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IPTC 2013: International Petroleum Technology Conference
- Conference date: 26 Mar 2013 - 28 Mar 2013
- Location: Beijing, China
- Published: 26 March 2013
51 - 100 of 581 results
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Modeling of Spent - Acid Blockage Damage in Stimulated Gas Wells
More LessAqueous fluids introduced by different stimulation treatments cause water blockage in the near-wellbore region of wells. This water blockage acts the same as formation damage when the well is put back on production. One of the examples is when gas wells in carbonate reservoirs are acid-stimulated; the wormholes that propagate into the formations might be surrounded by a region of high water saturation created by the leakoff of spent acid. The spent-acid blockage damage could be severe, especially in lower permeability regions where capillary forces are relatively high. This paper presents a model that investigates the spent-acid damage in wormhole region of acid-stimulated gas wells. The phenomenon of spent-acid blockage was first investigated in the experimental study to identify the problem. A labscaled model was then developed to characterize the capillary pressure and relative permeability behavior by matching the results from the model to the experimental observation. We then extended the study to field-scale by approximating the wormhole as a long, slender half-ellipsoid centered in an ellipsoidal flow field. The simulations that focused on the displacement regime of spent acid recovery process were developed. These models were solved numerically to predict pressure behavior and spent acid distributions for the flow-back process. With the models, we studied the effects of several key factors, such as capillary pressure, relative permeability, and addition of additives, on the efficiency of spent acid recovery. The results show that common additives routinely added to acid systems may aid, or hinder, spent acid recovery, depending primarily on their effects on rock wettability. With the studies performed on the model developed, we provide recommendations for minimizing spent acid damage to gas well productivity.
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Solid Deposition in Gas Turbines of a Cogeneration Plant, Sumatra, Indonesia, Mechanism and Remediation
Authors R. Hwang, J. Iwamoto, P. Coughlan and D. KumboroA rapid build up of solid deposits occurred in the fuel system of gas turbines of the Duri Field Cogen plant and forced to shut down the plant frequently, which resulted in a great reduction in both electric power and steam output and hence curtailed tremendously the field production of heavy oil. A comprehensive study of the fuel gas delivery system and fuel gas quality was undertaken to determine the root cause of solid deposition. The results of the study show that the pale yellowish solids recovered from the fuel system are mixtures of elemental sulfur and wax. Both elemental sulfur and wax were derived from the fuel gas delivered to the plant where they were detected in the gas at trace levels (sub ppm). The occurrence of sulfur and wax deposition was somewhat surprising as the routine monitoring of the gas showed their levels were well within operation specifications all the time. Interpretation of composition data of numerous gas samples and solid deposits combined with operation conditions of gas turbines and gas phase chemistry provided insights of the solid deposition process. The problem was caused by the significant pressure drop encountered in the fuel gas delivery system of the turbines, which induced a measurable temperature drop and the associated phase changes of elemental sulfur and wax hydrocarbons from gas phase to condense phase leading to their deposition and turbine plugging. A remediation measure was developed and implemented.
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Study of Progressive Flow Profile of Multiphase (Oil-Water-Gas) Flow for Downhole Monitoring Applications
More LessComputational fluid dynamics (CFD) has been actively used to make flow profile predictions in downhole oil and gas environments. The flow in oil wells inherently consists of oil, water, and gas phases. Flow profile predictions are complicated by parameters such as fluid properties, flow velocities, area, and well inclination. A proper understanding of flow behavior under various operating conditions is critical when designing downhole equipment and flow metering applications. This paper presents case studies involving the three-phase flow of oil-water-gas in a downhole tubular. Phase distribution is analyzed for different compositions by varying the individual phase volume fractions. Various flow regimes, such as stratified flow, homogeneous flow, and bubbly flow, are studied individually as well as in their transition from one regime to another. The transition criteria were also studied. Extensive efforts were focused on understanding random bubble distribution, bubble breakup, bubble-relative movement, distortion, and diffusion in fluid flow with respect to flow variables. Finite volume phase distribution for oil vs. water is obtained as a function of time and distance (coherence) for multiphase flow in production tubulars. The effect of geometry changes with the objective of flow homogenization is also studied to enable the locations and numbers of monitoring devices to be fixed. CFD results were found to be comparable to single-phase analytical solutions. The examples and references included in the paper demonstrate the accuracy of the study results. The studies verify that an understanding of flow dynamics is essential to evaluate optimum configurations of the variables described. Advanced knowledge of flow characteristics enables engineers to deliver robust and maintenance-free sensing technology for use in a subterranean environment.
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Productivity Improvement Using Combination of Static and Dynamic Underbalanced Perforation in Tahe Oilfield, Tarim Basin, West China
Authors L. Fuqiang, L. Lian, L. Li, H. Yong and Z. GangIn concern with the skin factor value, the key significant components which do not directly depend on the nature of the reservoir properties are drilling/ completion fluid invasion damage and perforating induced damage. The oil & gas industry has been tried to eliminate the fluid invasion issue by applied deep penetration perforating to bypass the invasion zone and reach un-invaded reservoir. Lots of experiences and lab analysis shows that perforation performance is not meet the expectation of the productivity because of the perforation induced damage. As for now, static underbalanced perforation has been recognized by industry as one of the method to obtain clean perforation tunnel. However, static underbalanced perforation method is not always giving the expected productivity result. Experiments showed that the cleanup of the perforation tunnel was not totally dominated by the static under-balance pressure but also the transient pressure during the first 100 milliseconds of perforation or dynamic under-balance. The dynamic underbalance can be obtained by creating an instantaneous drop in pressure around the guns during perforating. The combination of static and dynamic underbalanced perforation with deep penetration charges which be able to bypass an invasion zone, can create a clean tunnel, and significantly reduce the post-perforating damage by killing fluid, and finally maximized the productivity. This combination of the static and dynamic under balance method has been applied in Tahe Oilfield. Tahe oilfield is located in Tarim basin with reservoir horizon depth of 4100m-4600m,temperature of 94-103
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An Integrated Model for Selecting The Best Fuel to Develop in The Value Chain of Natural Gas
Authors A. Mousaei, A.A. Ghadirian and M.A. HatefiA value chain is a series of events that takes a raw material and with each step adds value to it. Global interest in the application of natural gas in production and transportation has grown dramatically, representing a long-term, low-cost, domestic, secure, etc. alternative to petroleum-based fuels. Many technological solutions are currently considered on the market or in development that address the challenge and opportunity of natural gas. In this paper, an integrated model is introduced for selecting the best fuel to develop in the value chain of natural gas through the four options: Compressed Natural Gas (CNG), Liquefied Natural Gas (LNG), Dimethyl Ether (DME) and Gas-To-Liquids (GTL). The presented model uses the Multiple Attribute Decision-making (MADM) techniques to select the best fuel in the value chain of natural gas based on the criteria such as market situations, technology available and transportation infrastructure. The model recommends some key guidelines for two branches of countries i.e. those have natural gas resources and the others. We believe that applying the proposed model helps the oil & gas / energy ministries in most effective and productive manner dealing with his complicated fuel-related production and transportation decision-making situations.
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Anisotropic Waveform Inversion with Well Constraints
Authors C. Wang, D. Yingst, J. Leveille and R. BloorThe term, "Waveform inversion" (WFI), refers to a collection of techniques that use the information from seismic data to derive high-fidelity earth models for seismic imaging. The attractiveness of WFI lies mainly in its lack of approximations, at least in a theoretical sense, in contrast to other model determination techniques such as semblance or tomography. However, a whole raft of approximations must be made to make the technique viable with today's computing technology and restrictions of seismic acquisition. These are collectively referred to as "waveform inversion strategies" and in this paper we mainly discuss regularization and preconditioning strategies. Because the wavefields need to be accurately modeled to represent the kinematics of all the waves during WFI iterations, the effects of anisotropy often help to improve WFI results. In this paper, forward modeling and its adjoint computation are based on acoustic wave equations in vertical transversely isotropic (VTI) media. We introduce a multi-parameter inversion for P-wave velocity and anisotropy parameters. WFI is a highly nonlinear, ill-posed problem. We introduce additional information and turn the unconstrained optimization problem into a constrained optimization problem in order to reduce the ill-posedness. The geophysics of the problem leads to appropriate constraints, such as restriction of model parameters, or information from well logs. In this paper, we use well logs as constraints and solve the problem using the augmented Lagrangian method (ALM), a mathematical method that replaces a constrained optimization problem by a series of unconstrained problems. The ALM with well constraints aims at preserving velocity characteristics from well logs and providing us with more reliable velocity updates. This paper presents the acoustic anisotropic WFI implementation using ALM with well constraints. It also discusses practical strategies for regularization and preconditioning and their influences on the models that are obtained from WFI. We illustrate these approaches on a 2D synthetic Marmousi example and another application to 3D VSO OBC data from the Green Canyon area of the Gulf of Mexico. From the results, we show that multi-parameter VTI WFI with ALM provides us with more useful and reliable model updates. To further evaluate our WFI results, we also compare offset gathers and RTM images and illustrate their significant improvements using updated models generated from WFI.
