bluuebunny/crossref_metadata_2025 huggingface dataset:
A Comprehensive Review on Gas Hydrate Reservoirs: Formation and Dissociation Thermodynamics and Rock and Fluid Properties
Authors: Fakher Sherif , Elgahawy Youssef , Abdelaal Hesham
Published: April 2019

Gas hydrates reservoirs are a type of unconventional reservoir that is an extremely abundant and ubiquitous source of energy. They are also relatively cleaner than most other hydrocarbon sources which makes them an even more attractive source of energy. The potential of this source of energy has, however, not been utilized since very little production has ever taken place from these reservoirs due to their complexity. This research provides an understanding of gas hydrates thermodynamics and reservoir properties in order to assist in properly modelling the hydrate flow in porous media. The research also provides a road map to the current production methods that have been used in pilot tests in order to produce from gas hydrates reservoirs. The production methods explained include depressurization, thermal stimulation, inhibitor injection, combined methods, carbon dioxide injection, and mining. The mechanism of each method is fully explained, and the advantages and disadvantages of each method are also explained. Several case studies worldwide are also discussed to show how each production method has been used to produce from the gas hydrate reservoirs. The results from the case studies are also used to reach conclusions on how each method can be improved upon. To the author's knowledge, no publication has provided a complete overview on gas hydrates and their production mechanism which makes this research a crucial step in providing an overview on many aspects of gas hydrates reservoirs and their production mechanisms and potential. Understanding the mechanisms to produce from gas hydrate reservoirs is a crucial step in the hydrocarbon industry to allow us to tap into this vast source of energy in the near future.
Numerical Analysis of Complex Fracture Propagation Under Temporary Plugging Condition in Natural Fractured Reservoir
Authors: Lu Cong , Li Junfeng , Luo Yang , Chen Chi , Xiao Yongjun , Liu Wang , Lu Hongguang , Guo Jianchun
Published: April 2019

Temporary plugging during fracturing operation has become an efficient method to create complex fracture network in tight reservoirs with natural fractures. Accurate prediction of network propagation process plays a critical role in the plugging and fracturing parameters optimization. In this paper, the interaction between one single hydraulic fracture within temporary plugging segment and multiple natural fractures was simulated using a complex fracture development model. A new opening criterion for NF penetrated by non-orthogonal HF already was implemented to identify the dominate propagation direction of HF under plugging condition. Fracture displacements and induced stress field were determined by the three dimensional displacement discontinuity method, and the Gauss-Jordan and Levenberg-Marquardt methods were combined to handle the coupling between rock mechanics and fluid flow numerically. Numerical results demonstrate that the opening and development of NF are mainly dominated by its approaching angle and relative location. For a certain NF crossed by HF within plugging segment, HF tends to propagate along the relative upper part when the approaching angle is less than 90°, otherwise the lower part will be easier to open. The farther interaction position is away from HF tip, the easier NF with approaching angle less than 30° or larger than 150° can be open, and the outcome will be opposite if the approaching angle is larger than 45° or less than 135°. Higher approaching angle and plugging strength is necessary for expanding the position scope of NF that can be opened around HF. Under the impact of plugging, fluid pressure in HF plummets at the beginning of NF opening and keeps decreasing until NF extending for a certain distance or encountering secondary NFs. Fluid pressure drop occurs mainly in the unturned NF, together with the width of unturned NF is significantly lower than that of turned NF and HF. Sensitivity analysis shows that the main factors, such as geometry, aperture profile, and fluid pressure distribution, affecting the network progress under temporary plugging condition are the horizontal differential stress, NF position, approaching angle, plugging time, and plugging segment length. The simulation results provide critical insight into complex fracture propagation progress under temporary plugging condition, which should serve as guidelines for welling choosing and plugging optimization in temporary plugging fracturing.
Implementation of a Scalable Distributed Cloud Computing Platform for Fast Real-Time Reservoir Development
Authors: Gutierrez Edgar , Wu Mark Hsu-Hsiang , Dong Weixin , Efimov Ivan
Published: April 2019

Recent developments of new ultra-deep logging-while-drilling (LWD) resistivity tools have increased usage for on-demand computational infrastructure. The tools are capable of providing much deeper determinations on formation geologies than conventional electromagnetic (EM) resistivity tools, allowing more accurate real-time wellbore adjustment and optimization. This technique efficiently explores reservoir insights for maximizing oil production; however, the time to process raw measurements into useful geological information is long owing to the complexity and large amount of data associated with the tools. The conventional computation platforms are not efficient enough for both real-time and post-well formation evaluations based on this tool's measurements.

