also invaluable and were integrated in selection of completions and development strategy.
Enhancing Proppant Flowback Control Through Surface Treatment of Proppant
Authors: Lu Weibing , O'Neil Bill , Zhang Kewei , Wang Chuanzhong , Quintero Harvey 
Published: November 2016

AbstractPost stimulation proppant flow back has long been an issue of the hydraulic fracturing process. The most common means of remedying proppant flowback has been to treat proppants with a resin coating. However, the most daunting factor in using resin-coated proppants is the resulting high price, which can be in excess of four times the price of untreated proppants. Additionally, resin coated proppants often need to be activated with exposure to temperature and pressure. In the case of low temperature/low closure stress reservoirs, additional chemical activators are required which further increases the cost. A proppant flowback control measure which is cost-effective and can perform over a wide variety of reservoir conditions would be advantageous to the hydraulic fracturing process.A new technology has been developed to control proppant flowback that is a non-toxic, cost effective, and operationally easy. After being coated with a proppant consolidation aid (PCA), the proppant depends on a physical mechanism rather than chemical bonding to increase proppant pack resistance to flowback. There is no minimum closure stress, temperature, or shut-in time requirements associated with the use of this technology, and the coating can be applied to all or just selectively some of the proppant stages, which allows more flexibility available to the operators in flowback design and production strategy.Laboratory testing will illustrate the efficacy of sand consolidation using the PCA coating. Simple lab bottle consolidation testing will demonstrate a comparison between untreated and treated proppants. Large scale tubing flow tests will also demonstrate the ability of the coated proppant to resist movement during fluid flow relative to untreated sand, and will also show the cleanup ability of the sand at higher flow rates in the event of a sand-off where proppant remains undesirably in the wellbore.Other testing will reveal additional benefits to the sand treatment such as improved sand pack conductivity and increased compressive strength. Computed Tomography (CT) analysis will be used to explain one of the mechanisms that results in increased proppant pack conductivity. Temperature stability testing will be included to show the wide potential application window of the PCA chemistry.
Unlock the Liquid Loaded Gas Wells with ESP Technology: The Successful ESP Dewatering Application in China Sichuan Gas Field
Authors: Peng Y. , Liao T. , Kang Y. , Zhu Q. , Li C. 
Published: November 2016

Abstract
The operator in China Sichuan gas field is often faced with challenges of efficiently removing water from aged gas production wells in which reservoir pressure depletes and liquid loading problem ensues. Applying the proper dewatering method is essential to keep the well flowing and avoid water accumulating in bottom hole. Among the many proven dewatering artificial lift methods, ESP (Electric Submersible Pump) technology has its advantage in wells which need a high volume of water produced with maximum pressure drawdown, which are beyond the capability of other artificial lift methods.
First introduced in year of 1984, the operator and ESP provider have made considerable progress to develop an ESP application method in the field through theoretical studies, field trials and regular production.
This paper concentrates on discussing the ESP sizing and optimization practice to tackle the corrosive, extremely gassy, fluctuating liquid inflow environment typically seen in gas wells - an area used to be perceived as infeasible for ESP technology. The methodology of well selection, completion string design and production management could be used for reference where there are similar challenges with Sichuan gas field.
Deep Water Reservoir Management Using Fast Turnaround Integrated Reservoir Modelling Workflow
Authors: Zwart Bert-Rik de , Varghese Jose , Nayak Prasanta , Saha Aloke , Numpang Anna , Din Mohd 
Published: November 2016

Extended Abstract
This paper presents a fast turnaround Integrated Reservoir Modelling (IRM) workflow for a deep water turbidite field. It is based on a static and dynamic Experiments of Design (DoE or ED) workflow that is used as a toolkit for uncertainty management. The case study shown here emphasizes the application of this "Multi Scenario Approach" methodology for field specific decisions such as short and mid-term reservoir management optimization and infill development opportunities, including impact of key subsurface uncertainties on these decisions.
anonumously
The objectives of Integrated Reservoir Modelling workflow presented here are: To create fully integrated models or multiple scenarios that provide realistic ranges of forecasts, e.g. geologically sound, to underpin development and operational decisions without anchoring to a single base case; andTo shorten modelling life cycle to achieve faster project delivery and allow for uncertainty workflows as proposed in this paper. There are many decisions that are dependent on model forecasts such as identifying infill well target locations and number of wells at the project level, project phasing to extend production plateau, and to identify and mitigate key projects technical risks
Galvanising Stakeholder Support for Carbon Capture and Storage
Authors: Maas Wilfried , Lee Danmi , Horan Denise , Wiwchar Tim 
Published: November 2016