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How Ball Materials Impact the Performance of Open Hole Fracturing Systems
Authors J. Baihly, J. Johnson, G. Melenyzer and I. Avilesmpletions rely on a sliding sleeve activated by a ball dropped from surface. Each ball travels the length of the lateral well to its intended operational depth, at which it meets a mated seat and isolates the wellbore below. Once the ball is in position, the sliding sleeve opens via the hydraulic force on the ball and seat, allowing a fracturing stage to commence. This dual function of the ball—activation and sealing—is of extreme importance for the stimulation treatment process. If the ball fails, it will result in bypassed pay zones and unintentional refracturing of previously stimulated zones. Although sometimes surface pressures can be used to infer ball behavior, often the pressure signals observed at surface cannot guarantee successful ball performance. This paper will present an extensive study of ball performance under pressure for the most common ball materials in the industry. Phenolic, composite and metal alloy materials were explored with the pros and cons for each investigated. In particular three main areas were analyzed: 1) molding, layering and extrusion of material versus inconsistencies in ball performance; 2) ball deformation at high pressure versus pressure required to bring the ball off seat; and 3) comparison of the performance of phenolic, composite and metal alloy materials for ball fabrication and their performance at high temperature. Manufacturing variability is also explored on this paper. The impact on the manufacturing process on the performance of balls made of the same material is presented by means of laboratory experimentation. The conclusions from this paper provide operators the necessary information to consider when making completion and ball material decisions in their field operations. In particular, the results of this testing may illuminate some previously unexplainable occurrences in graduated ball sliding-sleeve systems. This testing clarified that not all fracturing balls pumped in horizontal wells perform equivalently under wellbore fracture conditions.
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First Successful Application of an Environment Friendly Fracturing Fluid During On-The-Fly Proppant Fracturing
Authors M. Al-Ghazal, S. Al-Driweesh and F. Al-ShammariWith the increasing demand for natural gas, fracturing fluid technology needs to develop to enable optimized well completion operations with minimum ecological impact. The recent development of environmentally friendly polymer-free fracturing fluids — with superior operational performance — represents a major technological advance in the petroleum industry. The use of these new fluids during fracturing operations has the following benefits: minimized environmental footprint and formation damage, operational efficiency and simplicity, and maximized fracture conductivity. This paper discusses the first successful deployment, of an environmentally friendly polymer-free fracturing fluid, during on-the-fly proppant fracturing in Saudi Arabia. Also, the paper discusses the optimum layout of the fracturing equipment used during the job execution. The fluid was used to fracture a gas zone located between two water zones. Therefore, one of the main objectives of the treatment was to control the height of the fracture to not break through and contaminate the water-bearing zones. In addition, the fluid exhibited a low friction pressure and excellent proppant-carrying capacity. Moreover, the overall cost of this fracturing operation is in line with conventional, polymer-based fluid fracturing approaches. Evaluation of the post-treatment results demonstrated the following: very positive well productivity, improved fracture geometry (longer fractures with better height containment), and faster fracture cleanup time.
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The Role of Underground Storage in Large Natural Gas Production Operation
Authors M. Hoagie, G. Amorer, X. Wang and M.J. EconomidesUnderground natural gas storage has been used extensively in countries with large natural gas demand. Although much of the storage and withdrawal have been associated with seasonality, storage is becoming essential in an integrated natural gas management. It is particularly important in large operations, such as liquefied natural gas (LNG), where the total production rate must be maintained irrespective of the producing field day-to-day capacity. Natural gas storage capacity is affected by reservoir volume and tolerable pressure (to avoid fracturing) and injection or production rates that are affected by reservoir permeability, natural reservoir drive mechanism, well completion/stimulation, and the impact of cyclical losses. We present here a new sequence of calculations and estimations demonstrating salient elements of this practice: • Maximum capacity estimation with a new type of graphical construction, blending concepts of the classical p/Z vs. cumulative recovery straight line in natural gas production. • Prediction of withdrawal rates and time, constrained by decreasing storage pressure. • Determination of maximum or sustainable withdrawal rate for a period of time. In all cases, the injecting and producing wells are hydraulically fractured. The hydraulic fractures are designed for the withdrawal rate. Thus, the required number of wells is determined. These concepts are applied to a depleted natural gas field with an average pay of 33 ft and a permeability of 45 md. Forecasts of injection or production rates, cumulative storage or withdrawal, and pressure buildup or decline are presented as functions of time. The purpose of this case study is to sustain an LNG liquefaction operation for a specified period of time by employing underground natural gas storage.
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A New Model to Predict Average Pressure Difference of Liquid Droplet in Gas Well
Authors Z. Hai-Quan, L. Zhong-Neng, L. Tong, L. Kai and R. YongThe distribution of droplet surface pressure is uneven under the action of high velocity gas streams in gas wells, and there exists a pressure difference which leads to droplet deformation before and after the droplet. Moreover, it affects the critical liquid carrying rate. The pressure difference prediction model must be determined, because of the existing one lacking theoretical basis. Based on the droplet surface pressure distribution in high velocity gas streams, a new model is established to predict the average differential pressure of droplets. Compared with the new differential pressure prediction results, the existing pressure difference prediction results overvalued by 46.0%.This article also improves four gas-well critical liquid carrying models using the proposed pressure difference prediction model, and compares with the original one. The result indicates that the critical velocity of the original models is undervalued by 10% or so, due to the overestimate to the pressure difference.
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Field Optimization of Acid Concentration of Visco-Elastic Based Acid Using Fiber Optic Enabled Coiled Tubing (FOECT)
Authors M.A. Dhufairi, S.H. Al-Mutairi, D. Ahmed and M. BalSuccess of matrix stimulation treatments depend on the uniform distribution of treating fluids over the entire production/injection interval. Thus, when acid is pumped into a well, it naturally flows to the most permeable/least damaged zone. To avoid improper placement of acid into one interval of a zone of different injectivities, diversion techniques can be applied. Diversion can be accomplished by either mechanical means or chemical means. Diverting chemicals are deposited over the perforations or the formation. When deposited, they form a layer with a lower permeability than the formation it is covering. This imposes an additional pressure drop needed to penetrate the cake will cause the fluid to divert to another part of the perforated interval. Eventually, uniform injection is accomplished across the whole interval. Different concentrations of diverting agents can be used to get the required diversion, but how to know if the diverter pumped is indeed diverting or not is a challenge. Bottom-hole pressure or temperature responses can be checked during the job to get an idea if diverter is working properly. Thus, Fiber Optic Enabled Coiled Tubing with Fiber Optic Enabled Bottom-hole Assembly (FOEBHA) with pressure and temperature sensors for real-time downhole measurements and Distributed Temperature Sensing (DTS) is the best solution available. This paper describes the use of different concentrations of diverter i.e. visco elastic diverting agent and the behavior responses of downhole parameters with their usage.
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Research and Application of Fire Flooding Technologies in Post Steam Injected Heavy Oil Reservoir
Authors X. Changfeng, G. Wenlong and H. JihongAs fire-flooding has strong adaptability to develop the reservoir, it can be considered as a follow-up EOR technology of the low economic profit and high oil recovery reservoirs flooded by water or steam. Because of the complicated secondary water and steam channels, fire-flooding in post-steam-injected reservoir is far different from that in original reservoir. In this paper, the mechanism and problems associated with development engineering of fire-flooding in post-steam-injected heavy oil reservoir was studied systematically by using 1D&3D physical simulation systems and reservoir numerical simulator. The temperature of combustion zone decreased and high-temperature zone enlarged because there existed secondary water formed during steam injection which could absorb and carry heat towards producers out of combustion front during fire flooding, but high saturation of water in layer caused by secondary water had less influence on the quantity of fuel deposit and air consumption. In the process of 3D fire flooding experiments, air override was observed during combustion front moving forward and resulted in a coke zone in the bottom of layer, and the ultimate recovery factor reached 65%~70% on fact that the saturation of oil within the coke zone was no more than 20%. The flooding model, well pattern, well spacing, and air injection rate was optimized according to the specific property and the existed well pattern in post-steam-injected heavy oil reservoir, and the key techniques of ignition, lifting, and anticorrosion was also selected in the same time. The pilot of fire flooding in H1 block in Xinjiang oil field was carried out since Dec. 2009 on the base of these research work, and now the pilot begin to show the better performance. The production oil is about 49t/d, and the water cut is stable below 70%, the air oil ratio is about 2000m3/t, the good performance is gained for this kind of abandoned post-steam-injected heavy oil reservoir.
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Lithofacies Classification: From Sedimentologic Analysis to 3D Reservoir Modeling
By J. ChenDeepwater depositions are complicated processes reflecting the combined effects of global eustatic sea-level variation, regional sediment input, climate, paleo-topography, and many other factors. The complex depositional processes give rise to various depositional facies, which significantly impacts reservoir connectivity and quality. The description of deepwater depositional facies can be performed in details at sedimentologic level based on core materials, in which complex sedimentation feature such as grain and matrix composition, grain-size distribution, color, sorting, roundness, climbing ripple, cross bedding, various amount of mud clasts within massive sandstone, degree of bio-alteration, and so on, are considered to classify the facies. Such a detailed facies analysis is necessary because it provides information regarding the geological processes and associated environment that is responsible for the accumulation of the reservoir rocks. However, when dealing with reservoir modeling, it can be too sturdy to include all detailed facies types from sedimentologic description. Main attention should be paid to identify just the major facies types that bear geological environment signature, yet simple enough for any reservoir simulators to handle. This study integrates outcrop data with subsurface data, compares patterns of facies variations from outcrops to several deepwater fields, and suggests that for reservoir modeling purpose most of the deepwater turbidite fields can be described by four major facies types, channel/lobe axis, off-axis, margin, and background. Each of these facies has its range of reservoir properties, and the overall performance of the reservoirs depends on the relative proportions of various facies types and their spatial arrangement. By applying advanced technology, log data are trained to recognize facies types based on the patterns defined from core studies. The detailed log facies types can also be represented by four major groups. As a result, integration of core, log, and outcrop data leads to a robust solution for handling the complex lithofacies issues in 3D geological model, enabling better development of strategy for field development.