This paper introduces a high-performance computing (HPC) platform which provides flexibility among different deployment architectures and large-scale cloud infrastructure. This enables numerous computational resources to quickly process raw data and provide the information needed to successfully steer a well. The new HPC platform has 50% more efficiency compared to conventional parallelization methods, such as Open Multi-Processing (OpenMP), using same amount of CPUs. Furthermore, faster computation is achievable owing to the scalability of the HPC implementation as well as the flexibility of available assets in the cloud or on-premises environments, which are beneficial for applications with heavily computational requirements and short time constraints.
Understanding the Geomechanical Challenges and Risk Mitigation in Sichuan Shale Gas Drilling, China
Authors: Gui Feng , Wang Shanshan , Bordoloi Sanjeev , Ong See Hong
Published: April 2019

The drilling of shale gas development wells in the Sichuan Basin has been problematic, with stuck pipe and fluid loss events reported in many wells. These events hindered the development efforts as operators whose aim is to reduce drilling costs and increase drilling speed are faced with developing drilling strategies for more cost effective well delivery. As such, it becomes critical to understand the key mechanisms of borehole failures and fluid losses during drilling of the laterals so that proper mud weights and mud designs can be formulated to overcome the drilling challenges.

To optimize the entire drilling process from different angles, an integrated approach is required to combine the knowledge and expertise from different disciplines. A robust geomechanical model and detailed diagnostics of the borehole instability related problems are key and form the basis for the drilling risk management. To build a robust geomechanical model, several representative areas in the Sichuan Shale Gas play were reviewed using a consistent approach. A general understanding of the in-situ stress conditions and rock mechanical properties of the Longmaxi Shale Gas reservoir was developed by combing data and knowledge in the different areas. Using the geomechanical model, a series of newly drilled horizontal wells was also reviewed so that the main causes of stuck pipes and fluid losses can be determined.

Based on the geomechanical model and drilling experiences review, risks that could potentially cause non-productive time (NPT) during drilling of the planned wells were postulated and listed, and each risk was then assessed in detail so that a thorough understanding of the risk factors can be achieved from different drilling perspectives. Consequently, a multi-disciplinary mitigating solution was proposed in order to help with reducing the occurrence of any borehole instability-related problems. The integrated drilling optimization plan was executed successfully during the drilling of the horizontal wells in the Sichuan Basin.

The increase in understanding of the geomechanical issues in the Sichuan Shale Gas drilling indicated that common trends in shale characteristics are present although it is widely accepted that shale types and stress conditions are different in each field. With the geomechanical models being calibrated from information in different areas, uncertainties are reduced and the robust models in turn provide solid foundations for risk identification and mitigation, leading to successful and economical drilling of the long laterals. However, it is a long and continuous learning process in order to apply this integrated approach effectively. To achieve continuous improvement, the geomechanical model and mitigating solutions need to be refined regularly following the drilling process while further information and knowledge are being acquired in the Sichuan Shale Gas area.
A Multiphase Choke Temperature Model for High-Pressure Gas/Water/Glycol Mixtures
Authors: Jia Wenlong , Yang Fan , Mu JunCheng , Cheng Tingting , Li Changjun , Zhang Qi
Published: April 2019

