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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
521 - 540 of 581 results
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Evaluation and Application of Digital Rock Physics (DRP) for Special Core Analysis in Carbonate Formations
Authors Maclean O. Amabeoku, Tariq M. Al-Ghamdi, Yaoming Mu, R. Ingrain and Jonas ToelkeA pilot study to evaluate the quality and validity of special core analysis (SCA) data from Digital Rock Physics (DRP) has provided results that are comparable to laboratory measurements. The DRP technique applied in this study employs the Lattice Boltzmann Method (LBM) for computing relative permeability (Kr(Sw)) and capillary pressure (Pc(Sw)) curves from high resolution digital pore structures obtained from micro-CT image data. The DRP processes, results, and comparisons with laboratory measurements on carbonate rock samples from different Saudi Arabian carbonate reservoirs are presented. DRP conventional core analysis (DRP-CCA) computations include porosity, permeability, formation factor, and dynamic elastic properties. DRP special core analysis (DRP-SCA) computations include Kr(Sw) and Pc(Sw). The translation of DRP-CCA and DRP-SCA determinations from imaged 4 mm subsamples to the 38 mm core plug-scale was achieved by upscaling the data for the various flow units and porosity structures in each plug. The number of flow units within each plug varied between one and four. The process of assembling plug-scale DRP-CCA and DRP-SCA properties is discussed. DRP-SCA results and laboratory measurements from similar rock types in the same wells are comparable and show inherent process and inter-lab uncertainties. The dynamic range of the computed relative permeability curves is superior to the laboratory measurements. The comparisons further showed the benefit of the DRP images and computations in capturing the detailed pore structure and fabric of the rock, especially in the capillary pressure responses. The DRP-SCA computations accentuate spontaneous imbibition and the transition to forced imbibition, a region that traditional laboratory methods may not adequately capture. Computations for different wetting conditions provide relative permeability data that cover all possible rock-fluid wettability states. Similar attempts in traditional laboratory experiments would be long, tedious and expensive. This work shows that DRP can provide satisfactory and complementary data for reservoir studies. The images are readily available and can be used for sensitivity studies. The workflow allows users to conduct their own validation tests, just as we have done, to determine the applicability of the method.
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First Openhole Sidetrack in Deep Horizontal Well Saves Time and Lowers Cost: A Case Study
Recently, the first successful openhole sidetrack without a cement plug in Chong Qing field (central China) was drilled in a 5 7/8-in. horizontal section. Since 2009, approximately 50 horizontal wells using an LWD tool for well placement have been drilled in the field. Most of the wells are deep and geologically challenging, with uncertainty of formation dip and potential faults along the long lateral section. As a result, with only the near-wellbore formation measurements to use during drilling, it has been common to unintentionally drill out of the target zone during the well placement. There have been approximately 10 sidetrack wells in the field. Commonly used techniques for sidetracks in an open hole include time drilling without a cement plug, sidetracking from a cement plug, and sidetracking from a whipstock. In this field, the operator wanted to avoid using whipstocks. Openhole sidetracking without cement plugs using basic time drilling has had a low success rate. Therefore, sidetracking from a cement plug was the operator’s first option. However, the time to set the cement plug in these deep horizontal wells averaged approximately 12 days, including a bottomhole assembly (BHA) trip. It was therefore necessary to re-evaluate openhole sidetracks without a cement plug to save overall time and cost. Two previous failed openhole sidetracks without cement plugs were analyzed. Key lessons were learned and critical factors were identified, which could lead to future success through the application of a more consistent drilling technique. Once the feasibility of the method was established, the technology was successfully implemented to drill a sidetrack without a cement plug. The sidetrack was completed in only 4 days—at least 7 days faster than the openhole sidetracks with a cement plug in this field. This sidetrack represents a step change in efficiency and a reduction is risk during openhole sidetracking in these deep horizontal wells in Chong Qing field. Application of the right techniques will save drilling costs and time, thereby offsetting the geologic challenges in this drilling environment.