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New Stimulation Technologies in a Major Gas Field in the Middle East
Authors M. Al-Ghazal, S. Al-Driweesh, A. Al-Sagr and F. Al-GhurairiIn their natural state, most gas wells in the Middle East do not produce at their optimum level. This is mainly attributable to formation tightness or near-wellbore damage caused by drilling operations; however, a properly designed and executed stimulation program can enable more commercial gas production rates at higher flowing wellhead pressures (FWHPs). For this reason, and others, stimulation jobs (e.g., hydraulic fracturing and matrix acidizing) are common completion operations in the Middle East. In recent years, stimulation technologies have witnessed major advances, as their use has been the main driver for production from tight reservoirs worldwide. This paper outlines eight new stimulation technologies that have been recently deployed in a major gas field in the Middle East. In addition, the paper looks at candidate selection, the main characteristics and benefits of the technologies, and post-treatment results. Overall, the production results from the use of these technologies have been very positive and impressive, and the forecast is that their implementation will grow considerably over the coming years. The value of these new technologies will become even more significant as our industry accelerates the development of unconventional resources.
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Joint Inversion of Time-Lapse Crosswell Seismic and Production Data for Reservoir Monitoring and Characterization
Authors L. Liang, A. Abubakar and T.M. HabashyWe present a fluid-flow constrained inversion approach for joint interpretation of time-lapse seismic and production data. In this approach, the full-waveform seismic inversion is integrated into the traditional history-matching process. Hence, the interpretation of time-lapse seismic data is constrained by the fluid-flow physics in the reservoir. The key component in the workflow is a fluid-flow simulator, which computes not only the production data in the wells, but also the temporal and spatial distribution of fluid properties, such as fluid saturation and pressure. These fluid properties, together with prior rock properties, can be transformed to acoustic properties using the prescribed petro-elastic model. A finite-difference frequency-domain acoustic solver is then used to simulate the time-lapse seismic responses on the reservoir. We use a multiplicative-regularized Gauss-Newton scheme to update the reservoir model iteratively until good match between measured and simulated data is achieved. The derivative of seismic data with respect to acoustic properties is calculated using the adjoint method, and then connected to reservoir parameters using a chain rule derived from the petro-elastic model, while the derivative of production data with respect to reservoir parameters is calculated using the gradient-simulator method. A synthetic crosswell example is employed to demonstrate that the estimation of permeability and flooding front movement can be significantly improved from the joint inversion of time-lapse seismic and production data.
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Effective Uncertainty Management Strategies to Successfully Deliver Horizontal Well in Changbei Gas Field
More LessMulti‐lateral horizontal wells are being applied in field development extensively, especially in unconventional oil and gas reservoir in order to maximize economic development of it. Uncertainties are always present and are very significant in unconventional oil and gas reservoir. These uncertainties could be Geology‐related and Engineering‐related or exist in the available data. Industry has been using uncertainty analysis to identify, address and mitigate risk. Horizontal well objectives in Changbei Field are to drill 2km dual lateral wells into thin reservoir while maximizing production and minimizing well cost. One of prime challenges was to land and drill in <10m reservoir in channel margin by using conventional tool under limited budget, this was particularly challenging in Changbei’s braided channel complex with high reservoir heterogeneity. By classifying all uncertainties available during delivering horizontal well, this paper takes Changbei tight gas field as an example to discuss an integrated application of the workflow performing uncertainty analysis on geological and engineering parameters and identify the effective uncertainty management strategies based on it. The proposed uncertainty management strategies have been applied to tens of horizontal well in Changbei gas field, and the operation result show that it reduced the associated risks or uncertainties substantially compared to the pre‐applied case and improved horizontal wells planning and placement efficiently and economically.
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Hydraulic Fracture Initiation While Staged Fracturing for Horizontal Wells
More LessHydraulic fracturing is recognized as a successful stimulation technique for enhanced hydrocarbon recovery from unconventional tight reservoirs. Technological advancement in directional drilling has led the petroleum industry to drill arbitrarily oriented wellbores for exploitation of reservoirs, which otherwise could not be economically produced. Prediction of fracture initiation from such wellbores is therefore essential for petroleum industries to undertake efficient hydraulic fracturing stimulation tasks. In a hydraulic fracturing process, fluid is injected under pressure through the wellbore in order to overcome native stresses and to cause failure of rocks, thus creating fractures in a reservoir. These fractures create a passage through which hydrocarbon flows into the well from the shale formation. Based on the superposition principle and elasticity theory, a total stress field mathematical model while staged fracturing for horizontal well is abstractly presented in this paper, considering systematically influencing factors such as wellbore pressure, in-situ stress distribution, seepage effect of fracturing fluid, and induced stress produced by hydraulic fracture. The law of initial and subsequent fractures initiation is studied. The results show that the initial fracture initiation is affected by the wellbore azimuth angle, and it is easy for transverse fractures to form when the minimum in-situ horizontal stress along the wellbore direction. The stress distribution around wellbore is influenced by induced stress field, and when the initial fracture height is constant, the effect decreases gradually along wellbore direction until the combined stress field tends to the in-situ stress field. In a certain position from the initial fracture, the bigger the fracture height, the greater the induced stress, and in particular, the influence on induced stress along the wellbore direction is more obvious. Induced stress can increase subsequent fractures initiation pressure, whose level will reach 30% and increase as the fracture height increases. When fracture height is constant, the increase level of initiation pressure decreases rapidly with the increase of fracture spacing. There is well coincidence between computational solution and measured result. Results from the analytical and numerical models used in this study are interpreted with a particular effort to enlighten the causes of abnormally high treating pressures during hydraulic fracture treatments, as well as engineers study recovery techniques.
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Advanced Oxygen Enrichment Technology for Cost Effective Sulfur Recovery Processing Facility Applications in China
More LessA global trend towards increasingly-stringent environmental regulations of sulfur dioxide emissions to improve air quality is faced. China has been adopting progressive policies for improvement of air quality. Recent industry trends focused on producing cleaner air and fuels around the globe, especially in China, have generated significant demand for additional hydro-desulfurization and sulfur recovery capacities in both new and existing refineries and gas plants. Oxygen enrichment technology frequently offers the most economical route to achieve the desired increase in sulfur processing capacity with high recovery efficiency. This commercially proven technology has excellent operating safety records as witnessed by the safe operation of over 300 SRU/TGTU plants in USA, Canada, Europe, Middle East, South Africa and a newly installed facility in Panjin, China. This paper provides a technical background of oxygen enrichment technology, and discusses the various economic, logistical, process and operational advantages that can be realized through its implementation.
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Reserves Reporting Under Modern Fiscal Agreements
Authors E.D. Young and F.M. LasswellIn the exploration, development, and production of oil and gas resources, the ability to report reserves can be an important factor for many companies when considering upstream opportunities to invest and participate in. A common misconception is that when a company reports reserves, the reserves and underlying resources are owned by the company. While this may be true for some forms of concession and lease agreements, resource ownership almost always remains with the host government under modern production sharing (PSC) and risked technical service agreements (TSA). Reserves are primarily reported to comply with host country resource management requirements or the contractor’s home country capital market regulatory rules. The reporting of reserves reporting does not necessarily imply resource ownership. This paper discusses why the reporting of reserves is an important consideration for many companies and focuses on the key principles and agreement elements that enable reserves to be reported under a wide range of agreement types. The paper also discusses how the evolution of fiscal agreements, from early concessions through present-day risked technical service agreements has changed the way reported reserves are determined. In addition, the paper includes a brief discussion of the industry classification systems that are used to characterize reserves and how the investment community utilizes reserves information to assess company performance. The authors hope that the discussion and insights offered by this paper will improve the understanding of the basis for reserve reporting, clarify that reserve reporting does not necessarily imply ownership of the underlying resources and will help enhance the development of mutually beneficial fiscal agreements in the future.
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Utilizing Distributed Temperature Sensor Data in Predicting Flow Rates in Multilateral Wells
Authors J.M. Almulla, C. Yang and D. ZhuThe new advancements in well monitoring tools have increased the amount of data that could be retrieved with great accuracy. The new challenge that we are facing today is to maximize the benefits of the large amount of data provided by these tools. One of these benefits is to utilize the continuous stream of data to determine the flow rate in real time of a multilateral well. Temperature and pressure changes are harder to predict in horizontal laterals compared with vertical wells because of the lack of variation in elevation and geothermal gradient. Thus the need of accurate and high precision gauges becomes critical. A theoretical model is developed to predict temperature and pressure in trilateral wells. The model is used as a forward engine in the study and an inversion procedure is then added to interpret the data to flow profiles. The forward model starts from a specified reservoir with a defined well structure. Pressure, temperature and flow rate in the well system are calculated in the motherbore (main hole) and in the laterals. Then we use the inverse model to interpret the flow rate profiles from the temperature and pressure data measured by the downhole sensors. A gradient-based inversion algorithm is used in this work, which is fast and applicable for real-time monitoring of production performance. In the inverse model, the flow profile is calculated until the one that matches the temperature and pressure in the well is identified. The production distribution from each lateral is determined based on this approach. Examples are presented in the paper. The value of the model approach for production optimization for trilateral wells is illustrated through parametric study.
