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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 - 50 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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Development of New Type Curves for Production Analysis in Naturally Fractured Shale Gas/Tight Gas Reservoirs
Authors B. Xu, X. Li, M. Haghighi, D. Cooke and L. ZhangAs a result of ultra-low rock permeability and hydraulic fracturing, both shale gas and tight gas exhibit long-term transient and linear flow behaviour. Previous studies have introduced type curves for linear flow and assumed that the production is dominant by the stimulated reservoir volume (SRV). The more recent type curves are developed to include the production contribution from un-stimulated region which has been assumed to be a homogeneous system. We know that some tight or shale gas reservoirs are naturally fractured and unstimulated zone is not homogeneous. In current study, we have developed new analytical solutions (type curves) applicable for both natural fractured and hydraulic fractured shale gas/tight gas reservoirs in which both SRV and non SRV regions have double porosity flow behavior. Our developed type curves are more general and applicable for both homogenous and naturally fractured reservoirs. Numerical models were used to validate the analytical solutions and obtained an excellent agreement. We have also developed new type curves for shale gas/tight gas evaluation. The flow regimes are identified to show linear flow and transition flow alternately, and are more complicated than the assumption of homogenous un-stimulated reservoir in late period. The parameters sensitivity of type curves was also investigated and analysed. It is shown that the reservoir size, interporosity coefficient and fracture permeability ratio have great influence on type curves while the effect of storativity ratio is not such significant because fracture porosity is very low compared to matrix porosity. We have compared the new type curves with the curves based on SRV and Brohi’s solutions. It is concluded that double porosity behaviour of un-stimulated region has positive effect on production even if the fracture permeability is in the order of matrix permeability and the matrix bulk shape factor is low.
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Managing Structural Integrity Of Offshore Platforms: Looking Back to Drive the Future
Authors R. Piva, M. Latronico, A. Nero and S. SartiranaThe ability of a structure to perform its required function effectively and efficiently over a defined time period whilst protecting health, safety and environment is one of the major task to take into account especially for the old ageing installations. Considering that actual industry and regulatory authorities require the management of integrity not only at the design stage but during the entire service life, a Structural Integrity Management (SIM) process was developed by eni e&p to monitor offshore fields in the world by means of appropriate programmes of periodic inspections and life-extensions assessments. SIM evolved over the last 25 years according to Company best practices. Considering that the underwater inspection of offshore installations is a complex and expensive activity, a risk-based approach was adopted by eni e&p to monitor platforms conditions as an efficient methodology to obtain cost-efficient and state-of-art inspection plans. The risk-based strategy for the development of inspection scopes of work requires a thorough understanding of susceptibility to damage, tolerance of damage, and actual conditions of a platform. Due to the awareness that in-service inspection campaigns can only assess the local platform degradation due to environment, corrosion and accidental impacts, engineering activities as Ultimate Strength Methods are also performed with the purpose of investigating the global platform behaviour and safety level. This typically involves the use of nonlinear, large deformation analysis to determine the maximum loading that the platform can sustain without collapsing, even in presence of local damages. According to these approaches, at present, about 100 offshore conventional platforms installed in Italy seas are monitored, with 40 of them recertified to extend their operative life over the design life. Eni e&p Integrity Assessment approach was also applied to old steel gravity platforms with in-service life of about 40 years in the offshore Congo.
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Effect of Main Factors on Oil Recovery of Surfactant-Polymer Flooding
More LessAlkali-free surfactant-polymer combination flooding (SP flooding) can avoid side-effects encountered in alkali-surfactantpolymer (ASP) combination flooding, such as scaling and corrosion damaged the lifting system, strong emulsification resulted in produced liquid treatment problems and high cost of water handing. It can reduce the operation cost and be applied in oilfield easily. However, the oil displacement mechanism of SP flooding is not fully understood. In this paper, the main factors on enhancing oil recovery of SP flooding such as viscoelasticity, interfacial tension, emulsification and wettability of rocks surface were studied based on the Berea core oil displacement tests. The results of SP flooding physical simulation tests showed that: (1) High viscoelasticity of SP flooding was an important factor contributing higher oil recovery. When the ratio of viscosity of the displacement fluid to that of oil was more than 2, the higher oil recovery could be obtained by SP flooding. (2) The lower the interfacial tension, the higher the incremental oil recovery. When the interfacial tension of oil and water decreased to 5×10-3mN/m level, almost the highest incremental oil recovery of SP flooding could be obtained. Compared with the SP flooding system of solely high viscosity, more than 7-15% incremental oil recovery could be obtained by that of both lower interfacial tension and high viscosity (3) When emulsification intensity increased, the incremental oil recovery of SP flooding increased accordingly. Compard to the weak emulsification SP system, more than 6-11% incremental oil recovery could be obtained by means of enhancing emulsification ability. (4) Oil recovery of SP flooding at water-wet core condition was higher than that at intermediate-wet or oil-wet one. Studies on main factors for oil displacement efficiency of SP flooding are very important for the formula optimization of SP system, and they will provide foundation for scenario design of field tests and applications of SP flooding.