Co-existence of gas, water and glycol is commonly in produced fluids of high-pressure gas wells due to formation water production and hydrate inhibitor injection. The interaction between the polar water and glycol molecules can affect the phase behavior and subsequent temperature change during gas flowing through chokes at wellheads. This paper presents an isenthalpic flash method based on the cubic-plus-association equation of state (CPA EOS) to calculate the temperature at the downstream of the choke. In comparison with the traditional isenthalpic flash algorithm, this new method accounts for the self- and cross-association between polar water and glycol molecules, yielding more accurate enthalpy calculation results for fluid containing water and glycol as well as choke temperatures. The proposed model is validated with field test data. Results demonstrate that the average absolute deviations between the measured and calculated temperatures at downstream of chokes based on the proposed method are less than 1.6°C even for vapor-liquid-aqueous three-phase mixtures at pressures up to 100 MPa. Results yield from the proposed method are more accurate than those calculated from the SRK EOS combining with the Peneloux volume shift method and the Huron-Vidal mixing rule.
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

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

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

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

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

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

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

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

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.
Determining Critical Flowrate in High CO2 Content Carbonate Field, Sarawak Basin, Offshore East Malaysia
Authors: Kashim Muhammad Zuhaili , Giwelli Ausama , Clennell Ben , Esteban Lionel , Noble Ryan , Vialle Stephanie , Ghasemiziarani Mohsen , Saedi Ali , Md Shah Sahriza Salwani , M Ibrahim Jamal Mohamad
Published: April 2019

In line with PETRONAS commitment to monetize high CO2 content gas field in Malaysia, C Field which is a carbonate gas field located in East Malaysia's waters with approximately 70% of CO2 becomes main target for development because of its technical and economic feasibility. Injectivity has been determined as one of the key parameters that determine the success of CO2 storage in field operations. In order to characterize the CO2 injecitivity behavior in C Field, long duration coreflooding experiments has been conducted on two representative core samples under reservoir conditions. The first set of coreflooding test has been conducted on gas zone sample and another one is on aquifer sample. Two important approach has been applied in the experiment in which the first one is where the base rate is established after each incremental stage and the second one is the pre-equilibration of carbonated brine with standard minerals based on the percentage of core mineralogy before saturating the core with aquifer brine to mimic the insitu geochemical conditions of the reservoir. Pre- and post-flooding characterization was conducted using Routine Core Analysis (RCA), X-Ray CT-scan, Nuclear Magnetic Resonance (NMR) and Inductive Coupled Plasma (ICP) to examine the porosity-permeability changes, pore size alterations and the geochemical processes that might take place during CO2 flooding. Based on the differential pressure data, it showed no clear indication of formation damage even after injection of large CO2 pore volume. Pre and post-flooding characterization supported the findings where minor dissolution/precipitation is observed. Overall intrepretation indicates that the critical flowrate is not yet reached for both samples within the maximum rates applied.
Borehole Electromagnetic Technique for Reservoir Imaging and Monitoring from Uncased Sections of a Well Using Adjacent Casings as Receiver Antennas
Authors: Sena Armando
Published: April 2019

A novel borehole electromagnetic (EM) acquisition system and technique for monitoring hydrocarbon reservoirs is presented. The system works for production wells that have an open section (uncased) and an adjacent metallic cased section (or liner). The sources are deployed along the uncased sections and the upper casing is used as a long antenna to construct an EM receiver that increases the sensitivity of the system one or two orders of magnitude relative to existing EM technologies, and therefore, allows us to obtain an improved electromagnetic technique for imaging and monitoring the reservoir hundreds of meters from the well. Simulations of a time-lapse EM survey is presented to demonstrate the capabilities of the proposed system.
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

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.
Joint Migration Inversion Versus FWI-RTM: A Comprehensive Comparison Study Based Upon 2D Realistic Offshore Models
Authors: Sun Yimin , Kim YoungSeo , Qu Shan , Verschuur Eric
Published: April 2019

Joint migration inversion (JMI) is a recently developed technology that aims at incorporating the seismic velocity model update and acoustic migration, including all multiple scatterings, into one closed-loop process. Full waveform inversion (FWI) is a commonly accepted technology for velocity model building, and reverse-time migration (RTM) is the main method adopted for depth imaging. In this paper we first use a 2D realistic deep water model to benchmark JMI against a workflow of FWI combined with RTM. With some insights on JMI gained from this comparison study, we point out that a good niche for JMI is to provide a high quality initial velocity model. We further demonstrate the performance of JMI on a 2D deep water field dataset with an initial velocity model derived from migration velocity analysis (MVA).
Novel Pseudo Dry Gas System for Extended Subsea Tie-Backs
Authors: Rafty Andrew , Thomas Lee , Liebana Laura , Wood Terry , Stokes Stephen
Published: April 2019