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Well Architecture: Prediction of the Life Cycle Critical Drawdown Offered by Means of Passive Sand Control
Authors D. Chong and K. Seng ChanMost Geomechanical studies detail the conditions of which a given reservoir will fail given the stress states and rock strength. A full study usually involves rock mechanic tests, verification of in situ stresses, and the calibration of logs to produce a mechanical earth model. The result of these studies is usually the critical drawdown and bottomhole pressures at current and future depleted pressures. There is, however, no published method on how to evaluate the value of sand control in a given field development. This issue can become a hindrance when it comes to finalizing or justifying a particular AFE budget. A method is formulated where the critical bottomhole flowing pressure is determined from a verified sand failure criterion. An abandonment pressure is predetermined, and material balance calculations are done for every fixed pressure drop. The inflow performance relationship is developed from deterministic parameters, and adjusted to well test results. A critical flowing rate is then inferred from the critical flowing bottomhole pressure. Pressure conditions where the sand fails results in a critical flowing rate of zero. The cumulative production and producing duration can then be determined. This method can be programmed in a computer spreadsheet as iterations are required for the numerical determination of critical drawdown and material balance calculations. The dynamic coupling between sand failure prediction, inflow performance, and material balance calculation enables the life cycle evaluation of passive sand control. This paper provides a general guideline of optimizing EUR and the producing duration by minimizing sand production risk through optimized well trajectory, perforation orientation, selective perforation, and sand face completion design.
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Real World Solutions, Effective Fracture Treatment Design in Horizontal Wells
Authors J.M. Sturms, C.H. Smith and L. ZianeHorizontal wells have altered the ability to deliver production from marginal reservoirs. Although reservoirs with permeability values in the 0.1 to 0.01 millidarcy range had been identified in many producing basins, these reservoirs could not be exploited until horizontal drilling became a commercial reality. Drilling these reservoirs became an engineering process that could be applied with great success in many different basins and rock types. The completion of these resources proved to be a different matter, however. Wells that were drilled with excellent vertical control within the reservoir did not exhibit a consistent response to treatment stimulation along the entire traverse of the horizontal sections. However, reservoirs that were considerably different lithologically were always expected to provide a diversity of completion challenges. Pump-in tests were used in many cases in an attempt to understand this lack of consistency. More troubling are the reservoirs that appear to be homogeneous that do not respond well to similar treatment designs along the length of the horizontal section. In some cases, pump-in tests followed by treatment designed from that data failed to yield the expected production results. Sometimes, breakdown could not be achieved in the reservoir. This paper describes how to apply data derived from dipole sonic logs in horizontal sections of a well to establish the anisotropy along the length of the horizontal section. This information is then used to define the brittleness properties of each section of the wellbore. Perforations are selected to take advantage of this brittleness, and effective fracture treatments are designed and pumped. Two reservoirs are examined where this application is used. These case studies occurred in different basins, but both were difficult and troubling reservoirs. The fracture treatment success increased from 50 to 60% to 100%, with reduced breakdown pressures.
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A Dynamic Hybrid Model to Simulate Fractured Reservoirs
Authors W. Shuhong, L. Xiaobo, L. Qiaoyun and W. BaohuaFractured reservoirs simulation has long been challenge to reservoir engineers to handle the complex geometry structure of fractured reservoir and fluid flow processes in it which includes viscous, capillary, gravitational and diffusive effect. In traditional reservoirs simulation, the fractured reservoir is usually divided into matrix and fracture interacting continua such as Dual Porosity model or Dual Permeability model. It is assumed in these models that the fracture system is in a steady state which the width, length, density of the fractures in reservoir does not change during the whole production history, therefore, it is not possible to simulate fractures variation effect with these models. In order to simulate the unsteady state of fracture system, a dynamic hybrid model has been developed in the paper which a dynamic transitivity tensor model is overlapped to Dual Porosity model. It is assumed that the fracture network is the primary continuum for fluid flow, the matrix of low permeability, high storability is considered to be a sink or source to the fracture. The matrix and the fracture communicate through an exchange term which describes the fluid flow between matrix and fracture. The fracture network is considered to be in unsteady state in which fracture has possibility to widen, lengthen, and lose during oil production. A transitivity tensor is introduced to describe these processes, which is a function of pressure, stress, density of fractures. The paper will detail the dynamic hybrid model such as its assumptions, equations, mechanisms and also its applications in the fractured reservoirs simulation. The simulation results show that the dynamic hybrid model has high potential to accurately simulate the dynamic fracture network as well as the fluid flow with the capillary, gravitational and diffusive effects between matrix and fracture.
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Unlock Shale Oil Reserves Using Advanced Fracturing Techniques: A Case Study in China
More LessDevelopment of unconventional resources has become major focus in China in the recent years as the growth of energy demands. Many pilot projects on shale oil reservoirs have been initiated to seek for economic development with modern hydraulic fracturing technologies. Fracturing these reservoirs is quite challenging and requires not only large reservoir contacts but also high fracture conductivity in both primary fracture and fracture networks since oil viscosity is several magnitudes higher than natural gas. Vertical fracture connectivity is also an issue in many cases due to lamination of shale-rich layers with thin siliceous and calcareous beds. This typical sedimentary feature may result in either short fracture height or pinch-point in vertical fracture profile due to proppant embedment in shale-rich layers. The paper presents a shale oil case study in Northern Songliao Basin in China in which many fracturing treatments have been attempted in the past without success. Two existing vertical wells drilled in 1989 were used to study appreciate fracturing techniques and demonstrate the possibility of economic production before evaluating horizontal well completion. The paper illustrates optimization of treatment strategy and design by integrating detailed reservoir characterization, fracture simulation using unconventional fracture model and numerical reservoir simulations. It also introduces an innovative fiber diversion technique for improved vertical fracture coverage and proppant placement together with real time fracture monitoring for treatment optimization. After increased understanding from the treatment on the first well, the treatment on the second well was quite successful and the well produces 30 bopd after the treatment, which is the first ever economic production in the field. The first month production history also matches with the forecast very well, which increases the confidence of extending the practice to the entire field as well as subsequent horizontal well evaluation.
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Oman’s Large Carbonate Field Production Improvement through Integrated Well, Reservoir and Facility Management
Authors S.M. Al-Khadhuri, M.M. Al-Harthi and A. AlkalbaniManaging oil fields in the best way possible has always been in the centre of interests for various oil companies. Production maintenance and optimization, deferment minimization, efficient monitoring of well, reservoir & facility performance, crossfunction collaboration, and many other related issues, all represent the building blocks of a successful and efficient field management structure. This carbonate field of Petroleum Development of Oman is one of the largest fields in the Sultanate of Oman and has been running for more than four decades, and still contributes. Hence, it is becoming more important than ever to ensure that the field is managed both optimally and efficiently to adequately handle the subsurface complexity, the large stock of wells and facility units, and all other related issues, such as operations, services, human resources, etc. An integrated Wells, Reservoir and Facility Management has been implemented to create a more focus and discipline with the aim of achieving an efficiently monitored & controlled asset as well as highly synchronised multi-team actions. The integrated management approach involves structured reservoir and field reviews conducted by integrated multi-disciplinary team, structured processes utilising Smart Field concept and Collaborative Work Environment, enabling technology to obtain data, convert data to useful information and take right decision/action at right time. Exception Based Surveillance is deployed via smart tools to closely monitor and optimise wells and facilities in real time. As a result of the newly introduced management approach, a total of 26 sectors (more than 450 wells) have been collaboratively reviewed, resulting in: Wells book including full details on current status, challenges, potential activities and short term optimisation plan have been updated for all wells. This is considered a major achievement for this cluster of fields, where for the first time 100% wells were being properly reviewed on yearly basis. More than 150 activities have been identified as well optimisation, reinstatement, repair, data gathering and sidetrack. Excellent optimisation gain has been generated and stable production has been achieved. Proper planning of identified activities and faster implementation resulting in better reservoir monitoring, excellent production, significant deferment reduction and lesser restoration time of failed wells and equipment.
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A New Method for OBM Decontamination in Downhole Fluid Analysis
More LessDownhole fluid analysis (DFA) has been used successfully to delineate reservoir vertical and lateral connectivity and properties of the produced fluids. The DFA tools can measure bulk fluid properties such as gas/oil ratio (GOR), light-end compositions (CO2, C1, C2, C3–C5 and C6+), oil-based mud (OBM) filtrate contamination level, color (optical density) that is linearly related to the heavy ends (asphaltenes and/or resins), live fluid density and viscosity, etc. in real time at downhole conditions. Because of overbalance of drilling and formation pressures, and miscibility of OBM filtrate with formation hydrocarbons, the sampled hydrocarbon fluid is usually contaminated by OBM filtrate. This OBM filtrate contamination affects an accurate characterization of the reservoir fluid. On the other hand, DFA flowline temperature is slightly different than formation temperature. DFA flowline pressure, however, may be significantly different from formation pressure because the flowline pressure can be below the formation pressure when the DFA sensor is beside the probe/packer or above the formation pressure when it is on the output side of the pumpout within the Wireline Formation Tester (WFT). Therefore, decontamination of OBM filtrate on fluid properties and conversion of them from flowline to formation conditions are of great importance to interpret DFA measurements. A new reliable method has been developed in real time for characterizing downhole reservoir fluids, decontaminating OBM filtrate on the DFA-measured fluid properties and converting the DFA data from the flowline to formation conditions. The method has been validated against laboratory measurements of different types of reservoir fluids and OBM filtrates with successful results. This methodology establishes a powerful approach for conducting decontamination of OBM filtrate on DFA measurements in real time at downhole conditions.
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The Approach of CT-Dragged Hydrajet Perforating and Annular-Delivery Sand Fracturing Applies in Horizontal Wells
Authors L. Yuxi, Y. Xianggang, Z. Guoliang, Y. Long, L. Chengyu, L. Peng, L. Minghuis, Z. Shanjun, X. Hong, L. Liguo, L. Xianlong, C. Yunping, L. Yuebao, Y. Shifa, M. Jibao, Z. Tingting, L. Wei and W. XinyouMulti stage fracturing of horizontal wells is quickly creating the same ‘step change’ as when vertical wells first went horizontal (Rob Hari, 2010). Following the implementation of multistage fractured horizontal well, the operation scale enhances unceasingly. The new technique need to be complied with some characteristics, such as high fluid delivery capacity, large fluid amount per well and uninterrupted multi-stage execution. But small open area and big friction drag of tubing or CT become the vital constraint in increasing displacement. This paper will show the new approach of CT-dragged hydrajet perforating and annular-delivery sand fracturing applying in horizontal wells, and discuss technical measures for estimating and optimizing some construction parameters in two stages of the approach, finally describe two targeted operations.