Abstract
Our lives depend on reliable energy; if we are to prosper and tackle climate change, society must transition its economies and energy system to meet growing demand and emit less CO2.
Shell believes carbon capture and storage (CCS) is critical. CCS fitted to power plants could be a real game-changer, removing up to 90% of carbon dioxide emissions from power generation.
Engagement and cooperation with different stakeholder groups is key to maturing CCS projects. Shell has worked with stakeholders to help build a strong foundation for some of our CCS projects and this paper will share the approaches applied.
Collaboration is critical to achieving recognition of the scope and value of CCS and achieving acceptance for a specific project. It is important to create engaging outreach and educational initiatives that are targeted to the needs of the stakeholders, demonstrate commitment to local communities, address the points of challenge and clarification, make use of best practice and international project experiences and help bring CCS, energy and climate change to life.
QUEST
Shell began its community consultation program for its Quest Carbon Capture and Storage (CCS) project in 2008 — three years ahead of filing a project application. A large part of our early consultation efforts were focused on explaining what CCS is, and why the technology is important. Consultation efforts focused on landowners and residents living along the proposed pipeline route and in close proximity to the proposed injection wells, along with the local municipal governments. A community advisory panel has been set up to review data from the Measurement, Monitoring and Verification (MMV) program. The program itself has been reviewed by an independent external expert.
PETERHEAD
The funding for the Peterhead CCS project has been withdrawn, but we are proud of the relationships established in the early phases of the project's development. The team carried out extensive consultations with the public to keep everybody up to date with plans as they progressed. We proactively sought and received feedback which we then endeavoured to build into our plans.
In addition, strong relationships were built with local, regional and international organisations to develop education-based initiatives around CCS and to build an effective approach to local content on the project, both with the aim of creating best practice learnings for the future.
At Shell, we believe the world will need to find ways to deploy CCS if it is to achieve its ambition to tackle climate change. In order to set CCS projects up for success, we must explore and develop a new model of cross-sector collaboration including: Building an understanding of the local contextEngaging early - being present, responsive and inclusiveMaking communications engaging and relevant
Successful engagement, collaboration and community presence can lead to strong, trusting relationships that can be built on over the life of the project.
Floating LNG Safe by Design
Authors: Jewitt I. 
Published: November 2016

Abstract
This paper outlines the result of a design safety FLNG approach from research through concept development and ultimately implementation in design and engineering.
Prevention of process safety events is critical to business success. The industry has been developing and improving all aspects of its FLNG design since the 1990s. Safety has been the primary focus in FLNG design. There has been a programme of work to ensure that the FLNG has been well designed and as a result the facility incorporates a number of proven and tested technologies that have been in use in existing LNG plants for many years. However, for FLNG, comprehensive design standards have not always been available and so research and risk assessment as well as guiding safety philosophies has been essential the process safety challenges for the conceptual development and design.
In order to fully understand the risks associated with all aspects of a FLNG project and to manage the risks so that they are As Low As Reasonable Practicable (ALARP), it has been necessary to perform detailed safety studies to benchmark the safety of the facility and inform the risk mitigation in the design.
This development has identified multiple robust and proven ‘barriers’ to prevent safety incidents happening on the facility. The primary strategy for minimizing the fire, explosion and cold spill risk focused on hazard prevention. Whilst this strategy reduced the probability of an uncontrolled loss of containment, there remained a risk, which required control and mitigation. The barriers have been embedded in our FLNG safety philosophies and implemented in the design.
The industry is conscious that the prevention of process safety incidents is both critical to keeping people safe and also to ensuring continued business success. The extensive research that has been applied to this FLNG design provides confidence that the FLNG facilities will be as safe and reliable as other modern offshore production facilities currently in operation.
An Integrated Evaluation Workflow in Volcanic Reservoir with Comprehensive New Logging Data Sets A Case Study from Junggar Basin Xinjiang Oilfield China
Authors: Xinjun Mao , Weidong Huang , Youguo Sun , Yingbo Yang , Wei Wang , Lei Yang , Jichao Chen , Guo Wei 
Published: November 2016

