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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
1 - 20 of 581 results
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China's Marine Qiongzhusi Shale Play: First Deep Asia Pacific Region Horizontal Multiple Stage Frac: Case History, Operation & Execution
Authors Z. Lv, L. Wang, S. Deng, K. Kwee Chong, J.S. Wooley, Q. Wang and P. JiDuring the past five years, shale gas developments have changed the game for the US natural gas industry. Globally, shale exploration activities are also increasing. China is in the early stages of exploiting the world’s largest reserves of shale gas resources while attempting to cope with increasing energy demands. This paper presents a case history of applicable technology currently used in North America for initial attempts at shale gas exploration in China. This case study is the first Cambrian age marine shale well in the Qiongzhusi formation located in the shale-gas-rich Sichuan province. Many technologies were brought from North American shale gas applications for this well (Chong et al. 2010). This study describes the technologies used to drill and complete the targeted shale gas formation and guide the completion and stimulation design. The target formation was drilled horizontally and the casing was cemented. The formation was then stimulated with multiple stages after full integration of data from geologic, geomechanical, petrophysical, and core analysis, which aided in the fluid and proppant selection, proppant concentration, and the designed injection rate. A diagnostic fracture injection test (DFIT) was performed before the main treatment to confirm fracture gradient, closure, pore pressure, system permeability, and leakoff. Microseismic mapping was also used, which proved to be valuable when planning and assessing the fracturing results. Currently, the well is flowing gas at rates comparable to early production time in a typical North American shale gas well with a similar type of completion. This case study serves as an example of successful implementation of proven technology outside of the North America shale gas market. Continued projects such as this one are the predecessor to full-scale development of shale gas and have helped shape the abundant gas supply currently in the United States. Additionally, these types of projects are necessary to help China improve their future outlook on gas supply.
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Accelerating Time to Autonomy for Technical Staff- Developing the Industry's Best Performers
Authors M. Schaaf and A. Garg-BuckShell has publicly stated a production target of 4 mboe/day by 2018. This will require the recruitment and development of a large number of technical staff both recent graduates as well as experienced professionals. Shortening time to autonomy and time to integration respectively is critical to success. Structured programs are industry proven vehicles to achieve this and to provide the assurance that staff are truly competent to do what they are required to do. In addition, competence driven development programs offer a clear performance and competence bar. This paper describes Royal Dutch Shell’s approach to developing this critical pipeline of technical professionals by outlining the necessary and sufficient conditions for success of the Shell Graduate Programme, the Advanced Technical Programme and our approach to integrating Experienced Hires. The Shell Graduate Programme is an integrated approach that combines formal learning, with on the job tasks, active involvement of technical coaches and line managers and standardized methods of competence assurance. Not only does this follow the 70/20/10 methodology of learning but also results in the expected “time to autonomy” for graduate joiners being reduced by 1 to 2 yrs as compared to other less comprehensive approaches. In addition to closing critical capability gaps in the business, this is also a clear component of the Employee Value Proposition as Generation Y graduates today look for faster and more structured progression when selecting their employer of choice. The Advanced Technical Programme which is aimed at staff exiting the Shell Graduate Programme as well as experienced hires with only a few years relevant business experience, builds on the Graduate Programme and uses the same structures and principles. It focuses on developing technical professionals to make non standard, original technical decisions autonomously (and similarly follows the principles of blended learning combined with active involvement of Leaders. Finally shortening time to integration for Experienced Hires is critical to enable them to deliver for the business and a clear retention lever. The development of a single, comprehensive onboarding programme maximizes the impact experienced professionals have by accelerating the time to integration into Shell and enabling experienced hires to blend their past experience with the ‘Shell Way’.
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Challenges Evaluating Shale Gas Well Performance: How Do We Account For What We Don’t Know?