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First Installations of the 9-5/8-in. Enhanced Single-Trip Multi-Zone Sand Control Technology in Offshore Brunei
Authors B. Fourie, B. Marpaung, R. Jansen, A. Wong, D. Mok and N. Singh KarlseyBrunei Shell Petroleum (BSP) operates the mature South West Ampa (SWA) and Bugan Fields in Brunei Darussalam. The fields, located 10 to 21 kilometers offshore Brunei in water depths ranging from 10 to 40m, are major sources of oil and gas production. Controlling sand production is a key completion challenge as the reservoirs are composed of multilayer unconsolidated sands, requiring sand control for safe production. Cased-hole, stack-pack systems were considered as the default solution for shallow reservoir zones and wells. Due to the reduced production rates in some reservoirs in the fields and increasing rig costs there is a demand to improve the cased-hole gravel pack efficiency. The wells require zonal isolation and sand-control treatment. Cased-hole stack packs have been a reliable completion method, due to their capabilities for better zonal isolation and multi-zone functionality. Due to the reduced production rates in the mature fields, however, wells were no longer considered economically feasible. Therefore, BSP decided to try a new 9-5/8-in. enhanced single trip multi zone gravel pack system. This system appeared capable of providing significantly greater cost efficiency than conventional cased-hole stack-pack systems, which would make the marginal wells profitable. This paper describes the 3 wells completed by BSP in 2010 and 2011 using the enhanced single trip multi zone gravel pack system. For the 3 wells, a total of 10 zones required a sand control treatment. The paper also will describe why the enhanced single trip multi zone gravel pack system was chosen and will discuss the wellbore configuration, the implementation, and other field possibilities for the system. Finally, the paper will discuss the "best practices" learned from the first enhanced single trip multi zone gravel pack system installations; the challenges encountered during the job execution, and also, will compare the enhanced single trip multi zone gravel pack system with the conventional cased-hole stack-pack system to highlight the advantages of the new system.
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Multistage Temporary Plugging Acid Fracturing Technology Application to Long Well Interval Heterogeneous Carbonate Reservoir
Authors S. Jianming, W. Xinrong, H. Aijun, W. Anpei, Z. Bin and G. Bothe depth of 4775.4 ~6461.3m. In the produced gas, the average content of methane is about 75%, H2S 15% and CO2 10%. The thickness of producing formation is between 176.4m~838.8m, on average, the thickness is 395m. The formation is severely heterogeneous, including type, type and type reservoir which is developed alternately. The proportion of type reservoir is more than 50%, the total ratio of type and type is more than 90%. Gas testing in early exploration phase obtained no commercial gas production in type Ⅱ and type Ⅲ reservoir. Using the cores from Puguang gas field reservoir, fracture flowing capacity experiments have been conducted by using various acid fracturing fluid systems and different technical models. Considering geological characters, completion situation and surface gathering conditions, large-scale temporary plugging multistage injection acid fracturing technology is selected. The plugging ratio of the temperature-controlled temporary plugging agent is more than 90% and the plugging strength is greater than 15MPa. The pump discharge capacity of the new gel acid system is 10 m3/ min. The operating friction is 30% of that of clear water. The viscosity is more than 30mPa·s after being kept for 180min under 130 . 34 wells have been acid fractured by using this technology, and the average open-flow capacity of a single well is 487.8×104m3/d. And after having been producing for one year the average gas production of a single well is 69.3×104m3/ d. Multistage temporary plugging acid fracturing technology application to long well interval heterogeneous carbonate reservoir integrated with acid fracturing technology and optimized design is technical guarantee to develop Puguang Gas Field efficiently and safely, and at the same time it will also be a technology backup to develop some similar gas fields.
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Production Performance Analysis of Hydraulically Fractured Horizontal Wells in Sulige Gas Field
Authors L. Ruilan, H. Yongxin, Y. Shuming, F. Jiwu, X. Wen and Y. KeSulige gas field is the largest tight sand gas field in China. In order to boost gas production of individual wells and to maximize economic return, hydraulically fractured horizontal wells are widely applied in Sulige gas field in recent years. Influenced by special geologic condition and stimulation, the production performance of hydraulically-fractured horizontal wells in tight sand gas reservoir is obviously different from that of conventional gas wells, such as:①The dominant flow regime is linear flow rather than pseudo-radial flow and this flow regime may continue for several years;②The dynamic reserve, drainage area and productivity of producing wells vary with time quickly, especially in the early stage of production. By correctly identifying the percolation characteristics and production performance of hydraulically fractured horizontal wells in tight sand gas reservoir and combine with modern gas production analysis technology, 137 multi-stage fractured horizontal wells in Sulige gas field have been analyzed. Then a prediction chart of estimated reserves and new method of dynamic deliverability evaluation for Sulige multi-stage fractured horizontal wells are established. With these chart and methods, by using early stage production data, the dynamic reserve, drainage area and deliverability of multi-stage fractured horizontal wells can be predicted effectively with elapsed production time. In this paper, ultimate recoverable reserves, drainage sizes, drainage lengths and drainage widths of 57 multi-stage fractured horizontal wells in Sulige gas field are estimated. The results show that, in Sulige gas field, the average ultimately dynamic reserves and drainage sizes of multi-stage fractured horizontal wells are 2.8 to 3.4 times that of offset fractured vertical wells, and the average initial deliverability of multi-stage fractured horizontal wells is 4.0 to 5.0 times that of offset fractured vertical wells. Based on these data, the reasonable well spacing and gas flow rate of Sulige gas field are suggested.
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Understanding Tight Oil Reservoir Hydraulic Fracturing Stimulation Using Two Wells Simultaneous Microseismic Monitoring Approach
More LessThe tight sand oil reservoir found in the Ordos basin is known for its very low porosity and permeability. Almost every well has been stimulated using hydraulic fracturing techniques. The average production for a vertical well is approximately 4–5 tons per day. Among such a large number of fracture jobs, enhanced production after stimulation does not always meet expectations. Since 2005, hydraulic fracturing monitoring services have been carried out widely in this field to improve fracture geometry understanding and optimize well placement. With the implementation on-site, real-time hydraulic fracture monitoring, the pumping procedure can be adjusted accordingly based on the mapped microseismic events. Based on the past hydraulic fracturing monitoring experience in this field, an average microseismic event detectable distance range around 300 m is expected for the case of geophones inside a monitor well. Two parallel horizontal wells were thus drilled at 600m apart. Horizontal section length is around 1,500m for both wells. The original hydraulic fracture plans for each well consisted of 18 stage stimulations, but were subsequently adjusted to 13 stages based on real-time hydraulic fracture monitoring results. Three monitoring wells were drilled from toe to heel as shown in Figure 1. These monitor wellswill also be used as water injection wells in later secondary recovery processes. So hydraulic fractures generated by the pumping from both horizontal wells are not expected to extend far enough to reach the monitor wells. With this favorable well layout, simultaneous dual-well hydraulic fracture monitoring was proposed and conducted. In order to obtain the optimized fracturing parameters first, the initial 3 stages of each treatment well was conducted at one stage per well i.e. stimulate well-1 and then move to frac well-2. Simultaneous hydraulic fracturing began after the initial six stages were completed.
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Case Study: Successful Application of Coiled Tubing Conveyed Inflatable Straddle Packer for Selective Reservoir Treatments in Deviated and Horizontal wells of Rajasthan Field, India
Authors A. Kumar Singh, M. Dutt Kothiyal, P. Kumar, A. Sharma and M. MahajanField X in Rajasthan, India has been developed with 22 Injectors wells & 40 Producers wells. Most of the producers are completed with standalone screens of different types like conventional, ICD’s and SSD types. Almost 60% of the producers are completed with ICD type screens. The open hole for screens section has been drilled with 10.2 ppg SBDIF (Synthetic based drilling fluid) which includes dolomite and barite as weighting agents. After running the screens, the screen section is displaced with 8.4 ppg low weight SBDIF (Synthetic based Drill-In Fluid) which has organophilic clay (Viscosifier) and emulsifier as the key components. Due to some operational delay in bringing the wells online, mud was left inside the screens for a few months. The deposition of mud filter cake and heavier hydrocarbon probably choked the ICD screens ensuing a number of ICD’s non-contributing. Conventional stimulation techniques didn’t help in achieving good results. To effectively remove the suspected damage a coiled tubing based solution was implemented which involved the application of Inflatable Straddle Packer tool. It provides pinpoint accuracy for conventional, horizontal and multilateral stimulation treatments. Coiled Tubing Conveyed Re-Settable selective straddle packer elements allow multiple settings in one trip. Treatment Valve allows precise injection of treatment fluid & adjustable element spacing helps in straddling the long interval. A case history of successful application of CT conveyed inflatable straddle apcker tool in field X in India is presented in this paper which enabled the correct placement of a series of stimulating chemicals targeting different damage mechanisms i.e. wax deposition, mud filter cake, inorganic scaling etc. Post stimulation production logs showed excellent improvement of conformance in zonal contributions. The learning from this stimulation technique was also applied to the horizontal wells in field Y with very encouraging results.