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Modeling Seismic Responses in Heterogeneous Gas Reservoirs: A Theoretical Approach of Rock Physics
Authors Ba Jing, Chen Zhiyong, Cao Hong, Yao Fengchang, Xu Guangcheng, Zhang Xinyang, Li Jinsong and Lu MinghuiIn actual gas reservoirs, generally natural gas is heterogeneously distributed in the host matrix of water-saturated rocks, forming countless small "patchy"-like gas packets. This heterogeneity feature (also called the "patchy-saturation") will cause the elastic wave dispersion and attenuation in a seismic exploration band (101~103Hz). The reveal of the relations between seismic responses and reservoir fluid distributions will significantly improve the precision of reservoir characterization and fluid identification in exploration engineering. This paper uses a double-porosity model to describe the gas/water patchysaturated rocks. On the basis of Biot-Rayleigh (B-R) equations, multi-scale rock physics modeling is performed aiming at gas reservoirs. The wave responses in seismic, sonic (103~104Hz) and ultrasonic (>104Hz) bands are predicted and then quantitatively related to the basic properties of lithology and fluids. This approach of modeling is applied in limestone gas reservoirs located on the right bank of Amu Darya river. A multi-scale rock physics template is presented based on the theoretical studies. By combination with the method of the pre-stack inversion of reservoirs' elastic constants, two key parameters of gas saturation and porosity are finally estimated.
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Coalbed Methane Modelling Best Practices
Determining the potential range of recoverable volumes for a Coalbed Methane (CBM) prospect is a necessary precursor to a successful development plan. Several key best practices were incorporated into a workflow to consistently assess the CBM potential of numerous prospective areas. For each area 3D static models were built based on available structural data. The models were geo-statistically populated with coal properties such as density and ash content. Correlations for other properties including gas content, permeability and Langmuir volume were developed. An analysis of the residual distribution between each correlation and its measurements was used to characterise the uncertainty in each. Several methods were considered to reproduce this uncertainty. These ranged from directly applying discrete trends, to geo-statistical property population. The effect of applying each on the predicted EUR was investigated. Reservoir simulation models of production pilots were built and history matched. Given the complexities of the coal reservoir and the non-uniqueness of the history match, further work was carried out to capture the remaining uncertainty and determine its impact on the model predictions. Experimental design (DOE) was used to generate a population of simulation models that sampled the uncertainty range. By using the measured pilot production as a filter, this population was reduced to include only those that matched the observed production. The final step was to optimise the placement of development wells. An algorithm that traded off the gain in gas recovery obtained by a tighter well spacing, against the increased cost associated with the extra wells was devised. The uncertainty in recovery given by this well spacing was tested using the reservoir simulation models. Although static and dynamic modelling of CBM reservoirs is quickly becoming routine in the industry, the best practices developed while building this workflow are novel solutions to several challenges that still confound the CBM modelling community. These best practices are not unique to the study area and could easily be applied to other areas. As such this paper should provide a useful reference to those about to undertake a CBM modelling project.
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Extended Use of S13Cr Materials For Downhole Production Tubing
Authors R. Lee and J.E. Bol Sarawake presence of carbon dioxide and acids. The “self-healing” rate of chromium oxide of stainless steels is dependent upon the environment to which it is exposed, affecting its resistance to SSC. By understanding the overall service conditions and testing the martensitic stainless steels material(s) accordingly, the use of this material has been made possible beyond commonly accepted limits without compromising its overall properties. Specific testing (cyclic slow strain rate tests), more onerous than that recommended by NACE, has been conducted for the qualification of identified martensitic stainless steels. The test regime covered both production and shut-in conditions. The results show that under the particular conditions, S13Cr materials cracking resistance differs from the limitations described by NACE MR0175/ISO 15156. This paper aims to highlight business cases that have led to specific testing of martensitic stainless steel and describes the significant cost savings that have been achieved by using S13Cr materials as production tubing in sour service.