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Perforating Multiple Sands with Long Interval Separations Pushes the Limit in Completion Efficiency
Authors R. Iyengumwena, F. Otutu, I. Yahaya, E. Ene, W. Yorkor and D. FagbamiThe normal perforation practice in the industry is usually to carry out multiple trips to perforate intervals above 200ft apart either by wireline or by Tubing conveyed Perforation. Such Techniques only adds to increased cost and time to the completion time. This also adds some form of inefficiency of the perforation tunnels due to damage of the near wellbore from completion fluids and pressure surges between the two perforation runs. This paper highlights an approach to deploying a single trip multi-zone TCP system. The strategy is based on a multi firing system that allows for selective loading and firing of guns for several intervals without using the continuous gun spacers. This paper described in detail the innovative technique of perforating multiple intervals in a single run. This technique was recently applied successfully in an oil well in Nigeria. The pay-zones were 700ft apart. The initial consideration was to either use the Wireline conveyed perforation technique or using the Tubing conveyed perforation method in multiple runs. These methods would have been costly and time consuming. The paper focused on three major technical contributions to the oil and gas industry. Firstly, it documents successful application of multiple guns in a single run. Secondly, it describes the design considerations involved as well as the calculation required to safely design the multiple gun run in one trip. Thirdly, it identifies a technique of perforating multiple zones without exposing the earlier perforations to risk of formation damage by shooting the entire interval in one go. This technique ensures the objectives of the perforation were safely met and that no matter how far apart payzones are, a single run is possible. This achievement saved both cost and time for the company and adding more value to completion efficiency. The key areas of concern when designing the perforating technique were being able to correlate the lower zone at depth with the RA marker 800ft above the lower gun assembly and the combined detonation pressures. Both of these factors were carefully handled by strapping all components thoroughly, using known length of drill pipe pup joints and use of time delay multi firing system respectively. Perforation design is now an integral, customized element of Completion planning; it addresses the efficiency and optimization of the Completion process of a well, with a focus on enhancing Positive Net Present Value of Operators’ investment especially at the completion stage, all these done considering the peculiarity of the well. This paper describes a field proven technique deployed to perforate multiple zones in a single trip in hole using drill pipe to space out the different zones. This technique is made possible by utilizing Sequential Multi-Fire system with bottom line of cost savings and efficient operations.
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Derivation of Residual Oil Profile for Enhanced Recovery
Authors D.B. Johare, M.M. Altunbay and R.E. PoitPetrophysical evaluation of a given formation is not complete without looking into all means of exploitation of resident hydrocarbons. With this intent, we studied the hydrocarbon potential of the subject formation via conventional Petrophysics and identified only the possibility of recovering residual-oil (Sro). The remaining question and the objective of this study was the quantification of Sro that can make EOR sweeping of residual-oil economically viable or cost-prohibitive. It is a well-known phenomenon that additional residual oil (Sro) may be present below the conventionally defined oil-water-contacts as a function of geologic and hydrodynamic conditions. In addition, the oil-wet formations force the contact to be below Free-Water-Level leaving a sizable Sro “Stranded Oil” in or below the transition zone. The zone of “Stranded Oil” can be quite thick and economically viable for tertiary EOR techniques if there is a sufficient recoverable volume. To confirm the presence and quantify the saturation of residual oil, we used diffusion-T2intrinsic (DT2) maps from Nuclear Magnetic Resonance NMR log. The DT2 technique was challenged with a possibility of superimposed signals from residual oil and the filtrate from Synthetic-oil-based-mud (SOBM). However, an appreciable viscosity difference between residual formation oil and SOBM-filtrate made it possible to differentiate the NMR signals from SOBM and residual oil based on different diffusion characteristics. We had all possible reasons for having a thick zone of Sro. Either mechanical (tilting of the basin) and/or compartmentalization due to re-formed seals or later movement of water to the lower part of the oil accumulation were present. Hence, looking for a thick zone of Sro that was generated by reasons beyond the capillary behavior was justifiable. However, the quantification and derivation of Sro profile based on clearly identified residual-oil signals revealed a Sroprofile that failed to justify the formation as a future EOR sweep-zone.
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Pre-Heating Circulation Design for Dual Horizontal Well SAGD in the Medium-Deep Extra Heavy Oil Reservoirs
More LessDu 84 block in Liaohe oilfield is an extra heavy oil reservoir, which has a depth of 705 to 708 meters, average pay thickness of 50 to 90 meters, The current oil recovery using Cyclic Steam Stimulation (CSS) has reached 31%. Two SAGD pilots using dual horizontal wells have been constructed to test the follow-up process as the way to further improve the ultimate recovery factor. To establish the uniform heating along the new drilled horizontal wells in the partial depleted reservoir after CSS, the preheating circulation is applied during the initial stage of the pilot test. The challenge is that returning fluids from the circulation is difficult to lift to the surface due to low pressure in the formation (4-5 MPa). The presence of formation dip, which causes a relatively large projected horizontal separation (4-5 m) between the wells, further increases the difficulties for achieving uniform pre-heating. This paper presents the results from numerical simulation and reservoir engineering analysis. The downhole tubing design and operating parameters for pre-heating dual SAGD wells using circulation are determined for achieving uniform communication along the horizontal sections.
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New Findings on Heatloss of Superheated Steam Transmitted Along the Wellbore and Heating Enhancement in Heavy Oil Reservoirs
Authors X. Anzhu, M. Longxin, F. Zifei and Z. LunAt the conclusion of several cycles conventional saturated steam huff and puff in heavy oil reservoirs, the heating radius are typically only 20-30m as it went through successive saturated steam huff and puff. The heating scope can’t be enlarged by continuing saturated steam huff and puff any more. However, superheated steam huff and puff as a additional heavy oil recovery significantly increased heating radius of saturated steam huff and puff. Conventional saturated steam huff and puff theory is not applicable for superheated steam. In this study, superheat steam heat transmission mathematical models was established by three laws such as the law of conservation of mass, the theorem of momentum and the law of conservation of energy, thermodynamics and fluid flow theories. Based on models, the parameters such as temperature, dryness, pressure, degree of superheat, heat loss along the wellbore were calculated. This work analysis the superior properties of superheated steam and bring forward superiority of superheated steam huff and puff to effectively develop heavy oil reservoirs in recovery mechanisms, including simulation studies, and current pilot test effects.
