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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
81 - 100 of 581 results
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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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