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Application of the Multi-Parameter Geostatistical Inversion in the Carbonate Reservoir Prediction
Authors Liu CaiQin, Wang Zhao Feng, Wei Xiao Dong, Zhang Da Wei, Peng Xian Feng, Chen Xin, Peng Bo and Yang KeFour lithologies were developed in the study area and they were pore-bearing grainstone, compact sparite, shaly limestone and limy mudstone. The pore-bearing grainstone was the main reservoir rock. The characteristic analysis of the electrical and physical properties showed that the acoustic impedance of the pore-bearing grainstone was medium to relatively low. If we only use the inversion data of acoustic impedance, it is difficult to distinguish between the pore-bearing grainstone and other lithologies. In addition, it is difficult to distinguish the reservoir using any single given electrical parameter such as GR, density and resistivity. Therefore, we selected several sensitive logging parameters through crossplot analysis. On the basis of the geostatistical inversion, several volume data were combined, thereby the favorable reservoirs were determined. The multi-parameter geostatistical inversion integrated and constrained by logging data and seismic data. It not only takes the advantage of the geostatistical inversion which does not simply use the acoustic impedance to joins the calculation, but it also uses the curves such as GR, porosity which directly reflect the lithology and physical properties of the formation, to join the calculation. Compared with the conventional acoustic inversion, it greatly improved the vertical resolution, finely characterized the distribution of the reservoirs, and better conquered the problem of the multiplicity of the reservoir prediction and resolution.
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Towards Improved Management, Interpretation and Integration of Dipmeter and Borehole Image Data
Authors Erik-Willem van den Heuvel, Halimah Tengah, Tim Goodall, Dinah Pantic and Adri BalHistorically in our industry, dipmeter and image log data, have generally bypassed the data management processes necessary to safeguard these data for future use. Brunei Shell Petroleum (BSP) is no exception to this, as concluded from a review of these data in 2011. BSP is perhaps one of the few E&P companies that has a significant amount of dipmeter and image data, more than 500 wells, exceeding 7000km, backdating to the early days of dipmeter tools, covering a wide range of historical recording mechanisms, computing platforms and principal databases. The current reality is that both raw and processed data are generally not readily available in a format usable by either petrophysicists or geologists. This is largely due to dipmeter and image tools having suffered a lag-time between tool evolution and effective data storage and archiving systems. As a consequence the potential value of the dipmeter and image logs has remained unrealized. In 2012 BSP embarked on a Borehole Image (BHI) pilot improvement project consisting of some 54 wells, covering a wide range of dipmeter and image tools, with the objective to define data management standards and interpretation workflows aimed at effectively rescuing and ultimately ensuring full integration of this data. Integral to these improvements are recent advances in software capability to handle dipmeter and image log data. Our system and procedures allows for initial data QC and saving a “ready-for-interpretation” data subset available from our corporate data store. Petrophysicists and geologists, who might not have the expertise to QC raw image log curves (maybe up to 30 curves types), now have the confidence to import and use the ready-for-interpretation dataset into Techlog. Legacy image logs are readily available for multi-well studies, reservoir correlation, structural ties to seismic, net-pay calculations over thin bed heterolithic intervals and facies logs for reservoir characterization.
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Development and Application of Pressure Control Drilling System (PCDS) for Drilling Complex Problem
Authors Wei Liu, Lin Shi, Yingcao Zhou, Ying Wang and Hongwei Jiangose fracturing pressure and formation pressure is very near. It is easy to cause drilling complex problems such as well kick and well loss. In order to solve the problems, a pressure control drilling system (PCDS) was developed, including automatic manifold system, back-pump system and auto-control system, which can control the pressure distribution in the entire borehole annular precisely through closedloop automatic control system. The kernel of PCDS is auto-control system which has three significant characteristic, including an advanced real-time hydraulic method, simple and effective control system, self-adaptive control strategies. The auto-control system configuration composes of field-bus device, controller and workstation which form three levels. LevelⅠis measure and on-site diagnosis level. LevelⅡ is monitor and control level. Level Ⅲ is optimized control level. From 2011 to now, the PCDS has successfully finished six field services in China which can provides additional flow-rate and back pressure to compensate for the reduction or increment of bottom hole pressure while making a connection, reduction in rig pump rate, change in mud weight or drill pipe movement and so on. The underbalanced-pressure control technology is also developed which is different from the conventional PCDS technology because the controlled bottom-hole pressure is lower than pore pressure of formation and the gas or fluid can be allowed to come out from formation at a controlled rate which is benefit to protect reservoir and improve ROP. The applications prove that the PCDS equipment can control the bottom-hole pressure in an exact range and the precise pressure control technology of underbalanced drilling is feasible. So the PCDS equipment can easily adapt to do overbalanced, near-balanced and under-balanced drilling operation and will be more successful in the oil or gas well with safety and fast drilling in the future.