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Assessment of Multistage Stimulation Technologies as Deployed in the Tight Gas Fields of Saudi Arabia
Authors M. Al-Ghazal, S. Al-Driweesh, F. Al-Ghurairi, A. Al-Sagr and M. Al-ZaidThe increasing demand for oil and gas resources to support the worldwide development plans means that the petroleum industry is always actively engaged in exploring new frontiers in drilling and production, including tight multilayered reservoirs. It is becoming evident, more than ever, that producing the most oil and gas out of the drilled reservoirs is an absolute necessity. Accordingly, completion techniques have presented themselves as a crucial well construction parameter and a key to optimally producing wells. Several completion techniques have been exhaustively trial tested in Saudi Aramco to determine the most successful completion mode for each reservoir. Among those various techniques, open hole multistage stimulation has demonstrated superior performance in minimizing skin damage and maximizing reservoir contact through efficient propagation of fracture networks within the rock matrix. Overall, the production results from wells completed using open hole multistage stimulation systems — as deployed in the tight gas fields of Saudi Arabia — have been very positive. Of the approximately 40 wells here this new technology was utilized, the majority of the wells have met or exceeded the pre-stimulation expectations for gas production. Various multistage open hole completion systems were run over these 40 wells and the production results varied. This study highlights these systems and discusses their impact during the fracturing operation and the final stabilized well production. This study will also present some case studies in multistage fracturing operations and investigate the operational impact on productivity enhancement. Following the lessons learned and best practices from these experiences, with correct implementation, the findings from this study should increase the probability of having a more successful multistage stimulation job from a productivity standpoint.
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Net Identification: Techniques to Establish a Reliable Net to Gross Estimate
Authors J. Turner, T. Conroy and B. Van Deijlcommunication and quantification. Petrophysically, net has to be communicated in terms of permeability, the parameter which details a rock’s ability to flow gas. Permeability is the only parameter that comes close to describing the ability to flow gas or contribute energy. The more data available on permeability and net, the better the reservoir understanding will be and the easier it will be to explain reservoir processes. Net reservoir can be assessed by considering results from a number of investigative techniques. Important considerations include; over the life of the field will pressure from low permeable rocks contribute energy to the system, does the special core analysis data from drainage and the imbibition cycles indicate that there is movable fluid down to the permeability cut-off. It is important to quantify the impact of using a different cut-off on NtG. Consider if other traditional net indicators such as volume of shale or porosity either have uncertainty considered too large or are not representative of the permeable reservoir accurately. Net sensitivity can also be investigated by looking at the Equivalent Hydrocarbon Column (the sum of the product of porosity by gas saturation by net reservoir column). Consider the fraction of the reservoir rock that exists between specified permeability cut-offs. Investigate how sensitive the NtG is to the assigned permeability cut-off and assess the volume impact on recovery.
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Laboratory Measurement of Hydraulic Fracture Conductivities in the Barnett Shale
Authors J. Zhang, A. Kamenov, D. Zhu and A.D. HillThe Mississippian Barnett shale of the Fort Worth Basin is one of the most successfully developed shale gas plays in North America by applying multistage hydraulic fracturing stimulation techniques in horizontal wells. The fracturing design involves pumping low viscosity fluid with low proppant concentrations at high pump rate, commonly known as “slick water fracturing”. Direct laboratory measurement of both natural and induced fracture conductivity under realistic experimental conditions with the Barnett shale samples is needed for reliable well performance analysis and fracturing design optimization. During the course of this study a series of static conductivity experiments was completed. The goal was to measure the conductivity of propped and unpropped natural and induced fractures using a modified API conductivity cell at room temperature. The cementing material present on the surface of the natural fractures was preserved during the initial unpropped conductivity tests and removed for subsequent propped fracture conductivity measurements. The induced fractures were artificially created by breaking the shale rock along the bedding plane to account for the effect of the irregular fracture surface on conductivity. Proppants of various sizes were manually placed between rough fracture surfaces at realistic concentrations. The two sides of the induced fractures were cut in a way to represent either an aligned or a displaced fracture face with a 0.1 inch offset. The effect of proppant partial monolayer was also studied by placing proppants at ultra-low concentration. The results from the experiments show that unpropped induced fractures can provide a conductive path after removal of free particles and debris generated when cracking the rock. The aligned induced fractures have conductivities one order of magnitude lower compared to displaced induced fractures when unpropped. Poorly cemented natural fractures are effective flow paths. Unpropped fracture conductivity depends strongly on the degree of shear displacement, the presence of free debris and particles during fracture generation, and the amount of cementing material removed. The propped fracture conductivity is weakly dependent on fracture surface roughness at higher proppant concentrations because the proppant pack is the dominant contributor to fracture conductivity. Moreover, propped fracture conductivity increases with larger proppant size and higher areal concentration in the testing range of this study. Results also show that proppant partial monolayers cannot survive higher closure stress. Therefore, proppant packs with multiple layers of proppant are more beneficial than a partial monolayer by maintaining the conductivity at elevated closure stresses.