Authors A. Boulis, R. Jayakumar, C. Nyaaba, R. Rai and V. SahaiShale gas has emerged as a viable source of clean energy with advances in horizontal drilling and multi-stage fracturing. Well performance in the ultra-low permeability shale gas is governed by the interaction between reservoir rock and the fractures created during hydraulic fracturing. Numerical modeling historically has been used to study impact of variation in reservoir properties and completion characteristics on well performance. Shale gas field development requires a large number of wells to be drilled. The inordinate resource requirement to numerically model each well, necessitates the development of quick diagnostic tools. This paper explores how readily available pressure and rate data can be utilized to estimate and understand the unknowns involved in the completion and the reservoir parameters. Synthetic models have been used to generate well performance history which was then diagnosed using an analytical modeling workflow to generate well performance signatures. The synthetic models provided a controlled basis to study the reservoir and completion phenomena which are difficult to measure in the real field data. In practical application, multiple unknowns can co-exist to impact the overall well performance. Some of the major unknowns that were studied are reservoir permeability, fracture spacing, fracture half-length, fracture and matrix permeability changes with pressure. This paper also captures the performance signature changes with variation in original gas in place (OGIP) and the impact of contribution from stimulated rock volume (SRV) and external rock volume (XRV) outside the SRV. Fracture geometry is rarely known with certainty so this paper also addresses the performance changes that can be observed for various fracture geometry realization while conserving the total fracture area in all the models. The final section of the paper will address understanding the impact on estimated ultimate recovery (EUR) forecast for a particular scenario and how error in estimating the same reduces over time. We believe this fingerprint catalogue will serve as a valuable resource for prompt identification of dominant flow mechanism while providing a diagnostic method for identifying key indicators that control overall well performance.
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Analysis on the Impact of Fracturing Treatment Design and Reservoir Properties on Production from Shale Gas Reservoirs
Authors C.E. Cohen, C. Abad, X. Weng, K. England, A. Phatak, O. Kresse, O. Nevvonen, V. Lafitte and P. AbivinProduction from shale gas reservoirs depends greatly on the efficiency of hydraulic fracturing treatments. The cumulated experience in the industry has led to several best practices in treatment design, which have improved productivity of these reservoirs. However, further advancement of treatment design requires a deeper understanding of the complex physics involved in both hydraulic fracturing and production, such as stress shadow, proppant placement and treatment interaction with pre-existing natural fractures. This paper sheds light on the non-linear physics involved in the production of shale gas reservoirs by improving the understanding of the complex relation between gas production, the reservoir properties, and several treatment design parameters. A fracturing-to-production simulation workflow integrating the Unconventional Fracture Model (Weng et al., 2011), with the Unconventional Production Model (Cohen et al., 2012) is presented. By applying this workflow to a realistic reservoir, we did an extensive parametric study to investigate the relation between production and treatment design parameters such as fracturing fluid viscosity, proppant size, proppant concentration, proppant injection order, treatment volume, pumping rate, pad size and hybrid treatment. The paper also evaluates the influence of unconventional reservoir properties - such as permeability, horizontal stress, horizontal stress anisotropy, horizontal stress orientation, Poisson’s ratio and Young‘s modulus – on production. Since this paper focuses on fluid and proppant selection, our methodology was to run 28 simulations to cover the 2D parametric space of proppant size and fracturing fluid viscosity for all of these parameters. More than fourteen hundred simulations were run in this parametric study and the results provide guidelines for optimized treatment design. This paper illustrates how this unique workflow can identifies the optimum fluid and proppant selection that gives the maximum production for a given reservoir and completion. In addition, the parametric study shows how these optimums evolve as a function of reservoir and treatment parameters. The results validate several best practices in treatment design for shale. For example, combination of different sizes of proppant optimizes production by maximizing initial production and slowing down production decline. Simulations also confirm the best practice of injecting the smallest proppant first. The study explains why slickwater treatments should be injected at maximum pumping rate and preferably with 40/70 mesh sand. It also illustrates why reservoirs with high Young’s modulus (such as the Barnett shale) can be stimulated effectively with slickwater. Another key finding is that the optimum fluid viscosity increases with treatment volume.