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.
The Successful Selection, Optimization and Implementation of Adjust While Drilling AWD Flowchart in Offshore Oil Field of Bohai Bay, China
Authors: He Yifan , Hu Yong , Shi Hongfu , Zhou Junliang , Shu Xiao
Published: April 2019

BZ field is located at Bohai Bay of China, it is featured with multiple complex fluvial reservoirs with small lateral extension (100-300m wide) and thin accumulation (6-12m). Many channels are isolated and poorly connected across the field. As a result of the fluvial narrowness, low reserve abundance and limited natural energy, the development of this field was tied back into the neighboring field facilities and was categorized as the marginal value field with low ROR (rate of return). This paper presents a successful implementation of the flowchart of "adjust while drilling" to tap these kinds of reservoirs during the E&P circles.

In the ODP design phase, 13 well slots were reserved for the future use. And the overall geological characteristics is predicted to be much complex.

In order to mitigate risks, identify potential opportunities and improve the benefit of plan, a work flow integrating seismic, geology, logging and productivity forecast, with exploration concepts was designed during development phase to optimize drilling schemes.

The process is divided into 5 steps: 1. Locate and characterize key sands by combined analysis of logging and seismic data. 2. Recognize hydrocarbon migration pattern, identify potential oil-bearing sands, and estimate OOIP; 3. Design well patterns and forecast productivity based on the reservoir characteristics and OOIP. 4. Optimize drilling sequence and well trajectory; evaluate reservoir potential and risks based on data from drilled wells, and then optimize future well locations. 5. Apply logging while during drilling (LWD) and Periscope to reach optimal landing point and ensure high NTG.

Modifications to the ODP mainly include: 1. Staggered line well pattern was adopted to develop single story channel. 2. A large number of horizontal wells were adopted. 3. Understanding on the relationship between production wells and injection wells were improved by placing the deviated injection wells at the multi-stored channel stacking. And the well spacing was determined based on the updated reservoir properties to warrant waterflood sweeping conformance and efficiency. 4. Newly proved potentials were targeted through remaining reserved slots.

Through this process, OOIP has increased by 108%, production well counting has risen from 19 to 32, locations of 9 wells reserved during ODP phase have been successfully optimized and redirected; independent P-I pairs have been positioned for each single story channel with the P-I ratio over 90% and good response between those pairs. Average productivity has reached 1.5 times of the designed level.

The overall successful development of BZ field has proved the effectiveness of the flowchart, which is designed for the risk mitigation, potential tapping, slot utilization and financial performance enhancement. Therefore, it provides an insightful guidance for the future similar reservoirs development program design.
Effective Igneous Reservoir Identification and Controlling Factor Analysis in Eastern Sag of Liaohe Depression, China
Authors: Hu Zhenhua , Zhang Shenqin , Wu Fangfang , Liu Xunqi , Wu Jinlong , Li Shenzhuan , Wang Yuxi , Zhao Xianran , Zhao Haipeng
Published: April 2019

The igneous reservoir of Shahejie formation in eastern sag of Liaohe depression is characterized by complex geological environment, variable lithology and high heterogeneity. Reservoir evaluation is difficult only based on conventional logs due to complex lithology and pore structures. Effective igneous reservoirs were identified and reservoir controlling factors were analyzed based on effective porosity calculation, pore structure analysis, lithology identification, lithofacies analysis, fracture evaluation and heterogeneity analysis by combing nuclear magnetic resonance data, micro-resistivity image data, conventional logs as well as mud logging data.