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The Utilization of High-Definition Borehole Images to Determine Fracture Properties and Their Relative Age for Fractured Basement Reservoirs
Authors Bingjian Li, Thananapala Singam, Pham Thi Kieu Lan and Thang Tran NamFracture data from borehole images has been a critical portion of well data for the fractured granite basement reservoir characterization for long in Vietnam. However, acquiring good quality electrical borehole images can be often challenging due to extremely high formation resistivity and also abnormal wide range of resistivity spectrum within the basement. A new imaging tool was introduced in the local basement wells recently to provide highdefinition full-coverage electrical borehole images. The enhanced borehole images allowed better interpretation confidence and accuracy for fracture properties for the basement reservoirs. There are a few case studies presented in this paper to illustrate some key improvements and applications of this new image data. First of all, the image quality enhancement from the high-definition tool is shown in comparison with conventional image data acquired from the same basement formation. Secondly, a case example is presented to show that accurate fracture properties derived from the high-definition images can help to better predict permeable zones with validation from dynamic data in the same well. Thirdly, examples on how to interpret relative fracture ages for the various sets of fractures developed in the basement using the new images are also discussed. Such fracture information potentially allows better understanding of the fracture/fault development as well as assisting geoscientists to build proper fracture models in the basement.
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Joint Solution for Improving Subsalt Imaging Using 3D Gravity and Seismic Data
Authors Nu Yudong, Yang Zhanjun, Zhang Jianjun, Yang Boya, Li Yangsheng and Wang JingfuPre-stack depth migration (PSDM) is one of the most important technologies for accurate subsalt structure imaging. However, in the case of huge salt domes and low signal-to-noise ratios (SNR) of subsalt data, the key to accurate imaging of subsalt structure using PSDM is to establish an accurate velocity model. This paper presents a joint solution of 3D gravity and 3D seismic data. The SNR of seismic data above the several huge salt domes in the area is high, while the SNR below the salt domes is relatively low. Since the target is below the salt domes, the PSDM data can’t meet the needs of subsalt structure interpretation. We therefore carried out 3D gravity exploration to solve subsalt structural imaging accuracy problems jointly using 3D gravity data and 3D seismic data. Using the inversion result of 3D gravity formation separation, the cause of clutter in seismic reflections on the interior of salt domes is illustrated and the initial velocity model provided by 3D seismic data is revised in the study area. Through this revised initial velocity model, a new pre-stack depth migrated section with improved subsalt reflection SNR as well as better subsalt structure imaging is achieved. Along with the work flow of joint solution of gravity and seismic data, this paper also gives prerequisites for formation separation technique.
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The New Research of Subsurface System Performance Curves of Sucker Rod Pumping
Authors Ruidong Zhao, Jianjun Zhang, Zhen Tao, Jinxiu Tian, Shicai Huang, Junfeng Shi, Chunming Xiong, Xin Zhang and Yuxia WangSucker rod pumping system is the mechanical oil production method first used, up to now, it is also the most widely applied artificial lift method, however, three performance curves( displacement ~pump differential pressure, displacement ~ horsepower, displacement ~ efficiency) of sucker rod pumping (SRP), which are equivalent to those of electric submersible pump(ESP) and progressive cavity pump(PCP), are not available, increasing the complexity when node analyzing and designing of SRP well. As is known to all, when optimization design of SRP well, trial method is generally used and the operating time is long. Considering the interference of tubing, rod, wellbore fluid and piston pump when working, the subsurface system could be studied as a whole, and the relations between displacement and pump differential pressure, horsepower and pump differential pressure are researched. The dimensionless performance curves of SRP can be obtained based on API RP 11L standard. Three performance curves of subsurface system, namely the relation curves of displacement ~pump differential pressure, displacement ~ horsepower, displacement ~ efficiency, are drawn for the first time. The characteristics of these performance curves are analyzed, showing these curves described in this article can effectively reflect the working characteristics of the subsurface system of SRP. The subsurface performance curves can be a useful tool for sensitivity analysis and optimization design of SRP system. These curves allow developing a general nodal analysis algorithm for any artificial lift pumping method and a more convenient optimization design algorithm for composite pumping system, such as Jet- Rod pumping system.
