bluuebunny/crossref_metadata_2025_split huggingface dataset:
An Integration of Geology, Geohazards, Geophysics and Geotechnics for Pre-Feed Site Layout and Engineering Design of an Offshore Gas Field in the Timor Sea
Authors: Chullabrahm Pattarapong , Saranyasoontorn Korn , Svasti-xuto Maythus , Trithipchatsakul Chao , Sunderland Damon , Ingvorsen Peter , Madrigal Sarah , McAndrew Russell 
Published: April 2019

Abstract
This paper presents an integration of geology, geohazards, geophysics and geotechnical assessments for a design of an offshore gas production facility and an associated export pipeline. The gas field described in this paper is located off the North West coast of Australia in the Timor Sea in a water depth of approximately 130m.
Various resource development options were investigated during the Concept Select / pre-Front End Engineering Design (pre-FEED) phase of the project. These options included fixed and floating structures in the infield area and a 300km long export pipeline that ties into an existing gas trunkline connecting to an onshore processing plant.
To provide the necessary engineering due diligence to allow the project to progress further, several phases of geo-related investigations were undertaken to assess various geohazard challenges and foundation risks. Some of these challenges include a pipeline route traversing several steeply sloping seabed canyons, potential activation of turbidite sequences, and the presence of very soft carbonate sediments to calcarenite rock.
This paper describes these ground related challenges and how they were constrained through the geo-related investigations conducted, observations made and results obtained. Ground related challenges are described in two parts: Pre-FEED export pipeline routing reviews focusing on geohazard, geophysical and geotechnical considerations and ‘real time’ pipeline engineering Finite Element Analysis (FEA) performed offshore. Compared to normal practice, this non-standard offshore analysis allowed a preferred pipeline corridor to be identified during the survey with an informed understanding regarding feasibility and likely seabed intervention, thus optimising the field survey time and cost; andStaged acquisition and integration of infield geophysical and geotechnical data for developing high level assessments of foundation concepts.
Key benefits of conducting an integrated approach to geo-related challenges on a complex site will also be presented in this paper.
First Onsite Automatic Geomagnetic Observatory Improves Well-Bore Positioning
Authors: Momot Fabien , Humbled François , Garbers Martin , Shabanov Sergey , Gonsette Alexandre , Sikal Anas , Cousso Olivier , Reynaud Denis 
Published: April 2019

Abstract
Improvements in measurement while drilling (MWD) and service reliability over the past 25 years has made MWD tools the most cost-effective method for calculating wellbore survey position while drilling. However, with more complex well trajectories required to reach more challenging targets, reducing lateral uncertainty has also become a new challenge.
It is accepted that no geomagnetic model can properly account for the geomagnetic spatial and temporal local complexity for calculating MWD geomagnetic reference values. It is also well known that measuring local geomagnetic reference requires frequent absolute measurements in order to perform QA/QC, and that those absolute measurements could only be done manually so far, and consequently very few magnetic observatories are in operation. Therefore, solutions have been engineered to enhance the geomagnetic reference model with In-Field Referencing (commonly termed as IFR). Then, its combination with Multi-Station Analysis (MSA) correction algorithms has become a common method for addressing and reducing most of the correctable MWD azimuth, survey position error and lateral uncertainty.
Enhanced wellbore positioning could be a real game changer to achieve in-fill wells with high collision avoidance constraints, to develop projects that require high precision to hit the reservoir targets, or those located in specifically difficult areas, from a geomagnetic perspective, such as high latitudes and zones with crustal anomalies.
This paper presents the results of the new temporal magnetic field method "IFR4D" that was successfully used to drill two onshore wells in Argentina. The wells targeted the Vaca Muerta shale play, and demonstrated the ability to improve the wells absolute positioning while reducing the lateral aspect of "ellipse of uncertainty" by a combination of: A unique autonomous, remote real-time observatory developed to monitor and allow corrections for the local geomagnetic vector with frequent absolute control of the local and temporal geomagnetic vector field (Dip, Declination and Field Intensity), andA dedicated MSA algorithm defined to use local and temporal In-Field Referencing (IFR2) data at the position and time for each MWD survey station.
Once installed on location, the autonomous observatory measured all geomagnetic properties (Dip, Declination and Field Intensity) with no personnel onsite for more than one year, delivering a new level of geomagnetic accuracy to use as the standard reference for the life-time of the field. The data from the observatory was then used remotely while drilling to correct and optimize wellbore position and reduce the lateral aspects of the "ellipse of uncertainty" (EOU).
Separator Pressure Optimisation and Cost Evaluation of a Multistage Production Unit Using Genetic Algorithm
Authors: Motie Mohadeseh , Moein Peyman , Moghadasi Ramin , Hadipour Ali 
Published: April 2019