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Polymer Flooding for Middle and Low Permeability Sandstone Reservoirs
Authors Z. Xiaoqin, G. Wenting and P. FengDaqing Oilfield is a heterogeneous sandstone oilfield with multi-layers. Polymer flooding in primary oil layers has obtained significant technological and economic effects. As the recoverable reserves of primary oil layers decline yearly, secondary oil layers have become the focus of industrialized polymer flooding since 2003. Compared with the primary layers in Daqing Oilfield, secondary layers are of thinner thickness, lower permeability, narrowly-developed channel sands and poor continuity of sand bodies. There are four lower aspects and two imbalances in the dynamic performance of polymer flooding in secondary layers. Due to the geological properties and recovery performances of secondary layers, measures are taken to further enhance their recovery factors. Polymer flooding objectives are carefully selected, layers are carefully divided, well spacing between injectors and producers is shortened, and separated-layer polymer injections are widely utilized. In consequence, better development has been obtained.
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Nanostructured Material-Based Completion Tools Enhance Well Productivity
Authors Z. Xu, B.M. Richard and M.D. SolfronkMaking downhole completion tools interventionless is the ultimate level of integrated design of material and product that enhances well performance and saves operation time and cost. Two common approaches to interventionless tools are novel mechanical design and use of new engineered materials. New interventionless tool designs, though effective, are often limited to the small downhole geometry available. Use of high strength, disintegrable materials becomes a more attractive solution for downhole tools which require eventual removal after the tool completes its functions. This paper presents a new, groundbreaking, smart, disintegrable nanostructured composite (DNC) and its successful use for multistage fracturing tools to enhance shale gas/oil well productivity. The disintegrable nanostructured composite (DNC) is manufactured through a powder metallurgy process by consolidating reactive metal powders that were coated with metallic and/or ceramic reinforcements. Material composition and microstructure were engineered at the micro- or nanoscale, to vary material strength and disintegration rate. The DNC is lighter than aluminum and stronger than some mild steels, but disintegrates when it is exposed to the appropriate fluid. More broadly, the DNC has the potential for radically changing the downhole tool functionality landscape by reducing product operational complexity and potentially the wholesale elimination of complete well trips by causing all, or a portion of, a tool to disintegrate in the well.
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Hawiyah Gas Plant New Thermal Oxidizer Combustion Control Philosophy
Authors Y. Almubarak and H.M. AltawilHawiyah Gas Plant at Saudi Aramco recently commissioned a thermal oxidizer. The thermal oxidizer unit has two main functions that shall be achieved. The first function is to oxidize and destroy the Acid gas which has minute quantities of BTX. The BTX shall be fully destroyed at a temperature above 1800 deg F. The second main function of the unit is to provide heating media for the hot water which is used in the re-boiler of the DGA stripper in sweet gas treating unit. The hot water temperature controller has a set point of 350 Deg F thus providing constant water temperatures to the gas treat process. Hawiyah gas plant will share through this paper the internal effort to rectify the original control philosophy design problems submitted by the equipment vendor of the thermal oxidizer that fail to accommodate both functions at the same time. The paper will shed the light on all of the new innovative major advance control loops configured to achieve the appropriate hot water temperature, combustion chamber temperature in addition to the Oxygen trimming advance control. The new control scheme helps the plant to achieve more reliable system to any process changes, it helps to maintain the targeted process parameters set points and optimize the fuel consumption. Hawiyah Gas Plant will present the actual reduced figures in the fuel consumption after the modification and shows the improved in the equipment reliability. In the first part of the paper, brief description of HGP process will be shown. And In this introduction, the role and function of the Gas Treating unit 6 and its thermal oxidizer units will be discussed.
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Three-Dimensional Analysis on Stress Patterns within a Sub-Salt Formation and an Integrated Method for the Design of a Mud-Weight Window
By X. ShenBorehole stability and pore pressure environments downhole transition abruptly, often detrimentally in the presence of salt formations. Geomechanical regimes can vary considerably above, through, and below salts, making accurate modeling of them necessary but challenging. This paper proposes an integrated method that has been developed for predicting the Mud-Weight Window (MWW) of subsalt wells. The high efficiency of the 1D method and high accuracy of the 3D method are deliberately combined in the proposed integrated method, while the disadvantages of those methods are avoided. This objective is achieved by calculating the effective stress ratios, which are part of the input data of the 1D method, with a 3D finite-element (FE) model. The effective stress ratio brings a 3D property into the 1D solution of MWW, thus giving it a 3D property. A 3D model, where the wellbore trajectory was accurately referenced, was built to illustrate and validate the proposed method. A salt body with a thickness of 5.8 km was included. The distribution of the effective stress ratio within the model has been calculated and used in the numerical prediction of the 1D MWW. The prediction of a 3D MWW corresponding to the wellbore trajectory is then derived in the subsalt formation and merged with the numerical prediction.
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Simulation of Three‑Phase Capillary Pressure Curves Directly in 2D Rock Images
Authors Y. Zhou, J.O. Helland and D.G. HatzignatiouPore-scale modeling of three-phase capillary pressure in realistic pore geometries could contribute to an increased knowledge of three-phase displacement mechanisms and also provide support to time-consuming and challenging core-scale laboratory measurements. In this work we have developed a semi-analytical model for computing three-phase capillary pressure curves and the corresponding three-phase fluid configurations in uniformly-wet rock images encountered during tertiary gas invasion. The fluid configurations and favorable entry pressure are determined based on free energy minimization by combining all physically allowed gas-oil, gas-water, and oil-water arc menisci in various ways. The model is shown to reproduce all threephase displacements and capillary entry pressures that previously have been derived in idealized angular tubes for gas invasion at uniform water-wet conditions. These single-pore displacement mechanisms include (i) gas invasion into pores occupied by oil and water leading to simultaneous displacement of the three fluids, (ii) simultaneous invasion of bulk gas and surrounding oil into water filled pores, and finally (iii) the pure two-phase fluid displacements in which gas invades pores occupied by either water or oil. The proposed novel semi-analytical model is validated against existing analytical solutions developed in a star-shape pore space, and subsequently employed on an SEM image of Bentheim sandstone to simulate three-phase fluid configurations and capillary pressure curves at uniform water-wet conditions and different spreading coefficents. The simulated fluid configurations for the different spreading coefficients show similar oil layer behaviour as previously published experimental three-phase fluid configurations obtained by computed microtomography in Bentheim sandstone. The computed saturation paths indicate that three-phase oil-water capillary pressure is a function of the water saturation only, whereas the three-phase gas-oil capillary pressure appears to be a function of two saturations. This is explained by the three-phase displacements occurring in the majority of the simulations, in which gas-water interfaces form immediately during gas invasion into oil- and water-saturated pore shapes.
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Development Strategies of JZ25-1S Thin Oil Rim Reservoirs with Big Gas Cap
More LessJZ25-1S oil field located in Bohai bay which has a thin oil rim with a gas cap on top and aquifer below, and this field has to supply fuel gases to the residents. To achieve maximum oil recovery, force balance between aquifer drive, gas cap expansion, and viscous withdrawal shall be carefully studied for this type of reservoir at various stages of the production life cycle. Available methodologies including analytical, and simulation are used to optimize the development strategies, including well type, the well location, drawdown and so on. Using horizontal wells to develop the thin oil rim, the horizontal length parallels with the GOC and OWC, the horizontal section length is 300-400m nearby, the stand off over the OWC is 1/3 of the oil column if the gas cap index is more than 1.5, and the optimized drawdown of the horizon well is recommended 0.3-0.6MPa ; while the gas cap index is less than 1.5 and the aquifer is stronger, the stand off over the OWC is 1/2 of the oil column, the drawdown is recommended 0.5-0.8MPa; And making good use of the gas and aquifer energy at initial stages of production, then using waterflooding for the reservoir which gas cap index is less than 1.5 and the aquifer is weak. A number of horizontal wells were optimized and drilled in JZ25-1S field after optimizing the development strategies. The initial oil rates are from 943-2830bbl/d under the optimized drawdown. The management of GOC and OWC movement is extremely critical in this kind of oil field. Based on the achieved parameters, these wells display significant higher oil production with delayed water coning and slower gas channeling. Both simulations and production data demonstrate that the JZ25-1S development strategies gain success, using horizontal wells balance GOC and OWC to explore hydrocarbon, and achieve maximum results, which provides the theoretical and production data for development optimization of thin oil rim reservoirs with gas cap in Bohai Bay.
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The Use of “Dope-Free” Tubulars in Petroleum Well Completions
Authors A. Funes, F. Figini, E. De Franceschi, E. Actis Goretta, T. Castiñeiras, X. Wang and M.J. EconomidesAlthough invariably well tubulars have been connected with a thread compound to prevent corrosion and the galling of the metal itself, innovative technologies have allowed the introduction of dope-free connectivity by engineering the connections at the end of pipe sections. Avoiding the use of dope compounds has apparent benefits, one of which is the prevention of formation damage. Another is the efficiency and reliability of the operation itself, removing a cumbersome, albeit routine job, a major advantage in the hectic time of a drilling rig’s operation. During the connection assembly a portion of the thread compound is exuded outside the connection and gets access to the well fluids through the tubing and annular space. Laboratory studies by us with core experiments, presented in this paper, show that the dope forms a suspension which penetrates and damages the formation. The damage is severe (more than 99 percent) and will be present in any well injection service. For production the issue is different and will depend on the reservoir permeability and the ability or lack thereof of the dope compound to penetrate the rock matrix or whether it will form a removable filter cake. The reason that this problem has not gained widespread notice is perhaps because the problem has a narrow application of formation permeability, one that we delineate in this work. Additionally, we present evidence that the dope can be washed off usually by simple flow of reservoir fluids and/or brines or it can be partially dissolved by simple solvent treatments employing toluene or xylene. We present here the clear benefits of using dope-free pipe connections by quantifying the negative effects of the alternative. Production equations using a dope-induced skin effect are presented, showing the detrimental impact on well performance.