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Drillable PDC Casing Bit Defies Challenging Onshore Drilling Environment and Sets Longest Single-Trip, Drilling-with-Casing Record
More LessOrubadi formation in Permit PRL 21 at Western Province Papua New Guinea (PNG) was known for its challenges to drilling and casing-running operations on the surface section. A waterflow event occurred when drilling the offset well through the formation, consequently requiring the flow to be diverted. In addition, the surface casing-running operation was time-consuming due to tight-hole conditions, which led the operator to perform extra trips to ream through the ledges. An approach using the drilling-with-casing technique was presented and identified as the most suitable drilling method for setting the 13 3/8-in. surface casing safely and improving drilling efficiency through trip-time reduction and elimination of conventional drilling BHA handling. A unique, reliable and easily operated top-drive casing-running and drilling system, which had been used regularly for surface casing-running operations, has contributed to the first successful drilling-with-casing operation on the rig. The casing-bit selection has appeared to be an important process in this challenging project. Ultimately, a newly-developed polycrystalline-diamond-compact (PDC) drillable casing bit with PDC cutters was selected based on the estimated hard formation rock strength characteristic of the field, in order to achieve the targeted total depth in a single trip. The drilling-with-casing system was deployed through the problematic zone and mitigated the expected borehole problem with variations in the drilling penetration rate. Recommended drilling parameters were used to achieve optimum performance in combination with sufficient mud properties to maintain good hole cleaning and bit hydraulic performance until total depth. This paper presents the drilling-with-casing project in the field, covering the planning stage, equipment selection, preparation, implementation, and operational aspects of the longest nonretrievable 13 3/8-in. drilling-with-casing project performed in the world to date.
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Soft Computation Application to Optimize Drilling Bit Selection Utilizing Virtual Inteligence and Genetic Algorithms
Authors E. Jamshidi and H. MostafaviDrilling industry encounters various challenges during planning and drilling a new well. There are numerous parameters related to drilling operations that are planned and adjusted as drilling advances. Among them, bit selection is one of the most influential considerations for planning and constructing a new borehole. Conventional bit selections are mostly based on drillers’ experiences in the field or mathematical equations which stand more on recorded performances of similar bits from offset wells. It is evident that these sophisticated interrelations between parameters never can be stated in a single mathematical equation. In such intricate cases, utilizing virtual intelligence and Artificial Neural Networks (ANNs) is proven to be worthwhile in understanding complex relationships between variables. In this paper, two models are developed with high competence and utilizing ANNs. The first model provides appropriate drilling bit selection based on desired ROP to be obtained by applying specific drilling parameters. The second model uses proper drilling parameters obtained from optimizing procedure to select drilling bit which provides maximum achievable ROP. Meanwhile, Genetic Algorithm (GA), as a class of optimizing methods for complex functions, is applied. The proposed methods assess the current conditions of drilling system to optimize the effectiveness of drilling, while reducing the probability of early wear of the drill bit. The correlation coefficients for predicted bit types and optimum drilling parameters in testing the obtained networks are 0.95 and 0.90, respectively. The proposed methodology opens new opportunities for real-time and in-field drilling optimization that can be efficiently implemented within the span of the existing drilling practice.
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Managing Process Safety in Facilities Design
More LessIt takes usually 3 to 4 years on an average to build a complex oil and gas facility from concept to commissioning. All critical features of the facility are decided during the early stages of the project. In fact the concept stage can be called as the stage when the DNA of the facility is cast. During rest of the project all that is being done is to develop and translate this DNA to reality. Very little can be done in later stages to correct safety problems buried in concept itself. Are we paying enough attention to process safety during this stage? Projects are implemented under several constraints and process safety sometimes takes a backseat. While there are several methods of Process Hazard Analysis by which process hazards are checked during design, how far are they effective? As the project accelerates towards completion all focus will be usually on the schedule. Are project teams able to see the compromises made on process safety during the fast track implementation? This paper will review the current practices for ensuring process safety during project implementation. Further it will present case histories of projects where hazards where buried deep inside design in spite of safety reviews that were carried out. The paper will argue the case for deeper understanding of process safety and the need for better management of the same during project implementation. Summary of latest research on the subject from diverse fields of Technical Safety, Behavioral Science and Systems theory will be included in the paper. In conclusion, the paper will provide better ways of understanding the complex issues and demonstrate several important factors that will help in ensuring process safety during project implementation
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Production Integrated Sand Control Benchmark for Field Development
Authors K. Seng Chan, D. Chong, R. Masoudi, M.B. Othman and N. Salbi Bt M. NordinCurrent offshore marginal field development and mature field re-development in Malaysia consistently encountered high development cost and low recovery or incremental recovery. Wells are being drilled and completed at a high cost of 15 to 30 M$ per well while the estimated ultimate recovery (EUR) per well is as low as < 0.4 M Bbl. The associated well development cost (WDC) can be higher than 75 $/Bbl. This high WDC cost can be further aggravated by a significant increase in completion cost if an expensive sand control method is required to mitigate risk of sand production. Rock mechanical properties, stress and pressure distribution can vary widely, from layer to layer, rock facies to facies in the reservoir. Reservoir pore pressure and its distribution could also change drastically during the entire production life cycle. With results of field case studies as examples, this paper is to share our engineering approach in first determining where and when we need sand control based on the geo-mechanical sand-free critical drawdown pressure (CDP) evaluation for the selected well type, configuration and completion. The generated CDP will be later coupled with the current pressure and fluid distribution predicted from the reservoir simulation model and confirmed with the historical pressure and production data for well type, completion and sand control strategy in mature fields. Decision to implement a proper sand control can be made by comparing the CDP with the minimum drawdown pressure (MDP) required to meet the expected production rate target. Sand control method selection shall then be based not only on the sand particle size distribution, well life and the mode of well production (single selective or commingle) but also on maximizing reservoir contact and oil and gas recovery per well. The presented workflows and methodologies is to constitute a new sand control benchmark for well design and production optimization and serve as an engineering guide for optimizing the sand control cost in Malaysia.