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A New Theory on Cutter Layout for Improving PDC Bit Performance in Hard and Transit Formation Drilling
Authors Shilin Chen, Rob Arfele, Seth Anderle and Jorge RomeroThis paper presents a theory on layout PDC cutters in force-balanced groups. A group of cutters consists of two or three single-set cutters, which is able to efficiently remove a ring of rock. By carefully selecting the order of layout cutter groups, a new feature of a PDC bit is obtained: any three or four consecutive cutters on a bit profile may form a force-balanced cutter group, which ensures the efficient removal of any ring of rock. The concepts are verified by a core PDC bit and by a fullscale PDC bit in laboratory tests. Two field applications are provided in the paper to further validate the theory.
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Application of Well Spacing Optimization Workflow in Various Shale Gas Resources: Lessons Learned
Authors A. Boulis, R. Jayakumar and R. RaiIn shale plays, as with all reservoirs, it is desirable to achieve the optimal development strategies, particularly well spacing, as early as possible, to minimize loss of capital or reserves. The understanding of parameters influencing well spacing is a vital for the economic development of unconventional reservoirs. Previous papers on this subject have concentrated on unique history match solution, or a parametric study to evaluate optimal well spacing to maximize returns on investment. The optimal well spacing decision is a tradeoff between maximizing the ultimate recovery from an asset and the cost associated for that recovery. Development of shale gas resource will require drilling a large number of wells. Most of the shale gas reservoirs are early in their development cycle with very few wells having long term production data for error free forecasting. Shale gas wells have a long production life but most of the economic value of the well is recovered in the first few years of its life. During the field development it is critical for the operators to obtain a good understanding of the Stimulated Reservoir Volume (SRV) initially, and the contribution of the External Reservoir Volume (XRV) to the SRV in the long run. This paper presents a stochastic forward modeling workflow capturing uncertainties both in the reservoir and completion properties. The workflow was applied to evaluate an optimal number of wells required in a section in various shale gas resources in North America. The forecasted rates for all models are evaluated with an economical model to determine the optimal well placement in the section. Unlike the deterministic approach, advantage of the stochastic approach is in capturing the uncertainty in Net Present Value (NPV) by providing reasonable bounds for NPV that reflects the uncertainties associated with reservoir and completion parameters. Examples of application of this workflow in Marcellus, Woodford, Fayetteville and Haynesville shale gas resources are presented. The workflow discussed in this paper can be used by the operators in unconventional reservoirs to determine optimal well spacing and completion strategies earlier in the lives of these reservoirs, which could accelerate production and improve economic value of shale gas assets.
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Sea Water Injection Mobile System (SWIMS) for Waterflooding Marginal Offshore Oil Reservoirs in The Gulf of Thailand
Authors Tinnaphund Suthipintawong and Mark ZyweckSea Water Injection Mobile System (SWIMS) is a system that is designed to increase recovery efficiency through waterflooding small marginal offshore oil reservoirs in the Gulf of Thailand (GoT). This portable system consists of a submersible pump to lift sea water, chemical injection unit, water holding tank with the ability to treat with oxygen scavenger and biocide and high pressure pump capable of operating at up to 4,500 psi to achieve high rate injection. The system has a relatively small footprint and is designed to be mobile and flexible to service multiple offshore platforms. The main target reservoirs for SWIMS are small, high permeability, homogeneous reservoirs with a favorable mobility ratio, which allows injection at a higher rate than the production off-take. This ability enables the waterflood to be processed very quickly. When the reservoir is fully repressured and the targeted sweep is achieved, SWIMS can be mobilized to another platform.
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Applying Biological Enzyme to Remove Plugging in Screen Pipe Completed Horrizontal Wells in Vocanic Gas Reservior
Authors Yingan Zhang, Hongwei Wang, Guangyu Liu, Zhaopeng Zhu, Yongwei Duan, Qiqiang Pang and Xueping ZhouSince the grade I reservoir in Changshen volcanic gas field has high natural deliverability. Horizontal wells completed with screen pipe were applied to develop this type of reservoir. However, the severe mud pollution during drilling badly damaged the formation, which reduced the well deliverability greatly. In order to remove the mud cake near well bore and restore the reservoir permeability, a new plugging relief technology of biological enzyme was developed. According to the situation of screen completed horizontal wells and the degradation characteristics of the enzyme, laboratory experiments and field applications were conducted. The results show that biological enzyme can remove the reservoir pollution and recover the natural production of screen completed horizontal wells in Jilin volcanic gas field. It provided a new way to develop the grade I reservoir in Changshen volcanic rock gas field.