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Vital Role of Nanotechnology and Nanomaterials in the Field of Oilfield Chemistry
More LessNanotechnology has the potential to introduce revolutionary change in the energy industries such as exploration, development and production. Nanotechnology can revolutionalise the additive properties by tuning particle characteristics to meet certain environmental, operational and technical requirements. Nanotechnology produces nanomaterials that are ultra fines in nature, usually smaller than ordinary micro particles and thus has very high specific surface area with enormous area of interactions. Recent research has indicated that nanomaterials have unique properties for a broad range of applications in the field of oilfield chemistry, where fluid loss control, borehole stability, cementing quality of a well, remediation of damaged reservoirs, hydrocarbon recovery efficiency, oilfield wastewater treatment are of interest. This paper presents an extensive literature review of assessing the applications of nanotechnology and nanomaterials in the field of oilfield chemistry, investigating the existing problems in the application of nanomaterials in oilfield chemistry, and evaluating the potential technical and economic benefits that nanotechnology and nanomaterials might provide to petroleum development and production.
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Feasibility Study of In Situ Combustion Huff and Puff for EOR in Super Deep Heavy Oil Reservoir
Authors L. Jinzhong, G. Wenlong, W. Bojun, W. Yongbin and H. JihongLKQ oil field is a super-deep heavy oil reservoir with the dead oil viscosity of 9,680~12,000mPa.s at 50, the depth at 2,100 m~3,200 m and the reservoir temperature at 60~95°C. High oil viscosity and low flowability result in low production and rapid decline of primary development. The steam injection, as its low thermal efficiency, is not suitable for the super-deep heavy oil reservoir. In situ combustion is a promising oil recovery process in which thermal energy is generated inside the reservoir. However, the LKQ oil field has a reservoir depth of more than 2000m, no heavy oil field with such a high reservoir depth has applied high pressure in situ combustion all over the world. For the reasons, it is decided to study the feasibility of producing the field by in-situ combustion huff and puff (ISCHF) to enhance oil recovery. In this paper, the mechanism of ISCHF was analyzed firstly, and then a 3-D numerical model was constructed using STARS reservoir simulator to study the operating parameter and the economical efficiency of the ISCHF. As oxygen and natural gas may be produced together which may result in explosion, the security measures were researched by using numerical simulation. According to the simulation results, the fire line can advance symmetrically toward radial direction after the ignition; the oil was displaced to production well by steam, water and flue gas in the back production process; the accumulative air-oil ratios is below 1,000; and the oxygen content in the production gas is blow 3% if a nitrogen slug was injected after air injection stopped. The results can be used to ISCHF design and has great instruction meaning for the super-deep heavy oil reservoir development.
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Drilling Fluids Challenges in Successful Drilling of Gotnia Formation in the State of Kuwait
Authors M.J. Al-Saeedi, D. Al-Enezi and M. SounderrajanDrilling the Gotnia formation in Kuwait has long been a drilling fluids challenge due to its sharp contrast in lithology of salt/anhydrite interfaces. Presence of this salt layer below 13,000 ft. with a thickness of 700-1,200 ft. in deep wells makes this formation more plastic in nature due to high pressure and temperature. There is a fine line between kicks and total loses in this fractured formation. Hole instability, stuck pipe, total loss, well control, acid gases and H2S are frequent problems while drilling this section. High pore pressures exist, requiring mud weights ranging between 18.5-21.5 ppg. With this mud weight range in salt drilling, there are limited options available with the drilling fluid to ensure bore hole stability. Drilling fluids design, loss control and well control are massive tasks. Mud weight management with the knowledge of formation stresses, maintaining lowest possible rheology and managing the salt dissolution to avoid well bore closure/instability are key factors in avoiding complications in these deep wells. OBM is utilized to drill this formation due to the insolubility of salt in oil. Historically, this formation was drilled with lower oil/water ratios resulting in high rheology along with higher mud weights causing frequent mud losses and stuck pipes. Maintaining high oil/water ratio helped to overcome the problems associated with rheology and hydraulics. Salt rapidly reduces electrical stability and oil wettability in OBM. Emulsion stability was increased as a precaution to the extremely fine particles created through salt re-crystallization which has detrimental effect on stability. Fresh water in the water phase helps to minimize salt saturation and crystallization. This paper describes the drilling fluids challenges faced while drilling the Gotnia formation and the progress zade over the years to drill this formation successfully.