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Surmounting The Challenges Leads To Discovery Of New Field In Deep Jurassic Formation: A Case Study
This paper shares and discusses the challenges faced and activities that led to a significant discovery in a deep carbonate reservoir. It covers the successful well-testing design as well as the methods and procedures adopted to complete short term test of this well safely. A new structure in the state of Kuwait was identified for drilling the first exploratory well targeted at deeper Jurassic formations. Adjacent fields to this structure are HPHT naturally fractured reservoirs and fluids are sour in nature. The target well was sidetracked twice with two different kick-off points while drilling the deep formations due to well control problems. Deep formations in combination with HPHT and sour environment created unusual challenges while testing several zones in this well. Based on past experience, a simple test string assembly suitable for HPHT and sour environment was selected for this well. Perforating using deep penetration TCP guns, stimulation with Breakdown acid followed by emulsified acid and testing with Drill Stem Testing (DST) techniques were applied for evaluating the deep formations. During short term testing of second zone, gun hanger has moved upward by about 900 feet and plugged 5” production liner top preventing any flow/access from the zone below. Though this zone produced hydrocarbon, full potential could not be established due to plugging. The last zone was successfully tested and produced significant amount of gas and 44.5o API oil with 1% H2S. Meticulous planning and testing strategies could overcome many challenges to discover commercial quantities of hydrocarbon from new field. This new discovery adds significant hydrocarbon reserves and put a new field on the map of the state of Kuwait. Based on the commercial success in this well, further exploration and development activities are being planned to focus on the same structure.
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A Novel Emulsified Acid System for Stimulation of Very High-Temperature Carbonate Reservoirs
Authors N. Pandya and S. WadekarBecause the world demand for energy is expected to continue growing, exploration is turning to deeper and high-temperature reservoirs. Such reservoirs include fields with high bottomhole static temperatures (BHSTs), such as the Ursa (250°F) and Thunder Horse (280°F) in Gulf of Mexico (GOM). Acid stimulation of such reservoirs at high temperature is a challenging task. Emulsified acid systems are expected to perform better in reservoirs with BHSTs ranging from 275 to 375°F compared to nonretarded acids and gelled acid systems. However, fluid stability and the inhibition of corrosion are major challenges to overcome for successful implementation of this technology. Emulsion instability and the corrosion rate are interrelated, and both increase with higher temperature. Also, fluid stability decreases as a result of corrosion of the metal surfaces. At the same time, an excessive addition of corrosion inhibitor destabilizes the fluid system. Hence, the proper selection and balance between the corrosion inhibitor and emulsifiers are required. Three different types of corrosion inhibitors were evaluated, and an emulsified system was designed with proper optimization of various ingredients, including corrosion in hibitor, an intensifier, and a cationic emulsifier. The system was tested for stability and corrosion loss with static corrosion test using P-110 coupons. After reviewing the literature, it is believed that this emulsified system is the only one to pass static corrosion tests at 275°F for 4 hr and remain stable at 300°F for 2 hr with 28% acid strength. This enables the acid stimulation of carbonate reservoirs having BHSTs up to 300°F while reducing the corrosion rate. As per the study, the effect of the intensifier was different to that found in plain acid, suggesting possible interactions of the additives with the emulsifier. Because fluid stability and the rate of corrosion are interrelated, they should be evaluated together, especially for designing emulsified acid systems for stimulation of very high-temperature carbonate reservoirs.
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Feasibility of Using Laser Bit Beside of Common Bits to Drilling Slim Holes
Authors M. Bazargan, H. Jalalyfar, A. Koohian and M. HabibpourThe capability level of rotary as well as first generation drilling operation could not be matched for deeply drilling programs. To reach that deep, the increasing in drill string length could also cause an additional constraint on hydraulic performance. The operation of slim hole drilling has significant potential to reduce well costs. This cost might be savings are especially important with increased demand for reduced capital finance under current economic conditions in the Iranian oil and gas industry. This savings achievement could be caused by use of smaller drilling rigs, work over rigs, reduced casing size, reducing requirement for drilling consumables and other costs associated with hole size. Otherwise, using laser irradiation for drilling operation can save cost little more higher look like do not using casing and perforation in reservoir layer for slim hole which are drilled by high power laser systems. As the matter of fact, Cost savings achieved from slim hole drilling could be offset by inability to effectively transmit the weight to the bit, increased mechanical failures of drill pipes and tools and reduced the well bore instability effects in particular, in drilling operation at greater depths This paper investigates the effects of borehole parameters during laser drilling operations in the case of slim hole.
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Novel Approach in Sand Production Management - Produce It!
Authors S.E. Lidwin, M. Uyzmanizeil Bin Yaakub and H.E. Bin HarunSpecifically in the upstream sector of oil and gas industry, sand production is a common associated production problem anywhere around the world. Various phases of sand production related businesses have been growing very fast. Various parties such as universities, chemical and equipment manufacturers, service companies and field operators have been working on the sand production issue intensively. While R&D mostly involves academia and chemical and equipment manufacturers, the service companies and field operators would collaborate in field trials and pilot projects. Continuous feedback from the field operators is very important in order to improve the quality and performance of any specific sand control product. Initially a field operator might not be interested in the sand production related issue if there is no such problem in its field. However, once the sand production is detected then all sort of reactions come alive. The sand production if not managed properly will result in significant impact to the well (and field) life, be it reduced productivity, completion premature failure, erosion to the surface equipment and HSE issues including asset integrity and managing environmental impact. All of these effects will somehow or at the end impacting the operator financially, which could have been avoided if the sand issue be taken care of much earlier especially during the field development stage. As seen or heard many times, cost savings were only realized during the development phase of the field but when it came into the production phase, the sand management cost and impact are much greater than the initial cost savings. This is the risk many field operators have been considering nowadays.