Abstract
This paper is to show a case study from Junggar Basin in North West China, which integrates a variety of logging data acquired by latest wireline measurements to analyze and evaluate lithology, pore types, fluid types and geomechanics properties of volcanic reservoir.
Interpretation of volcanic reservoir has always been a great challenge. Recently, a lot more advanced data sets are available from the new wireline tools and measurements in Xinjiang Oilfield, such as SonicScanner, LithoScanner, Images logs, and latest 3D Saturn Radial probe forvolcanicformation sampling. The new data provide a better view for avolcanic reservoir. An integrated evaluation workflow that combines multiple latest wirelinetechnologies has been set, which can provide a good solution to the evaluation of volcanic reservoir in this area. Calibrating high precision and high-resolution lithology data to core data can accurately describe the complex lithology of volcanic reservoir. Meanwhile, apart from fractures identification, we are not only be able to categorize rock type with help of structure analysis provided by image data, but also can analyze the volcanic eruptible period by comparing images of adjacent wells. In addition, by acquiring, processing and interpreting advanced sonic scanner data; we can evaluate formation anisotropy, fracture effectiveness, identify gas zones and calculate geomechanics parameters, which will be used later during stimulation. In the end, utilizing the 3D Radial probes, the formation tester can confirm the fluid type by the downhole analyzer and actual fluid samples, this greatly reduce the uncertainly for evaluation and later stimulation.
In this example, Well A from XinJiang oilfield, JinLong Block, is a typical volcanic formation which is characterized by highly developed natural fractures with various attitudes, complex lithology, which mainly contains andesitic volcanic breccia, breccia andesite, basalt, andesite, tuff and volcanic sedimentary rock, and quite low matrix permeability. Thus, SonicScanner, LithoScanner and FMI data have been acquired, and the favorable lithology, well-developed fracture zones, and high matrix porosity zones have been identified, the "sweet spot" have been located. In the end, the actual gas sample has been obtained for the first time by formation testers using 3D radial probe in volcanic reservoir in CHINA.
This case study is a good example of volcanic reservoir evaluation. A workflow that is applicable to this area has been formed, which can be used as guidance for evaluation of other similar wells in the future.
Stay in the Pay: Steering for Black Gold - Multilayer Bed Boundary Detection Reducing Structural Uncertainty for Advanced Well Placement
Authors: Platt Chris , Carter David , Slamet Remy , Doogue J. , Nguyen Thanh P. , Santoso G. , Abbasgholipour A. 
Published: November 2016

Abstract
The Wassana field is located in the G10/48 block in the Gulf of Thailand, operated by Kris Energy. Wassana recently commenced production following a successful development campaign, including very challenging horizontal productions wells with significant uncertainly of reservoir structure and thickness. The Seismic data was used for field development and several horizontal wells were planned to penetrate thin sand reservoirs. However, the challenges is significant variations of structure and thickness amongst the tilted fault blocks. To guarantee for the success of drilling horizontal wells, geosteering technology can be used to reduce structural uncertainty and achieve high net-to-gross in the reservoir for superior production.
The Wassana field is comprised of tilted fault blocks, with a mixture of Oligo-Miocene intra-formational shale stratigraphic traps and structural traps. The execution of horizontal wells presented significant challenges, as the objective was to maximize reservoir exposure, taking into account high structural uncertainty with lateral variation in formation dips and sand development uncertainty both in distribution and connectivity. Based on the planned well paths, pre-job modelling of the horizontal wells with a Resistivity Inversion indicated a lot of geosteering difficulties and challenges. All the decisions made in real-time would be very critical and important to ensure well success.
With challenging horizontal well placement, a number of techniques and technologies were employed. A High Build Rate Hybrid Rotary Steerable Tool with near bit GR was used to help optimize the well landing in the 8.5in sections, in order to land high in the sand, whilst maintaining high ROP and wellbore quality. Near Bit Triple Combo LWD was used to confirm landing in high quality sands in order to prevent any loss of horizontal footage and maximize the effectiveness of the horizontal section. A new geo-steering tool was selected for geo-steering utilizing a new Stochastic Resistivity Inversion, which would be able to map multilayer bed boundaries, to illuminate the reservoir structure in real-time, thus significantly improving geosteering decisions to remain in the oil bearing sand.