Abstract
Once reservoir fluid is brought to the surface it is separated to discrete streams of oil and gas in production unit. This should be conducted with consideration of maximizing oil production and to decreasing total costs as well. The regulation of separators pressure is a key point to achieve the highest oil recovery in this process. In addition, estimating the optimum number of separation stages, would augment the design of production plant economically. Adjusting separator pressure is usually conducted by employing PVT data which are provided through flash or equilibrium separation tests. In case of experimental tests unavailability, an alternative method could be empirical correlations. However, such tentative methods contain inaccuracy and are also time consuming which may limit their utility. In this study the issue was addressed by applying genetic algorithm (GA) as well as flash calculation through a case study on one of Iranian oil field. It has been tried to optimize set point pressures of each stage and enhance liquid share of the fluid with respect to minimized gas oil ratio (GOR). Prior to this, four scenarios were considered for determining the number of separation stages. To determine the prime scenario, a cost evaluation was implemented which leaded to the selection of four-separator scenario as the most economical case.
Research and Practice of Full Life Cycle Well Integrity in HTHP Well, Tarim Oilfield
Authors: Liu Hongtao , Cao Lihu , Xie Junfeng , Yang Xiangtong , Zeng Nu , Zhang Xuesong , Chen Fei 
Published: April 2019

Abstract
There is abundant natural gas in Kuqa foreland area of Tarim basin, the reservoir has characteristics of ultra depth(6500m-8000m), high pressure(115MPa-140MPa), high temperature(170°C-190°C) and complex corrosive medium, which bring well integrity high challenge. There are 52 production wells in the Kuqa foreland basin in 2012. The 16 wells of these production wells exist sustained casing pressure(SCP). The SCP wells caused by the tubing string failure is 61%.
Since 2012, in order to build safe well barrier and achieve scientific production management, consider all important periods of drilling, well testing, well completion and production in well full life cycle. the design methods of the four main well barrier components(casing string, cement, tubing string, well head) are optimized. A set of technology for well barrier quality control, well maintenance and well production management is formed. Finally, the key technology of full life cycle well integrity for ultra depth, HPHT gas well is formed.
In view of the large angle of bedding, well deviation controlled difficultly, and coexistence of high pressure saline aquifer and week bed in one open hole section which lead to serious casing wear and poor cement stone, the vertical well drilling technology, the collapse resistance casing design methods, the casing wear preventing measures, negative pressure test method and high temperature, high density cementing technology are completed. These technologies improve the safety of casing string and the quality of cement. Considering the extreme working conditions(the partial pressure of CO2 is beyond 2MPa, The content of chlorine is about 80000mg/L, acid job, 136MPa pump pressure in well head)of tubing string, material selection method, triaxial stress analysis method, quality control technology for tubing string is optimized. The failure ratio of tubing string reduced from 50% in 2013 to zero in 2017. Referencing API RP 90-2 and IOS16530-2, a special calculation method for annulus pressure management is formed, which include minimum operation pressure and maximum allowable pressure for different annulus. Then a risk assessment system is established. The SCP wells is controlled less than 22% in the condition of increasing number of high pressure gas wells.
Based on the research introduced above, China's first set of well integrity specification series is completed. The integrity specification series include the well integrity guide, the well integrity design and the well integrity management for high temperature high pressure and high sulfur gas. These results effectively support safty in production for high pressure gas field in Tarim basin, and will promote the well integrity level in the same kind of oilfield.
Research and Application of Retreatment Technology to Tap Remaining Oil in Chang Qing Low Permeability Oilfield
Authors: Wu Zengzhi , Zou Hongjiang , Wang Yugong , Wu Long , Li Yong , Xu Yang , Wang Renfeng , Meng QingCong , Jiang Wenxue , Wang Suoliang , Li Shan , Li Dan 
Published: April 2019

Abstract
With the development of Chang Qing Oilfield, the following technical problems are faced: the increasing proportion of the low-production and low-efficiency wells, the worse production of pertinence and effectiveness in conventional retreatments and a large amount of remaining oil between wells and layers. In this case, the technique of radial fracture network fracturing and deep plugging has been proposed. Meanwhile, the matching products which include variable viscosity diverting acid, micro expansion high strength plugging agent and temporary plugging agent (oil soluble, water soluble and anti-scale) have been developed as well. Nowadays, the retreatment technology has been successfully tested and popularized in Chang Qing oilfield. Compared with the conventional retreatments, these two technologies have remarkable effect on increasing production and prospective application.
Development of a Novel Anti-Temperature, Anti-Wear and Ecofriendly Lubricant SDL-1 for Water-Based Drilling Fluid
Authors: Liu Yunfeng , Qiu Zhengsong , Zhong Hanyi , Meng Meng , Zhao Xin , Nie Zhen , Huang Weian 
Published: April 2019