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Applications of Downhole In-Situ Reservoir Fluid Properties in Interval Pressure Transient Test
Authors N.R. Hademi, S. Daungkaew, S. Chokthanyawat, W. Kiatpadungkul, C. Platt, T. Limniyakul and N. LastApplications of Downhole InSitu Reservoir Fluid Properties in Interval Pressure Transient Test
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Petrophysical Reservoir Characterisation of a Complex Heavy Oil Carbonate Reservoir in North Oman
Authors N. Al-Balushi, R. Al-Mjeni, D. Said and A. Al-YaarubiPetrophysical Reservoir Characterisation of a Complex Heavy Oil Carbonate Reservoir in North Oman
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Optimization Study of Production‑ Injection Ratio for Steam Flooding
More LessProduction-injection ratio (PIR) is one of the most important factors to affect steam flooding performance. Previous research and field applications of steam flooding have confirmed a common conclusion that the production- injection ratio should not be less 1.2 to achieve higher oil recovery for a conventional heavy oil reservoir. This paper presents the optimization study of production-injection ratio for an unconventional heavy oil reservoir with edge/bottom water. Aimed to Jin 45 Block of Liaohe Oilfield, experimental and numerical simulations are carried out and sensibility analyses are focused on the effect of aquifer size. Compared to the conventional heavy oil reservoir, the results of this study have validated as follows: (1) The optimum production-injection ratio (OPIR) of Jin 45 block steam flooding is significantly dependent on the size of its aquifer. Actually, if only the reservoir pressure is available to steam flooding, the OPIR will reduce with aquifer increasing. (2) With the aquifer increasing, the reservoir pressure before steam flooding will relatively increases, thus steam specific volume decreasing and production-injection balance point removing. (3) The difference of production-injection ratio reflects a balance relationship between production and injection underground. For a heavy oil reservoir with edge water, production-injection balance should be completely maintained to prevent water invading which will seriously lead to bad thermal efficiency of steam flooding. (4) Note that the OPIR should be understood as an average concept. Essentially, the production-injection ratio is differently implemented at different stages of steam flooding. Hence, the interval ratio will be corresponding different. This paper suggests that actual reservoir condition and production performance should be globally taken into account to optimize the production-injection ratio at every stage of steam flooding. It is a considerable strategy to satisfy the management requirement of steam flooding program.
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New Offshore Sidetrack Practices Reduced Significantly Stuck Pipes in KSA
More LessThis paper demonstrates the causes of the major issue of stuck pipes in offshore sidetracks in Saudi Aramco & also explains the new drilling practices implemented to reduce the number of stuck pipes while drilling or running completion systems. Out of three wells sidetracked, two stuck pipes occurred. Year after, this number of stuck pipe has declined significantly after revised and corrected drilling practices. In year 2005, oil demands went up and therefore, Saudi Aramco converted vertical and deviated wells to horizontal in order deliver more oil to the oil market. Sensitive shale instability problem was present almost in every well where drill pipe got stuck. Also, it is worth mentioning that development of humps while drilling contributed to inability of cleaning the hole very efficiently. Typically, every single well is sidetracked and drilled across shale formations of different pressures up to the productive zone. After drilling the horizontal section, the whole well is reamed with stiff assembly during which obstructions and tight spots are cleared. Then, ICD system is deployed to TD. This paper will highlight the main causes of stuck pipe and following that, successful solutions will be presented and explained in detail.
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Well Integrity During Operating the First Offshore Gas Wells in Saudi Arabia; Experiences and Lessons Learned
Authors S.M. Alsyed, E.A. Uzcategui, R. Adesegha and A.S. Al-AhmariAnnulus pressure is an important key to maintaining Well Integrity. During the start-up of Saudi Arabia’s first offshore nonassociated gas field containing high pressure high rate sour gas wells, a continuous increase of some annuli pressures was experienced despite the fact that these annuli were cemented to surface. During any well production, the heat transfer from the produced fluid to the trapped annuli fluids causes annuli pressures to increase to levels that could exceed collapse and/or burst pressure limits of the casings. This is especially true during early startup of the well when all annuli fluids are cold (offshore wells) or at ambient temperature (Onshore wells). To ensure that the pressures does not exceed the maximum allowable limit of well tubular various calculations were performed, taking into account not only the tubular limitations but also the formation pressures these casings encountered, to set the maximum limit. Periodic bleeding of pressures and continuous monitoring was necessary to avoid reaching this maximum set limit for the first four months of production. In this paper performance of the different annuli is analyzed and discussed. Calculation methods are also discussed in details which were employed to determine the maximum allowable pressure limit for each annulus. Elimination of frequent bleeding of 1st casing-casing annulus in one of the wells by revisiting the maximum limit, taking into consideration the formation pressure the casing was set in are some of the lessons learned documented during this first offshore gas field startup and will be put forth in the paper.