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New Mathematical Models for Calculating the Proppant Embedment and Conductivity
More LessProppant embedment plays a significant role in decreasing fracture aperture and conductivity, especially for weakly consolidated sandstones, shale (oil and gas) rock, and coal beds. Empirical and semi-empirical models were usually used to calculate the embedment of proppants. However the accuracy of matching or predicting the proppant embedment using these existing models may not be satisfactory in some cases. On the other hand, it is difficult to determine the coefficients of these models. In this study, analytical models were derived to compute the proppant embedment and fracture conductivity. These new models can be used to calculate the proppant embedment, proppant deformation, the change in fracture aperture and fracture conductivity in the ideal or experimental situations of either single-layer or multi-layer patterns in the fractures under closure pressures. The new models showed that the proppant embedment and fracture conductivity are affected by the factors of closure pressure, fracture aperture, the elastic modulus of proppant and coal bed, the size of proppant, the concentration of proppant-paving, etc. Experimental data of proppant embedment in fractures and fracture conductivity of different proppants at different closure pressures were used to test the models derived in this study. The results from matching the experimental data using the new and the existing models were compared. The results showed that the new models especially the revised new models could match the experimental data in all of the cases studied. The new models for calculating the proppant embedment and fracture conductivity with a better accuracy are of great significance in selecting proppants, which is helpful to achieve high fracture conductivity and then high oil or gas productions of conventional, especially unconventional resources such as shale oil, shale gas, and coal bed methane.
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The Study and Application of High Temperature ‑ Resistant Solid Expandable Tubular Technology
More LessThe introduction of solid expandable tubular has been successful in the oil and gas industry, normally nitrile-butadiene rubber was vulcanized outside the tubular in order to seal off the annulus between the tubular and the wellbore, and the rubber may fail at about 400K temperature, making the tubular incapable while applied in high-temperature wells. To solve this problem, two kinds of materials aimed at replacing the rubber were considered, one is copper which could be welded upon the tubular, and the other is the steel which is the protruding part of the SET body and can be obtained through machining process. Firstly full-scale expansion tests were performed to compare the impact of copper and steel on the expansion force, given the same length and post expansion interference; secondly the experiments aimed at understanding the sealing ability of the two new materials were carried out in the simulative environment of 673K. The results showed that the use of copper and steel witnessed increased expansion pressure about 10% and 20% respectively compared to rubber, when the two materials were put into 673K environment for pressure testing, both copper and steel demonstrated instable results due to the irregular shape of the casing, therefore the right strategy was to set up sealing components at different part of the SET to increase the chance of success. The test results demonstrated that generally 0.5mm post expansion interference was enough for both to function well at 25MPa. The steel was more reliable than the copper since the latter demands additional process to be integrated with the SET and the field application of the casing patching in the high temperature well selected steel as the sealing material, two months after the operation, the steel passed the test of 15MPa without any leak. We expect this research will contribute to improving the high-temperature resistant ability of expandable tubular, and will help form the technical basis for the future application in some extreme conditions.