Based on our study, the igneous reservoirs in the study area are more related with effective porosity and pore connectivity, and less related with fractures. Good reservoirs are mainly distributed on the top part of explosive facies and effusive facies, where lithologies are mainly Trachyte, volcanic breccia and breccia-bearing tuff. The weathering leaching process is quite important for igneous reservoirs, but the reservoir qulity would not be good if the weathering process is too strong as it will lead to low effective porosity.

The accuracy of igneous reservoir evaluation gets improved a lot by this integrated approach and the conclusion from this study will help to optimize igneous reservoire exploration plan.
Fracture Network Mapping Using Integrated Micro-Seismic Events Inverse with Rate-Transient Analysis
Authors: Wang Wendong , Zhang Kaijie , Su Yuliang , Tang Meirong , Zhang Qi , Sheng Guanglong
Published: April 2019

In the development of shale oil and gas reservoir, hydraulic fracture treatments may induce complex network configuration, which is very challenging to characterize. The existing fracture properties interpretation methods mostly rely on simplifying assumptions and are typically empirical in nature. The aim of this work is therefore to introduce an integrated framework involving fractal theory, inverse analysis of micro-seismic events (MSE), and rate-transient analysis to map the heterogeneity and distribution of fracture properties. In this work, a general framework is proposed to characterize both the geometry configuration and the owing properties of the complex fracture network (CFN). The CFN characterization framework is naturally divided into two stages: characterize the fracture geometry network by microseismic data and characterize the fracture dynamic properties by production data. In the fracture configuration characterization stage, a stochastic fractal fracture model based on an L-system fractal geometry is applied to describe the CFN geometry. Moreover, the genetic algorithm (GA) as a mixed integer programming (MIP) algorithm are applied to find the most probable fracture configuration based on the microseismic data. As to the owing properties characterization stage, we introduced embedded discrete fracture model (EDFM) for the computational concern and a Bayesian framework is used to quantify these fracture dynamical properties e.g., conductivity, porosity and pressure dependent multiplier by assimilating the production data. In addition, rate-transient analysis is also applied to calibrate the total fracture length and estimate effective stimulated-reservoir volume (ESRV). In order to validate this framework, a synthetic numerical case is developed. The result indicates that our integrated framework is able to characterize both CFN configuration and properties by assimilating microseismic and production data sequentially. The proposed workflow shows that the characterized CFN model would yield reasonable probability predictions in unconventional production rate.
An Assessment of the Impact of Rheological Properties on Rate of Penetration Using Data Mining Techniques
Authors: Al-Hameedi Abo Taleb T. , Alkinani Husam H. , Dunn-Norman Shari , Flori Ralph E. , Alsaba Mortadha T. , Amer Ahmed S. , Al-Bazzaz Waleed H.
Published: April 2019

The rate of penetration (ROP) plays a major role in reducing drilling costs, making it an important area of investigation. There are various controllable and uncontrollable factors that affect the ROP, and the variation in these variables affecting the ROP made it a very pivotal drilling parameter that has a significant effect on non-productive time. In this work, sensitivity and statistical analysis were carried out using data from over 1000 wells in Basra oil fields, Iraq. The scope of this work is to determine the effect of rheological properties on ROP, to provide a method for estimating the recommended range for drilling fluid properties based on data mining techniques.

In this work, huge real field data from over 1000 wells drilled in Basra oil fields, Iraq were gathered and analyzed to better understand the characteristics of a drilling fluid that enhance ROP and quantify the impact of each drilling fluid rheological properties on ROP. The data used in this study were collected from mud logging data, daily drilling reports (DDR), and geological information. Statistical and sensitivity analyses were performed in order to identify the relationship between ROP and drilling fluid rheological properties. The correlation coefficient (CC) was utilized to understand the effect of solid content (SC), yield point (Yp), and plastic viscosity (PV) on ROP. The results showed that SC is the most influential rheological property on ROP, then PV and finally Yp. In addition, this work demonstrates how bit hydraulics can be improved by means of modifying the rheological properties rather than adjusting the flow rate or nozzle size.

Large-scale collection and interpretation of field data or in other words "data mining" can be considered as a strong tool in understanding the impact of different parameters on the ROP in order to estimate the recommended range of rheological properties, which will result in improving the ROP.