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Casing While Drilling (CwD): Surface Hole Optimization in Mature Field of Offshore North West Java
Authors H. Taufiqurrachman and E. TanjungOffshore North West Java (ONWJ) is one of Indonesia's mature fields. Mature field developments in this level require a simple, fast and cheap well design to be economically interesting. The highlight in this paper is drilling top-hole section optimization by applying Casing while Drilling (CwD). The main 2 challenges in drilling top-hole section in ONWJ are gumbo attack and loss circulation. Past mitigation was drilled a small pilot hole to reduce cutting amounts then enlarge the open-hole by hole opener. However it did not solve the problem completely. The gumbo attack still occurred, some associated non-productive rig times still happened and safety concern to clean the plugged flowline still existed. KCl Polymer mud system was not an option due to loss circulation existence, where hole will collapse when seawater is displaced to keep hydrostatic. CwD were executed successfully at 2 exploration wells in Q3 2011 by implementing Vertical-CwD (VCwD). First trial of VCwD was run only in surface section with a simple cutters casing shoe mounted on the end of a casing string. Further improvement in drillshoe, BHA and mud design was made on the second trial to extend the interval and improve overall ROP. The second trial of VCwD managed to safely drilled almost 3000ft of combine surface and intermediate vertical section with overall ROP of 60fph, where at surface section CwD was performed blindly due to total loss circulation and it was successfully cemented (no annulus pressure trap so far). The second trial has saved the company over 1MMUSD compared to conventional drilling. In 2012, numerous trials of Vertical Casing while Drilling (VCwD) have been performed for exploration and development wells in offshore North West Java. CwD is heralding the way to the future of drilling in mature fields of Offshore North West Java.
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Integrating Pressure Transient Analysis and Production Analysis for Dynamic Reserve Evaluation in Tazhong 1 Ordovician Carbonate Gas Field, Tarim basin
Authors S. Hedong, S. Ying, L. Shiyin, K. Bo, L.U. Linlin, S. Zhicheng and L. YanchunTazhong Ⅰgas field is a typical vug-fractured marine carbonate gas condensate reservoir with characteristics of high heterogeneity and complex geological & dynamics, of which grand challenges face the development by using the classic evaluation method of dynamic reserves. On the basis of literature research, a formal definition about dynamic reserves is given. Besides, a workflow of dynamic reserve for carbonate gas condensate reservoirs is built relying on the long-term lowaccuracy data of daily production and short-term high-accuracy data of pressure build-up testing, which integrates full life cycle short-term pressure transient analysis and long-term production analysis combined with the geological understanding. The factors affecting reserve estimate are analyzed based on a field application on TazhongⅠgas field, including initial formation pressure, PVT, the error of pt~pwf conversion, production time, producing water and routine of work. The simulation results show that the gas-liquid two-phase pseudo-pressure method is more appropriate than the pseudo-ingle phase method for calculating dynamic reserves for low gas-oil ratio gas condensate wells. The workflow can improve data utilization ratio, reduce the uncertainty of reserve estimation, avoid the development risk, optimize the development plan, and contribute the enhanced oil recovery in the late stage. It can be also used in other marine carbonate reservoirs. Recently, three thousand large-scale condensate gas fields have been discovered in the Ordovician carbonate reservoir of the Tazhong area, which is located in the middle part of the central uplift belt in the Tarim Basin〔1-2〕. However, the traditional material balance method for doing what is not applicable in this area due to many factors. First, the type of reservoirs is various, including cavity, fracture-vug, cleavage and matrix pore (dominant). Second, the flow mechanism is complicated, including seepage and conduit flow. Besides, fluid property is complex in nature, leading to low-, middle-, highcondensate and volatile gas reservoirs. Third, controllability is low during the development, the production model involves non-constant pressure and non-constant rate. Fourth, it is difficult to calculate the bottomhole flowing pressure due to the small difference between the formation pressure and the dew point pressure, there is the retrograde condensation phenomenon in formations, and multi-phase flows happen in the wellbore. Fifth, there are fewhydrostatic gradient data, and they do not decrease monotonically. Therefore, a great challenge facing developers is how to evaluate the dynamic production of complex carbonate gas condensate wells under the complex production status.
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Improving Safety & Reliability through Process Safety Management in Gas Handling facilities
Authors A. Eid Al-Adwani and V. Madhusudana Rao KapavarapuDuring the whole Facility Life Cycle of a Gas handling plant, Risk Management for protection of environment and communities and prevention of major hazards along with Asset Management are the key drivers for making the facility compliant with Health & Safety Regulations and Environmental issues and at the same time profitable economic and able to preserve asset value by improving the level of operational and process safety has become a crucial and challenging issue in a HSE perspective in Gas handling facilities. Process safety can be placed at the intersection of these independent but interrelated aspects and can be regarded as the key element for performing an integrated and comprehensive analysis capable to maximize plant effectiveness ensuring the best safety level, minimizing risks to safety and security and limiting at the same time downtime due to operational disruption or interruption, thus achieving consistency throughout the whole project life cycle. Therefore an effective process safety management demands a holistic and systematic approach for improving operational and process safety throughout the whole project life cycle from design and construction, through operation and maintenance, to decommissioning. In light of the above considerations a tool for process safety management has been elaborated and is hereafter described as a new structured approach of BAD ACTOR Identification in the facilities and its mitigation methods. Process Improvement approach was adopted in Kuwait Oil Company in Gas Management group and Gas Operations team and the similar culture was inculcated in to the operation employees to report all process incidents and BAD ACTORS. These BAD ACTOR events will be analyzed based on risk prioritization by conducting structure Risk analysis and Root cause analysis of various methods and recommendations will be implemented to avoid similar incidents to improve the reliability of the plant operations.