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Application of Chemical Tracers for Clean-Up and Production Inflow Monitoring with Onshore Wells in Italy
Authors G. Nutricato, C. Repetto, A. Santi D‘Amico, G. Oftedal, E. Fćvelen, C. Andresen, E. Leung and V. WikmarkChemical tracers have recently been used to identify oil and water production along different intervals in open hole slotted liner completion, compartmentalized with swellable packers. The reservoir is a fractured carbonate brown field containing several sub-areas producing asphaltene and clasts in which chemical inflow tracers have provided greater understanding of characterizing the reservoir and its’ well performance in deviated wells. The permanent downhole tracer systems have been successfully applied in two onshore wells in Italy. The principle of this technology is to place a number of unique chemical tracer systems in different compartments along the length of the lower completion with only minor modifications for clean-up and production monitoring. The system releases tracer into the well stream when wetted by the target fluid, oil or water. When wetted by the opposite phase they will remain dormant, meaning no tracers will be released. The application of permanent oil and water tracer systems placed at pre-defined intervals along the production zones of the wells. Upon well start up, oil samples were taken at the surface and were analyzed to identify which zones were effectively contributing to oil and water production. Permanent water tracer systems were installed aiming at detecting the onset of early water breakthrough. After water break-through has occurred, a regular sampling program is performed and samples analyzed to identify the location of water production to understand the water profile evolution over time. Swellable packers have been used to segment the horizontal sections for the purpose of selective zonal stimulation and to optimize future water shut off intervention by treating the offending zones based on tracer detection. This paper will discuss an innovative wireless approach using chemical inflow tracers as the technology enabler with field proven case studies for clean-up verification, identifying where water and oil is flowing, assess stimulation job effectiveness and estimate relative flow contribution between intervals. Lessons learned for future installations will also be discussed.
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D50 Shift Factor – Shifting the Concept of SBMs Performance Evaluation
Authors Md. Amanullah, T. Allen and M. KilaniDifferent grades of sized bridging materials such as ultra-fine, fine, medium and coarse grades are frequently used in drillin fluid formulations to enhance fluid characteristics, improve mudcake quality and eliminate or reduce formation damage while drilling. Selection of high quality and long lasting SBMs is an essential part of superior drill-in fluid design to achieve these goals. Historically, color, provenience or origin of the SBM samples were evaluated visually or by applying some geological analysis tools such as the petrographic tools to identify and select highly durable and mechanically strong SBM products. These subjective and inappropriate methods of assessment frequently lead to disastrous SBMs performance in down hole conditions. Due to the limitation and ambiguity of the petrographic methods, attempt was made to identify high quality and long lasting SBMs by evaluating acid solubility of SBMs. Though this evaluation criterion is good from acid solubility point of view, it has no relevance to mechanical behavior of SBMs while drilling. Hence, the assessment method also provided misleading information regarding SBMs performance in down hole conditions. Due to the failure of the above approaches, attempt was made to assess SBMs quality using Brinnel Hardness Tester. The outcome of the research was not reliable and inconclusive and thus was not successful in providing a guiding tool for SBMs performance evaluation. This paper describes a fit-for-purpose index parameter defined as the D50 Shift Factor that readily indicates the relative toughness of SBM products and thus provides a powerful guiding tool for high quality SBM product selection for superior drill-in fluid formulations. The index parameter is based on size degradation principle of SBM particles i.e. weak SBMs will cause higher shift of the D50 size compared to tough SBM products. Experimental results demonstrate the usefulness of the D50 Shift Factor in SBM performance evaluation and superior fluid formulations for trouble-free, economic and nondamaging drilling operation.
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Integrated Reservoir Management Utilizing a Portfolio Approach to Beat the Impact of Delayed Water Injection Projects - Opportunistic Strategic Alignment in North Kuwait
Authors H.B. Chetri and Hussain Al-AjmiNorth Kuwait is blessed with multiple reservoirs stacked, Tuba at the shallowest and Ratawi at the deepest level. Water flood expansion was the key ingredient to provide the short term production assurance for the Asset. Field development activities have been progressing for two of the major stacked reservoirs with lion’s share of incremental production (Mauddud & Upper Burgan), assuming that these reservoirs will get the benefit of water injection, to cope up with the enhanced level of production. Unfortunately, the water injection projects have been delayed till the end of 2013, leading to rapid decline in reservoir pressures and erosion in the well performance of the producers (naturally flowing as well as on artificial lift). A comprehensive review of the portfolio of all reservoirs was made vis-à-vis the drilling/ workover activities. Complete history of pressure-production data for last 40 years was analyzed using OFM. The output from the reservoir simulation models was analyzed & discussed with multi-disciplinary teams. Aggressive surveillance & data integration plan was made and implemented to identify the focus areas, from where “new” production can be accelerated and / or controlled, adhering to the best reservoir management practice. Isochronal reservoir pressure maps were updated with full field static bottom hole pressure surveys. Detailed analysis of the RFT/ PLT data was performed to optimize the perforations at layers with high reservoir pressure. New wells from shallower reservoirs were deepened to the reservoirs enjoying the active water drive and accordingly, completed for short term production till the water injection expansion project is commissioned. Integrated reservoir management approach was followed throughout the gamut of field development activities with multi-skill expertize reviewing as peers for smart decisions. The paper’s objective is to share the integrated Reservoir management approach to beat the impact of delayed water injection projects on overall production portfolio, without compromising the technical requirement of voidage replacement ratio for depletion drive reservoirs with best practices approach.
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Platong Gas II Project – World Class Project Execution Through Processes and People
Authors R. Maleevat, S. Sae-Seai and K.S. WernerIn October 2011, Chevron Thailand Exploration and Production Limited (CTEP) reached an important milestone with the commissioning and start up the Platong Gas II Central Process Platform (CPP). The CPP is able to deliver up to 420 MMSCFD of natural gas and 22,000 BPD of condensate with full water injection facilities. This represents a 20% increase in total gas production from CTEP operated assets, as well as a 10 % increase in the overall gas production for the Kingdom of Thailand. Importantly, this was achieved without compromising large base business operations which deliver up to 1600 MMSCFD of natural gas to Thailand. The $3.1 billion project was successfully delivered by the project team after overcoming many challenges which could have adversely impacted both cost and schedule. Significant challenges included: the hi-jacking of structural steel, high casing wear in wells during drilling and development, and a pipeline integrity event. In the face of these challenges, the project went from Final Investment Decision (FID) in March 2008 to full production in October 2011 with “best in class” on safety, project execution and reserve discovery performance. With the largest float over topside ever installed by Chevron (19,200 tons) and the initial 4 remote production platforms with 92 drilled wells, the project team achieved a flawless, world class start up to full production within two weeks. Each of the challenges faced by this project was overcome by delivering high performance through people and processes aligned with the Chevron Way. The execution plan focused on putting the right mix of experienced people together so subject matter experts (both internal and external) from engineering and base business operations could effectively combine and successfully deliver the project. The value placed around collaboration with the asset team and offshore operations team ensured a seamless transition to operations. Standard processes employed included the disciplined application of reservoir management best practices, leading drilling technology, well head platforms and pipelines fabrication and installation, and Chevron’s MCP project management tool kit. Together, people and processes led to a safe and world class project and positioned Platong Gas II as a model of Chevron Project execution via an integrated multifunctional team.
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Remaining Oil Distribution Pattern of Massive Matured Oilfield with Strong Bottom Water: an Integrated Reservoir View
More LessThe highlight of this study is to establish the distribution pattern of remaining oil in massive matured oilfield developed by bottom water under water cut over 90%. The approach combines reservoir engineering and numerical simulation to demonstrate the controlling factor and distribution pattern of remaining oil and complexity water oil movement. The study involves dynamically describing of water oil movement and studying of remaining oil enrichment mechanism and conducting a detailed typical numerical reservoir simulation of H oilfield. The results of the integrated reservoir study show that remaining oil distribution pattern was seven distribution forms (that is flower-like oil, isolated-island oil, ridge oil, attic oil, banded oil, roof oil, sandwich oil) controlled by micro-structure, inter-beds, rhythm, heterogeneity, faults, well pattern and development strategy, and water movement was affected by the transformation of water energy and the formation of water-flooding advantage flow channel, and which was formed for heterogeneity that is production rate heterogeneity, reservoir heterogeneity such as dual porosity and high permeability heterogeneity. Furthermore, the horizontal oil mainly located in flower-like oil which controlled by structure and well pattern, vertical oil mainly located in attic oil controlled by structure, isolated-island oil controlled by local micro-structure, and roof oil controlled by structure and rhythm. The mechanism study also show that inter-bed can affect the distribution of remaining oil when the dimensionless inter-bed radius larger than 0.6 and has little effect on remaining oil when smaller than 0.2, and remaining oil may located on upper zone, lower part and cross inter-bed, and the high oil viscosity also made oil be remained under the inter-bed. The mechanism study show a great agreement with the simulation study of H oilfield, and can support the following development adjustment and EOR study.
