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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
61 - 80 of 581 results
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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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