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Effect of Reservoir Porosity and Clay Content on Hydraulic Fracture Height Containment
More LessThe technique of hydraulic fracturing is an essential way for reservoir stimulation. Prediction of hydraulic fracture geometry has been a difficult challenge in petroleum engineering. A 3D non-linear model is established for simulating hydraulic fracturing processes based on the ABAQUS code. The fluid-solid coupling equations consist of rock stress equilibrium, porous fluid mass conservation, Darcy’s law and effective stress principle. The differential equations are discretized in finite element form and solved. The cohesive elements based on damage mechanics are adopted to model the fracture initiation and propagation. A typical hydraulic fracturing process of a horizontal well in Daqing Oilfield, China is simulated with this model. Variation of proppant concentration during the fracturing procedure is taken into account by the user-subroutine we developed. The bottomhole pressure evolution obtained from the simulation is consistent with the field-measured data. Thus the model is verified. For vertical fracture, the effect of formation porosity and clay content on fracture height containment is investigated and discussed. The rock properties are connected to porosity and clay content by a set of formulae. The results show that larger porosity and clay content could confine the fracture height. As the porosity of the pay layer increases, the permeability increases while the elastic modulus decreases. Since the fracturing fluid leaks off into the reservoir more easily for larger porosity formations, the fracture height decreases and the bottomhole pressure drops. With the increase of the clay content of barrier layers, the elastic modulus decreases and the tensile strength of rock material increases. And the fracture height will decrease as the material is more difficult to be damaged for larger clay content formations. Our work can provide a new understanding of fracture height containment and could benefit the design and practice of hydraulic fracture treatment.
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Foam Assisted Air Injection (FAAI) for IOR at Hailaer Oilfield: Prospects and Challenges
Authors W. Bo-jun, L. Jin-Zhong, J. You-wei, K. Fan-zhong and W. Jia-ChunThe Xi11-72 Block, located in Hailaer Oilfield, Inner Mongolia Autonomous Region, China, contains many ultra-low permeability (<2.0×10-3μm2) oil reservoirs, with natural fractures. The reservoir temperature is 82°C; the original reservoir pressure is approximately 22.5 MPa; and the water-sensitive index of the reservoir is high (>0.7). Primary production and limited water flooding experience at adjacent Blocks have shown that the recovery factor in these reservoirs is very low due to lack of reservoir energy and poor water injectivity. Since 2009, Foam Assisted Air Injection (FAAI) has been proposed, in order to block natural fractures, maintain reservoir pressure and/or increase sweeping and displacement efficiency. A series of laboratory experiments have been conducted to study the oxidation kinetics of air/air foam with oil and the blocking and displacement efficiency of air foams in different oil sands. Reservoir simulation has also been carried out for predicting the reservoir response to foam assisted air injection and optimizing the injection process. Air injection pilot test started in the field since 23 April 2011 in a well group with 1 injector and 6 producers, using a Skid-mounted high pressure air compressor (40 MPa, 7 m3/min air rate). Oxygen breakthrough was observed (oxygen contents 3.7%) on 13 May 2011, and then assisted foam was injected to inhibit air breakthrough. Up to 30 June 2011, five foam slugs had been injected into the reservoir. The field results show that air injection can enhance injection capacity; assisted foam injection can inhibit air breakthrough effectively; and oil production can be significantly increased with water cut reduced by 4%. The detailed laboratory study, field experience and prospects and challenges analysis are presented in this paper.
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Successful Application of Novel Organic‑Solvent‑Mud‑Acid Stimulation Approach for Unlocking Productions and Optimising Field Watercut in the Temana Offshore Brownfield
Authors K.H.T. Wee, M.B. Jadid, G. Bakar, W.A.W. Mohamad and Z.M. MainuriOne of the key successes in optimising a mature offshore oil producing field with water drive mechanism is to actively unlock additional oil production from reservoirs that have not experienced water breakthrough while maintaining gross production from reservoirs that have started producing water. This can be achieved by drilling more infill wells to create additional oil drainage points; however this is a very capital intensive investment. The other approach is to perform stimulation jobs on existing wells (both idle and producing) as part of production enhancement activities to increase well productivities which are comparatively more cost effective. With the increase in well productivities, these wells can be produced at lower drawdown which can delay water breakthrough. This paper describes a holistic approach from understanding well inflow productivity problem due to severe downhole asphaltene or wax deposition issues, formulating the right organic-solvent-mud-acid chemical recipe for the well stimulation jobs, selecting the appropriate well candidates, and optimizing offshore stimulation job execution to ensure good chance of success. The stimulation campaign for 3 wells was carried out between Dec 2009 and Jan 2010 and was proven to be very successful. The cost per job was reduced by 30% compared to previous stimulation job, oil production for all wells increased (including a well which is closed in for 10 years), and up to date, water production has not been observed. Finally, a post job detailed technical analysis was conducted to allow a better understanding on the chemical recipe performances for optimization of future stimulation jobs.