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The Application of Multistage Geometric Analysis Method in Natural Fracture Identification
Authors W. Chenggang, X. Anzhu, Z. Lun, W. Qiong and Z. LianboImaging logging can intuitively recognize fractures around borehole walls. However, expensive cost of imaging logging limits its popularization, so little data of imaging logging can be used. How to use conventional logging data is an important item in fracture recognition. Conventional acoustic logging has sensitive response to cavities and fractures. Fractal geometry variable scale analysis (R/S) in combination with acoustic logging data to calculate fractal dimensions of target layers is a new method . Fractal dimension based on R/S analysis can reflect the variability of acoustic logging data, namely reservoir vertical heterogeneity. The stronger vertical heterogeneity is and the better fractures develop, the higher fractal dimension is in fractured low-permeability sandstone reservoirs. So fractal dimension is used to forecast fracture development in oil-bearing formations of Y1, Y2 and Y3 which are low-permeability sandstone reservoirs in X area of Western oilfield in Ordos Basin. Besides a significant discussion about fracture development depend on quantitative analysis of the results from field testing. Dynamic analysis, field outcrops and coring well evaluation show the forecast results have a good agreement with the actual stuation. The research results have certain significant guidance to fracture description. Introduction Development practices of low permeability oilfield in both domestic and overseas show that natural fractures play an important role in the practical development result of low permeability reservoirs[1]. So the research of natural fractures has become one of the key contents of reservoirs evaluation and forecast, and also one of the urgent needs of the oilfield effective development. Now there are lots of methods for fracture recognition and description[2]. But it is often difficult to effectively identify and predict the distribution of fractures because of the restrictions of data types and quantities in a specific oil-bearing block. Conventional logging data are the most among the existing data in X area of Western oilfield. Conventional logging data to establish fracture logging response mechanism models to recognize fracture distribution can be used? Through consulting a large number of literatures, there are examples which use fractal geometry variable scale analysis (R/S) in combination with conventional logging data to recognize fractures relative development at home and abroad [3].So based on the characteristics of low and ultra-low permeability reservoirs of Yanchang Formation in the Ordos Basin, ractal geometry variable scale analysis is used to make a tentative forecast of fractures development of Y1,Y2 and Y3 layers, the main target layers in X area of Western oilfield .Besides fractal dimension to conduct a comprehensive classification evaluation at Y1,Y2 and Y3 layers is also can be used. And the results of evaluation are nearly identical to actual productions which have some vital guidance for effective development of oil -bearings.
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Carbonate Reservoir Interaction with Supercritical Carbon Dioxide
Authors H. El Hajj, U. Odi and A. GuptaIt is well known that with continued production from wet gas reservoirs, the reservoir pressure eventually falls below the dew point pressure leading to condensation and loss of gas productivity in the reservoir. The concept of simultaneously injecting CO2 in a gas reservoir for long term storage while at the same time accelerating production of the gas reservoir is intriguing and promising. CO2 may also interact with carbonate matrix by changing porosity and permeability of the host rock; this is true for reservoirs that are found in the Gulf Region. Core floods experiments with carbon dioxide aging were conducted in a core sample analogue to carbonate at reservoir conditions. CO2 interaction in carbonate formation was evaluated by XRF and SEM analysis; furthermore mineral trapping was also investigated by AFM. The results of the laboratory study showed that the CO2 would dissolve some of the rock at high pressure aging. Dissolved carbonate was found also to be precipitated along the core after decreasing the pressure of the system. The results of this study are directly applicable for evaluating CO2 Huff-n-Puff, a process that can potentially raise the reservoir pressure back above the original dew point. Results of this experiment help answer some critical questions related to introducing CO2 in wet gas reservoirs and its interaction with carbonate reservoirs.
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An Integrated Approach of Fractured Reservoir Modelling Based on Seismic Interpretations and Discrete Fracture Characterisation
More LessAn integrated approach of fractured reservoir modeling is presented. First, the fracture density and azimuth distribution of the entire reservoir is mapped from seismic anisotropy analysis and image log calibrations. Then we apply a dynamic workflow to construct the discrete fracture model by connecting fracture elements laterally and vertically. A tetrahedral grid is then generated for detailed reservoir simulation that fully resolves the discrete fracture characterization. Finally the flow simulation is performed on an actual carbonate reservoir block in the Mideast. This study presents a systematic way of modeling and simulating fractured reservoirs.
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From Molecular Dynamics to Lattice Boltzmann: A New Approach for Pore Scale Modelling of Multi-Phase Flow
More LessAbsolute permeability tensor and relative permeability curves, which are the two most important properties in prediction of subsurface flow dynamics, are both obtained from lab experiments traditionally. Although the measuring approaches have been widely used and results are largely accepted for many years in most cases, the lab experiments are usually expensive, not robust especially for low and ultra-low permeability core measurements, and can not always be repeated for different fluids or under different flow scenarios. Multi-phase modeling based on geometry information of cores obtained by Micro X-ray Computed Tomography becomes an emerging technology that tries to yield rock properties directly. Among all the methods of pore scale modeling, Lattice Boltzmann Method (LBM) shows an apparent advantage in terms of computational efficiency, readiness for parallel computing, and capability of modeling flow with complex boundary conditions. Several multi-phase LB models have been proposed in the last two decades, with successful implementation in the simulation of actual single component two phase (liquid and vapor) flow problems. But for actual solid-fluid systems, most models suffer from the parameters fitting in order to match the experimental results. In this study, we propose to integrate Molecular Dynamics (MD) simulation with Lattice Boltzmann method to solve this problem. The basic idea is to first construct the molecular model based on the actual components of the rock-fluid system. Then MD simulation is performed to compute the interaction force between the rock and the fluid of different densities. MD simulation results indicate that the composition of the forces is a surface force as a nonlinear function of fluid density. This calculated rock-fluid interaction force, combined with the fluid-fluid force determined from the equation of state (EOS), is then used in LBM modeling. Without parameter fitting or assuming the linear relationship between the rock-fluid interaction force and fluid density, this study presents a new systematic approach for pore-scale modeling of multi-phase flow. We have validated this approach by simulating a two-phase separation process and gas-liquid-solid three-phase contact angle. The success of MD-LBM results in agreement with published EOS solution and experimental results demonstrated a breakthrough in pore-scale, multi-phase flow modeling. Based on an actual X-ray CT image of a reservoir core, we applied our workflow to calculate absolute permeability of the core, vapor-liquid H2O relative permeability and capillary pressure curves. With the application of this workflow to a more realistic model considering actual reservoir rock and fluid parameters, the ultimate goal is to develop an accurate method for prediction of permeability tensor, relative permeability and capillary curves based on 3D CT image of the rock, actual fluid and rock components.
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Innovative Single-Phase Tank Technology for In-Situ Sample Validation Enhances Fluid Sampling Integrity
More Lesstesters (WFT) are able to capture and retrieve multiple discreet hydrocarbon fluid samples at in-situ conditions. Expeditious sample validation once the sample bottles are retrieved at the surface is critical because it provides certainty on sample type and quality. The typical process for well-site sample validation can be very expensive and high risk because it requires a full laboratory restoration apparatus, a portable lab, and trained personnel to handle high-pressure sample often under unfavorable conditions. The Advanced Optical Cylinder (AOC) is the latest evolution in single phase sampling technology by Baker Hughes. The AOC sample chamber eliminates the high risk and costs associated with sample quality validation in the field and provide the clients with very valuable and timely data regarding their fluid sample. nitrogenThe AOC design incorporates nitrogen compensation, to retrieve a single phase sample, as well as visible-near infrared (Vis-NIR) technology to obtain spectroscopic measurements of the sample within the tank. The ability to capture a single phase sample is very important because the accuracy of reservoir fluid samples can provide critical parameters needed for optimal completion and production design. Vis-NIR spectroscopy is a well established tool used for downhole fluid analysis that provides critical information such as fluid type, sample purity and PVT properties. With the AOC, it is now possible to verify the consistency of the captured sample of the crude oil or gas obtained during sampling, as soon as the tanks are retrieved at surface without the need for sample transfer. The benefits include avoiding lengthy waiting periods for PVT laboratory analysis, ensuring the quality of retrieved samples, and enhancing critical economic decisions about the reservoir. The Advanced Optical Cylinder (AOC) provides the best method for non-invasive sample validation of the captured formation fluid sample, using a high resolution spectrometer that easily connect to the tank to capture detailed visible and NIR spectra of the pressurized fluid sample. This spectrum can then be compared to the fluid analysis data that was captured while the WFT was sampling, further analysis of the VIS-NIR spectra can determine contamination, GOR, bubble point, and API gravity. Field examples will be used to demonstrate the application and benefits of in-situ sample validation using the AOC.
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Application of a New Method to Estimate Free Fluid Level and Recognition of Compositional Grading Using Wireline Formation Testing Data
Authors S. Khajooie, M. Qassamipour and M. FarhaniDetermination of fluid contacts in a hydrocarbon reservoir is extremely important in calculation of initial hydrocarbon in place and field development planning. The uncertainty in the present fluid type and fluid levels may have a significant impact on the reserves estimation and well completion strategies. Wireline Formation Testing is widely used to discover fluid contacts (or its generic term, Free Fluid Levels). Precise analysis of pressure data obtained from these tests is crucial in defining the type of fluid and fluid contacts. Although the traditional method of P-D Plot to determine a Free Fluid Level (FFL) is easy to implement, however it has the disadvantage of lack of information on uncertainty of the analysis. It is often difficult to identify and remove noisy data which may result in inaccurate estimation of contacts. A method has been mentioned in the literature by which Fluid Level is discovered using formation pressure data that are projected to a datum depth. With this method, it is very simple to find noisy data points which contribute to uncertainty in the FFL estimates. Another benefit of applying such method is to authenticate compositional grading presence in the reservoir. Also it can discriminate layers with different pressure behaviors in a multilayered reservoir. In this paper, several wireline formation testing data such as data from MDT and RFT tools -in different fields in Middle East- have been analyzed by previously mentioned method. A good agreement was observed between the results of this method and other data like petrophysical interpretation, geological evidences, DST results and finally PVT analysis. Also a correlation has been developed to confirm existence of compositional grading and a strategy has been proposed to calculate the rate of density change with depth in those reservoirs where variation of density is not extremely nonlinear.
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