Abstract
Lubricants used in the Water based mud (WBM) can solve the high torque and drag problems encountered in extended reach drilling operations. The fast development in the deep & ultra-deep drilling technology puts forward higher requirements for the anti-temperature performance of WBM lubricants which beyond the ability of the commercial lubricants. How to fulfill the gradually restrictive environmental regulations and lower the total cost has already been a tough task for the drilling fluid designers.
In this paper, a novel lubricant SDL-1 as synergistic application of optimized waste by-product vegetable oil MVO-3 and expandable graphite GIC was described. The physicochemical properties of MVO-3 and GIC were analyzed separately. In order to form a stable synergetic system, the type and amounts of the dispersants and emulsifiers were optimized. Then technological development process of lubricant SDL-1 was introduced in details. And comprehensive evaluations of SDL-1 were conducted according to corresponding technical standards and the synergistic mechanism of it was revealed.
Development of the novel lubricant as synergistic application of waste by-product vegetable oil and expandable graphite affords a hopeful solution to solve the high torque and drag problems during drilling process. The substantial reduction in drilling costs with valuable application prospect makes the new developed lubricant more attractive. Furthermore, further benefits could appear in the economic development of relevant industries as the locally waste by-product vegetable oil was used in developing the novel lubricant.
Is Surfactant Environmentally Safe for Offshore Use and Discharge? An Evaluation Strategy for Chemical EOR Application in Malaysia
Authors: Chai Ching Hsia Ivy , M. Yusof M. Faiz , Hanafiah Norshariza 
Published: April 2019

Abstract
Without regulation pertaining to the use and discharge of surfactant for offshore enhanced oil recovery (EOR) process in Malaysia, we adopted the guidelines from OSPAR (Oslo Paris Convention) that governs the use and discharge of offshore chemicals in the North Sea Region. In OSPAR, the CHARM (Chemical Hazard Assessment and Risk Management) model is being used to assess the risk of offshore chemicals to the marine environment. CHARM prescribes the Predicted Environment Concentration:Predicted No-Effect Concentration (PEC:PNEC) approach which ratio determines the hazard quotient (HQ) in order to rank the chemical by colour banding. Our surfactant formulation achieved a HQ of 2.16 or Silver colour banding with the stipulation that the volume of the discharged produced water is twice the volume of chemical solution (squeeze) injected. Nevertheless, in providing more certainty and confidence for both operators and local regulators to allow for overboard discharge of our flow-back surfactant formulation, we conducted a comprehensive produced water dilution modelling called DREAM (Dose-related Risk and Effect Assessment Model). The model calculates the Environmental Impact Factor (EIF) of each component of the chemical in the discharged produced water. Similar to CHARM, the DREAM uses the PEC:PNEC approach, but its PEC input parameters include environmental influences such as weather profile, current, etc. and incorporates a slick model. Its output is a quantation of the risks to the receiving environment, called the Environmental Impact Factor (EIF); where EIF is more than 1, the impact to the environment is significant. We simulated the chemical fate of individual component of the formulation with the scenario whereby the produced water is not treated prior to discharge. The time-averaged EIFs were more than 1 across all weather windows, indicating the discharge of untreated chemical-containing produced water is likely to have a localized environmental impact. We used both CHARM and DREAM as decision support tools for effective management of operational discharges from offshore projects. Limitations and recommendations from DREAM simulation results in the context of our EOR application are discussed.
Intelligent Oilfield - Cloud Based Big Data Service in Upstream Oil and Gas
Authors: Yang Xudong , Bello Oladele , Yang Lei , Bale Derek , Failla Roberto 
Published: April 2019

Abstract
The Oil and Gas (O&G) industry is embracing modern and intelligent digital technologies such as big data analytics, cloud services, machine learning etc. to increase productivity, enhance operations safety, reduce operation cost and mitigate adverse environmental impact. Challenges that come with such an oil field digital transformation include, but are certainly not limited to: information explosion; isolated and incompatible data repositories; logistics for data exchange and communication; obsoleted processes; cost of support; and the lack of data security. In this paper, we introduce an elastically scalable cloud-based platform to provide big data service for the upstream oil and gas industry, with high reliability and high performance on real-time or near real-time services based on industry standards. First, we review the nature of big data within O&G, paying special attention to distributed fiber optic sensing technologies. We highlight the challenges and necessary system requirements to build effective and scalable downhole big data management and analytics. Secondly, we propose a cloud-based platform architecture for data management and analytics services. Finally, we will present multiple case studies and examples with our system as it is applied in the field. We demonstrate that a standardized data communication and security model enables high efficiency for data transmission, storage, management, sharing and processing in a highly secure environment. Using a standard big data framework and tools (e.g., Apache Hadoop, Spark and Kafka) together with machine learning techniques towards autonomous analysis of such data sources, we are able to process extremely large and complex datasets in an efficient way to provide real-time or near real-time data analytical service, including prescriptive and predictive analytics. The proposed integrated service comprises multiple main systems, such as a downhole data acquisition system; data exchange and management system; data processing and analytics system; as well as data visualization, event alerting and reporting system. With emerging fiber optic technologies, this system not only provides services using legacy O&G data such as static reservoir information, fluid characteristics, well log, well completion information, downhole sensing and surface monitoring data, but also incorporates distributed sensing data (DxS) such as distributed temperature sensing (DTS), distributed strain sensing (DSS) and distributed acoustic sensing (DAS) for continuous downhole measurements along the wellbore with very high spatial resolution. It is the addition of the fiber optic distributed sensing technology that has increased exponentially the volume of downhole data needed to be transmitted and securely managed.
Non-Toxic High Temperature Polymer Drilling Fluid Significantly Improving Marine Environmental AcceptabiIity and Reducing Cost for Offshore Drilling
Authors: Liu Xiaodong , Gao Yonghui , Hou Wei , Ma Yongle , Zhang Yong 
Published: April 2019