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Effect of Porous Media on Saturation Pressures of Shale Gas and Shale Oil
More LessShale gas and shale oil are the typical ones of unconventional reservoirs in the past decade. Some research studies focused on the effect of porous media on the dew point of gas condensate and bubble point of crude oil systems in terms of experimental and theoretical work. They reached to the contradictory conclusions. Therefore, it is of great importance to develop an effective method to predict the phase behavior of shale gas and shale oil in porous media and investigate the effect of some factors on the saturation pressures of shale gas and shale oil in unconventional reservoirs. In this work, by taking into account the effect of capillarity on saturation pressures of gas condensate and crude oil systems, the theoretical model has been developed to predict the phase behavior of shale gas and shale oil in unconventional reservoirs. The Parachor model is applied to determine the interfacial tension of crude oil and gas condensate. Some case studies were completed to address the effect of porous media on the phase behavior of reservoir fluids. The effect tendency of some properties of porous media on the dew or bubble point of reservoir fluid is discussed in this paper.
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Shallow Gas Overburden Characterization and Full Wavefield Modelling for Gas Clouds Imaging
Authors C.T. Ang, H. Othman, M.H. Zahir, A.G. Adnan and A.R. GhazaliImaging complex subsurface like the gas clouds has always been challenging. Gas clouds are gas accumulation, trapped as an overburden that lowers P-wave velocities (Vp) and frequencies, disrupting transmitted energy and obscures events beneath it. Attenuation of seismic amplitude due to multiple scattering in thin layering of heterogeneous media was first reported by Anstey (1971). A nonlinear full waveform redatuming method proposed by Ghazali (2011) utilized multiple scattering phenomena which described the overburden as complex scattering and translated it to a transmission correction operator. Since it is a nonlinear full waveform inversion (FWI) method, it is important to characterize the rock properties in the gas clouds to identify factors that caused the formation of shallow overburden and help to constraint non-linear inversion results.
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Integration of Basin Modeling, Uncertainty Analysis, Hydrocarbon Charge Volume Assessment in Petroleum Exploration Risk Evaluation
More LessRecent developments in hydrocarbon (HC) exploration have necessitated the strengthening and greater integration of geologic model building. Robust basin modeling requires a two-step procedure consisting of constructing reliable input frameworks that are consistent with available data and geologic interpretations and related geohistory processes and conducting basin simulation tests to explore and determine the confidence level of modeling results. Integrating structural components such as faulting and salt movement is a key element and requires their restoration through time. These restorations impact our understanding of basin development, HC migration patterns, fetch areas, as well as the assessment of potential HC volumes. The granularity or resolution of the stratigraphic input may also alter the modeled migration pattern, including the relative importance of lateral and vertical components and distance. Key modeling input parameters include the source rock distribution through time and space. This input can be developed through the integration of geochemical data with stratigraphy, paleo-bathymetric framework, and other basin specific conditions (e.g., paleolatitude). As a result, a 3-D framework of organic richness and kerogen type can be developed. The restorations and interpretations are imbedded within the basin modeling workflow and iteratively interact with the basin’s burial history modeling. This iterative approach along with the numeric simulator accomplishes the integration and optimization of the input geologic model and directly yields more realistic modeling results consistent with the basin’s specific geology. 2 IPTC 16423 Finally, in order to capture the full range of uncertainty in the petroleum system and to objectively evaluate the hydrocarbon potential and risks in the basin, a suite of simulations need to be performed using a probabilistic approach to determine the confidence level to be placed on the HC volume potential and risks in the analyzed basin.