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Drilling and Completion Technique Selection Methodology for Coalbed Methane Wells
By J. CaballeroGeographically, coal-bed methane exploration or development has occurred on every continent with the exception of Antarctica. Worldwide, many different completion techniques have been utilized to develop coal-bed methane reservoirs. These techniques range from vertical well multi seam completions to multiple lateral wellbores drilled into a single coal seam. Stimulation techniques include open-hole under-ream, cavity creation, and hydraulic fracturing. A number of factors influence the selection of completion techniques including proximity to established oil and gas infrastructure, depth, number and thickness of coal seams, permeability, gas content, composition, and saturation, porosity, etc. The purpose of this paper is to survey the various techniques that have been utilized, to provide the rationale for utilization of each technique, to comment on the commercial success of the various techniques, and to propose a general selection criteria approach that may be useful in the selection of a drilling and completion technique.
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The Development of a Workflow to Improve Predictive Capability of Low Salinity Response
Low Salinity Waterflooding (LSF) is an emerging improved oil recovery (IOR) technology that has been shown to work in a number of cases, while sometimes – unexpectedly – no incremental oil production is observed. Industry has not yet reached consensus on the mechanism behind LSF, which precludes effective screening and prioritization of LSF candidate fields. In this paper a workflow is introduced that improves the way fields are screened for their LSF potential. It employs closely interlinked experiments and modeling work from the molecular scale to the macroscopic Darcy scale, thereby closing gaps that previously impeded the predictability of the low salinity effect. The new workflow is based on the notion that wettability is a surface phenomenon. Elucidation of the low salinity mechanism should thus not be based on bulk measurements, but rather on the characterization of surface compositions and forces. The main insights that follow from this work are: Application of successful LSF leads to a wettability modification towards more water-wet, which is consistently observed at the atomic scale and at the core scale; The surface alterations that occur during LSF correlate with macroscopic observations such as oil recovery from core plugs; The time scales involved in wettability modification towards a more water-wet state can easily be long enough to lead to false negatives in common SCAL experiments; It is demonstrated that double layer expansion (DLE) is likely behind the low salinity mechanism, as processes involving cation exchange are expected to only occur long after breakthrough of the low salinity bank. Even though the workflow has been developed for LSF in sandstones, it is also being employed for LSF in carbonates. The fundamental insight that surface properties dominate the response does not only impact how LSF research and related SCAL experiments are being conducted, but impacts all other EOR processes relying on interfacial phenomena, as well as oil field science in general.
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Novel Applications of Formation Testing to Optimize Field Redevelopment Program and Gas Injection EOR Project in Mature Fields
More LessFormation testing has been utilized widely worldwide as well as in China for field exploration and appraisal, helping reservoir characterization and evaluating hydrocarbon reserve. However, using formation testing technology at development stage in order to improve the reservoir ultimate recovery is not mentioned much in published literatures. In this paper, two case studies were summarized on how formation testing was used at the secondary and tertiary stage of development field in west China including the first domestic gas injection monitoring application. HD Field is one of the oilfields of PetroChina which contributes significant oil production in Tarim basin. With strong aquifer support, one challenge in the adjustment of oilfield development plan is to identify how a potential zone has been water flooded. This case study demonstrates how data acquired from the formation testing helps reservoir engineering study, revises the field development plan and eventually identify the new wells locations with encouraging production result. The second case study demonstrates the first ever application in China of gas injection monitoring in field YH. This field is rich of gas condensate and utilizes gas injection as the main approach to drive the field production and to maintain the reservoir pressure. Because of commingle gas production from multiple zones; it is challenging to understand the sweeping efficiency of injected gas from different formation. With the help of real time downhole fluid composition measurement and innovative new designed probes, formation testing is able to pin point zones that have been swept by injected gas. So the gas injection strategy was adjusted accordingly to improve the overall field recovery.