Abstract
Oil based drilling fluids, polysulfonate and other toxic drilling fluids have been restricted to use by strict environmental protection laws and regulations, when drilling in high temperature well in environmentally sensitive sea areas. Meanwhile, the environmental requirements of drilling fluid biological toxicity value LC50 greater than 30,000mg/L, Hg content of barite less than 1mg/L and Cd content less than 3 mg/L, which brings severe challenges for high temperature drilling fluids and offshore environmental protection.
A kind of new non-toxic and high temperature polymer drilling fluid with the temperature resistance for 200°C and the biotoxicity value satisfied the discharge standard of the first class sea area has been developed in order to meet the requirements of high temperature deep well drilling operation and environmental protection. It can also drastically reduce the costs of waste disposal that is due to the drilling fluid and drilling cuttings can be discharged directly to the sea.
A high temperature polymer filtrate reducer with temperature resistance for 200°Cand viscosifier with temperature resistance for 180°C both have been developed, which are used for high temperature filtration control and rheology regulation. This new system consists of these two high-temperature synthetic polymer materials, along with a special nano-plugging agent, glycol shale inhibitor, extreme pressure lubricant, and barite or formate weight materials. The formula and performance of drilling fluid are studied which suitable for drilling under different formation pressure coefficients, and the performance of drilling fluids at different bottom hole temperatures are also reviewed, so as to prove it can provide superior fluid performance for various harsh drilling conditions. The test results showed that the drilling fluid has the following main technical features: temperature resistance for 200°C, 200°C thermal stability time more than 72h, HTHP water loss 15~25mL, aquatic biological toxicity LC50 value higher than 100,000mg/L, luminescent bacteria EC50 higher than 300,000 mg/L. The test results from a high temperature deep well in Bohai offshore oil field, with depth of the bottom well 6066m, and the bottom temperature 204°C, are also presented.
This drilling fluid is environmentally friendly and meets the discharge requirements of offshore, which can greatly improve the HSE operation level and eliminate the rig costs associating with drilling and waste management, especially in remote sea and deep sea drilling, that the disposal cost of waste drilling fluid accounts for more than 30% of the total drilling fluid cost.
Novel Pseudo Dry Gas System for Extended Subsea Tie-Backs
Authors: Rafty Andrew , Thomas Lee , Liebana Laura , Wood Terry , Stokes Stephen 
Published: April 2019

Abstract
The ‘Pseudo’ Dry Gas (PDG) subsea concept is being developed to dramatically improve the efficiency of subsea gas transportation by removing fluids at the earliest point of accumulation. The technology will increase the geographical reach from receiving gas terminals, allowing asset owners to prolong production life without the need for more expensive design solutions. This paper will provide an overview of the innovative technology, demonstrating that a 200 km plus tie back can be achieved, without compression.
Increasing the distance of subsea tie-backs increases the liquid inventory, with constraints on pipeline diameter for slug free flow. The PDG concept is based on a main gas line integrated with piggable gravity powered drain liquid removal unit and pumps (a smaller fluid line transports separated liquid). Multiple units are specified to drain liquids as they condense in the line, maintaining near dry service. Liquid free operation removes the constraint on pipeline diameter. Specification of a large diameter pipe (within installation limits) reduces backpressure on the wells, enhancing recovery. Minimum stable flow limits are removed, improving tail end recovery.
Current stranded gas development options (subsea compression, floating facilities, FLNG) generate a step change in costs which can make a project uneconomic. This is even more acute in mature and semi-mature basins where existing gas processing facilities / LNG terminals already exist offshore or onshore along with sunk costs from the exploration. A case study for a 185 km pseudo dry gas subsea tie-back to shore demonstrates the PDG concept feasibility. This result is used to argue that the PDG concept should be included in the suite of subsea processing options considered by Operators in early field development planning.