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Thermally Stable Cutter Technology Advances PDC Performance in Hard and Abrasive Formations, Kuwait
Authors A. Hussein, N.A. Al-Anezi, A.Q. Al-Sarraf, A.K. Dhabria, H.A. Baqer, H. Maliekkal, O. Ghoneim and Y. ZhangEfficiently drilling the 16” hole section in high temperature/high pressure (HTHP) conditions through hard/abrasive Jurassic formations in Kuwait’s oil fields has been a distinctive challenge for more than a decade. The difficult sequence of lithologies starts with abrasive Zubair sand (with pyrite) followed by reactive Ratawi shale and then hard carbonates (UCS 10-30kpsi). The Zubair is approximately 1300ft thick and has historically been drilled with four/six rollercone TCIs or a combination of two TCIs and two PDC bits or two/three PDCs. The objective has been to reduce the total number of bits/trips and ultimately drill the Zubair and as much Ratawi as possible with one PDC bit. Initial attempts with PDC were encouraging, but not economically successful compared to rollercone cost/ft. To improve performance, an FEA-based modeling system was used to predict downhole behavior. Based on these knowledge gains, a new PDC bit design was produced with optimized blade orientation and reconfigured cutting structure. Although the new design did improve performance, the drilling team concluded the PDC shearing elements were unable to withstand the HTHP environment (thermal degradation) and vibration induced impact damage. The operator required new technology to enhance cutter longevity. To deliver a suitable solution, new cutter technology was developed using a two-step manufacturing process high temperature/high pressure pressing technique. Laboratory tests indicated the new style cutter has significantly increased resistance to abrasive wear and thermal fatigue compared to standard cutters without compromising impact resistance. The HTHP cutters were run in a nine-bladed PDC with outstanding results setting a new Kuwaiti single run Zubair footage record (1302ft) and Zubair/Ratawi field footage record (1347ft). The authors will discuss the application challenges and resulting performance improvement. Offset analysis will document a performance step-change that saved the operator an average of 10 days of rig-time ($500,000USD).
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Recent Technology Developments in Chemical Enhanced Oil Recovery
Authors J. Lu, J. Liyanage, S. Solairaj, S. Adkins, G. Pinnawala Arachchilage, D. Hoon Kim, C. Britton, U. Weerasooriya and G.A. PopeSeveral classes of new surfactants have recently been tested for enhanced oil recovery. These new surfactants were needed for oil field applications under reservoir conditions that made it difficult or impossible to find conventional surfactants with the desired behavior such as ultra-low interfacial tension, aqueous stability, thermal stability at high temperature, low retention, tolerance to high salinity and so forth. We illustrate results for several of these new surfactants and discuss under what conditions they are suitable, how we developed formulations using them and some of the general principles that can be applied to future applications. A common theme of this development is the need for surfactants with large hydrophobes (carbon numbers above 18) even for some light oils. A second common theme is the advantages and flexibility of propylene oxide and ethylene oxide linkages between these large hydrophobes and the sulfate or carboxylate end group. A third common theme is the advantages of highly branched hydrophobes regardless of the other characteristics of the surfactant structure help prevent undesirable viscous phases. Finally, a fourth common theme is the advantages of using surfactant mixtures with diverse structures and sizes. These common elements enable us find surfactant formulations that are highly effective and that can be made from available feedstocks at reasonable cost.
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Combustion Front Expanding Characteristic and Risk Analysis of THAI Process
Authors L. Jinzhong, G. Wenlong, W. Yongbin, W. Bojun and H. JihongToe-to-Heel-Air-Injection (THAI™) is an in-situ combustion process that is used for the recovery of bitumen and heavy oil. It combines a horizontal production well with a vertical air injection well placed at the toe. The drainage mechanism of THAI is similar to SAGD of the vertical - horizontal well pattern. However, it is much more difficult to control the THAI process compared with SAGD as gas flow and liquid flow coexist in the horizontal well for THAI. The start-up and the combustion front expanding characteristic of THAI require critical attention, in order to ensure optimal process operation. The temperature profiles and post-mortem pictures of the sandpack during 3-D combustion cell tests performed on Z Block heavy oil are presented in this paper. The processes and the results of 3-D experiments indicate that high temperature ignition, at least 500 is essential for startup of THAI. Then the combustion front is growing in size and expanding downwards, and the high temperature ensures that the utilization factor oxidation is high. After the combustion front propagates beyond the ‘toe’ position, the temperature burning zone, deposition of coke around horizontal well, air injection rate and production rate are key factors for stable propagation of the combustion front. Experimental results also indicate that the combustion front will break through along horizontal wellbore in case of high temperature and high oxygen concentration in the horizontal well because of improper regulation of injection and production. After combustion front breakthrough, a considerable bypassed oil area will be left in the reservoir which results in low recovery efficiency. In the same time, the combustion front breakthrough along horizontal well may also lead to damage of the wellbore by means of high temperature oxidation(combustion) which will result in considerable engineering risk. In order to solve this problem supervision and control measures are researched. It can be helpful for successful planning and implementation of the field pilot testing.