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Spontaneous Imbibition of Water into Oil Saturated M_1 Bimodal Limestone
Authors E. A. Clerke, J. J. Funk and E. ShtepaniThe M_1 nested bimodal pore system is prevalent in many large limestone oil reservoirs in Saudi Arabia. Within this pore system is contained a large portion of these fields’ oil in place. Very low initial water saturation in these large structural relief carbonate reservoirs results in oil emplaced into pores controlled by M macropore throats and also into pores controlled by much smaller Type 1 micropore throats. Approximately, seventy-five percent of the M_1 oil portion is stored in the macropore system and about 25% is stored in the Type 1 micropore system. This prevalent M_1 petrophysical rock type (PRT) is an example of nested bimodal pore system consisting of an instance from the distribution of Macro possibilities (M porositon) and an instance from the Type 1 micro porositon distribution. The maximum pore-throat diameters of the Type 1 micro porositon are on the average 53 times smaller than the M macro porositon average maximums. M porosity average is 17% with a mean maximum pore-throat diameter of 58 microns. The Type 1 microporosity average is 5.6% with a mean maximum pore-throat diameter of 1.1 microns. Thus, common in Arab-D carbonate reservoir matrix is a bimodal pore network with a very large hydraulic contrast between a fine network of well-sorted tubular Type 1 micropore throats, connected and adjacent to a network of much larger diameter moderately-sorted M macropore throats. In a previous publication by Clerke, it was shown that the very small micropore throats’ contribution to the total permeability is commonly below the resolution and reproducibility of the permeability measuring device when in the presence of many much larger pore throats. The micropore network is permeable if only at a small value. For the two phase flow occurring in a waterflood for oil recovery, the M_1 PRT requires an understanding of the two phase recovery processes in each pore subsystem considering capillarity in the combined pore network. This paper demonstrates that the Type 1 micropores are themselves a permeable network to water and to both oil and water when under waterflood. Hence for our carbonate reservoirs, “pores with throat diameters less than one micron when filled with oil in a bimodal M_1 pore system contribute to oil recovery through a time dependent spontaneous imbibition process and thereby contribute to oil recovery by waterflood.” Further, it is demonstrated that the multimodality porositon classification proposed by Clerke are a form of dynamic rock type that classify the position and the type of internal pore level capillarity spatial gradients that affect ultimate oil recovery. New high-precision laboratory data has been obtained at very low phase pressure: water imbibition into oil saturated M_1 pore systems at near zero phase pressures (spontaneous imbibition) and dispersion of D2O into water filled M_1 pore systems. These pore systems can now be analyzed to obtain the magnitude, direct time dependence and scaling behavior of this important and previously overlooked portion of the total carbonate oil recovery by waterflood.
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Optimal Infill Drilling Using Simulation and Cross-Functional Integration- Ubit Field Example
Authors G. J. Krukrubo, J.E. Nwakwue, O.A. Babafemi, R.H. Young and H.O. OgunnusiThe Ubit Field, located southeast of the Niger Delta, is a Nigerian National Petroleum Corporation (NNPC)/Mobil Producing Nigeria (MPN) Joint Venture (JV) asset that has been on production for more than 40 years (September 1970). Ubit has approximately 2.4GBO OOIP, with production peaking at ~137,000 BOPD in 1997, and is currently at ~85,000 BOPD. With much of the reserves yet to be produced, it is important that an optimized field development plan be implemented to maximize recovery. Guided by reservoir simulation models, a revised Ubit Field re-development plan was approved in December 2009. Infill development has proceeded as designed, and the first infill drilling program is underway. Integration of results from reprocessed seismic, geologic interpretation, core, log and reservoir simulation studies, coupled with state of the art technology in well completions, were critical in developing an optimized depletion plan. Reservoir simulation results consistently indicate higher reserves capture with increased well density from infill drilling that targets unswept locations around and down-dip of abandoned completions. Results from the integrated studies suggest varying the optimum well spacing requirements for the different sections of the reservoir. The recovery factor in the lower quality reservoir section (Disturbed Biafra) could be vastly improved by increasing well density. The multidisciplinary study for field development indicates that approximately 100 additional wells should be drilled to tap unswept resource in the field. This aggressive approach will maximize ultimate recovery, but requires closer well spacing than minimum regulatory specification . The technical basis for this strategy, primarily reservoir simulation models anchored in measured hard-data, is the core focus of this paper.
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