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Mini DST to Characterise Formation Deliverability in Unconventional Reservoirs
Authors B. Kurtoglu, H. Kazemi, E.C. Boratko, J. Tucker and R. DanielsCharacterization of reservoir deliverability is fundamental for the economic development of any field. In the Bakken, a need exists for reliable pressure transient tests to provide effective formation permeability of the combined fracture-matrix porous formation. This effective permeability can then be compared to laboratory measured core permeability of the matrix rock samples. This comparison is the basis for planning early production options and subsequent decisions for EOR alternatives. In the Bakken this understanding is particularly important because of the influence of massive hydraulic fracture stimulation on reservoir performance. Determining well deliverability potential by conventional drill stem tests (DST) or traditional wireline formation tests (WFT) in the past has resulted in mixed success in the Bakken. On the other hand, the mini-DST has definitely increased reliability and the success rate of pressure transient tests. The operation of mini-DST tool requires much less time than the classic DST, and multiple zone tests can be conducted to assess individual zone deliverability. The Mini-DST tool uses the conventional Wireline Formation Tester (WFT) configured with a dual-packer module and downhole pump. Tests are conducted by inflating the dual-packer module to isolate a 3-foot interval of the wellbore. Then, formation fluid is pumped out from the packer-isolated wellbore interval followed by a pressure buildup in the interval. Some simple overlay comparisons, as well as conventional pressure transient analysis, are used to interpret the drawdown and buildup pressure responses. In this paper we present several field tests which were analyzed both by conventional pressure transient analysis and numerical simulation. The analyses have provided insight into a better understanding of the flow mechanism in the Bakken both during primary production and in forecasting various improved and enhanced oil recovery proposals. The experience can also serve as a basis for test design in similar low-permeability reservoirs.
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Innovative Design of the Solid Expandable Tubular to Patch the Casing: Area Below the Previously Installed Expandable Tubular
More LessSolid expandable tubular was widely used for casing patching and proved to be cost effective, however, when the damaged area of the casing is exactly located below the position previously applied by this technology, conventional expandable tubular may not be the choice to do the job since the tubular could not be positioned smoothly due to the loss of the wellbore size caused by the previously installed tubular. The paper discussed an innovative design of the expandable tubular to meet this challenge. Basically the new design involves putting the expansion tool outside the tubular, as a result the expansion ratio could be maximized and the tubular without launcher could pass through smaller wellbore, specifically the outer diameter of the tubular and the maximum diameter of the expansion tool were the same. The tubular could be put upon the inclined plane of expansion tool as it was delivered into the well, the expansion tool was powered by a piston cylinder and an anchor was used to fix the tubular during the expansion. In the field application, the tubular was equipped with two expansion tools at its two ends, the upper end of the tubular was cut thinner in order to secure the expansion of this part firstly and the expanded tubular do not touch the casing after expansion. After passing through the previously patched area, we used the hydraulic power to expand the upper end of the tubular and then raised the whole set of the tubular upward until it was stopped by the lower end of tubular installed last time, the mechanical plus hydraulic force were applied to finish the whole expansion, the field experiment was a success. This innovative design will further enhance the passing ability, expansion ratio and filed efficiency of the expandable tubular; preparing this technology better performance in the mono-diameter well.
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