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Collapse Strength Study for the Solid Expandable Tubular
More LessThe paper summarized an experimental and theoretical study of the collapse resistant ability of solid expandable tubular (SET)after expansion, and the formula used to calculate the collapse strength of casing was modified to make it adaptable to the expandable tubular. One key limiting factor of the expandable tubular in its application in the open hole well to replace the casing is its postexpanded mechanical properties. The collapse strength of the expandable tubular after expansion was significantly compromised as the result of the comprehensive influence by the change of factors like the ovality, eccentricity and residual stress. In view of these problems, firstly full-scale expansion experiments were performed to examine all the impact of those factors; secondly the formula was modified based on the experimental data; thirdly the collapse experiments were carried out to test the strength of post-expanded tubulars as well as the accuracy of the modified formula. The results demonstrated that after large-scale plastic deformation, the dimension of the tubular changed dramatically as represented by the increase of eccentricity and ovality, the residual stress also appeared on both inside and outside surface of the tubular, the starting point of the collapse occurred at the position with the least wall thickness. The calculation results which reflected the average collapse strength of the tubular were larger than the actual experimental outcome but the error was kept well within 15%. We expect the research will contribute to the better understanding of the collapse resistant ability of post-expanded tubular and form the necessary technical basis for it future broad use.
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Nano-Ceramic Coatings- A Means of Enhancing Bit Life and Reducing Drill String Trips
Authors S. Sengupta and A. KumarDrilling bit is the main tool which performs the task of grinding and cutting through the formation. This causes cracking, spallation and delamination of the drilling bit and it needs to be replaced periodically depending upon the formation conditions. This replacement of the bit requires tripping the drill string and running it in again which causes loss of time. Also, a new bit has to be installed which causes monetary loss. Coating the bit with Nano-Ceramic coatings can help reduce the wear and tear significantly. Another promising fact is that these coatings don’t allow the metal substrate below to be affected. So, the worn out bit can be recoated with a fresh layer of Nano-Ceramic coatings and be reused. This paper shall go through the Nano-Ceramic crystalline structure, coating processes, testing mechanical properties (Young’s Modulus, Bond strength, Tensile strength) of the coatings and the comparison of mechanical properties of conventional and Nanostructured coatings. An application of this technology will be to use it for bits to drill highly abrasive formations like those formed by igneous rocks. The Nano-Ceramic coatings are made from an Al2O3-TiO2 Nano-Ceramic powder. This is applied on the bit surface via plasma coating method. The powder is partially melted to form grains of varying sizes. This lack of homogeneity is a major factor in enhancement of mechanical properties which will be explained further in the paper. There is a marked reduction in propagation of cracks as seen under SEM photographs. There is doubling of Bond strength as compared to conventional coatings.The toughness is about 2-4 times that of a conventional coating. This shall be further illustrated in the paper with help of graphs and images. This technology could lead to huge savings for operators as tripping frequency would be reduced. The replaceability of the bit also ensures savings for the operating company.
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Fracture Finite Difference Seismic Modelling
Authors M. Ferla and C. D‘AgostoThe objective of this study is to measure the seismic response of fluid filled fractures, trying to evaluate which acquisition survey parameters can better highlight this feature. The scope of fracture modelling is simulating the presence of a fracture system in the area of interest verifyin if it is detectable and describable by a 3D P-wave or PS-wave seismic data, for issues related to operative aspects but also for future support to the drilling activity. A system of aligned fractures can be described as an effective anisotropic medium when the dominant wavelength is long compared to the fracture scales. In order to model the behavior of seismic waves in fractured media, we can characterize the model with normal and tangential crack compliances, Coates and Schoenberg (1995). The main measurable effects on seismic data are the shear wave splitting and p-wave AVOaz anomalies. Shear-wave splitting due to the alignment of vertical cracks can be recognized by the polarization of the fast split shear-wave, which is usually parallel to the local strike of cracks and can be used to characterize fracture orientation. The time delay between fast and slow shear-waves is closely related to the intensity of crack-induced anisotropy in the medium (proportional to the fracture density). The main question to answer is if a 3D multicomponent survey can detect the travel time shift between parallel and perpendicular directions generated by the investigated formation. The second subject is to investigate the potentiality of fluid discrimination with PS waves but also PP waves. Modeled data is generated using elastic anisotropic finite difference code. The analogies between cracks systems and anisotropic media have been analyzed in order to infer interesting considerations about fractures characterization. The anisotropic parameters and the geophysical model have been assumed on the basis of inplace data measurements. The obtained results demonstrated the correlation between the seismic features and the fracture characteristics, such as crack density, fractures orientation, fluid content and AVO anomalies.
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Carbonate Rock Type Matrix, the Ultimate Rock Properties Catalogue
Authors O. Al-Farisi, H. Belhaj, S. Ghedan, S. Negahban, J. Gomes, F. Yammahi, M. Amr, H. Khamissa, K. Ibrahim and A. Al-ShamsiThe heterogeneity in carbonate rocks, made it hard for Geoscientists and Reservoir Engineers to define a universal classification methodology that is able to honour the critical reservoir static properties. Most classifications, like, lithofacies, capillarity and textural methods have based their rock typing concept on one or two static properties, then tried to find an analog to other static properties to cluster or group them, then worked to populate the rock types across the whole field. However, from field observations and experiences of utilizing these conventional techniques, it was obvious that they suffered from several gaps, like inability to have the properties analog consistent throughout the whole reservoir. Moreover, the groups or clusters have big dispersion that produced overlaps, and then theoretically they could not fully honour the physics and rock properties links. Therefore, in this study, rock typing is made to honour static properties all together through changing the classification concept to resolve the gaps of the traditional methodologies. The ultimate objective of all reservoir characterization and rock classification is to enable building geological and simulation models, with optimum honouring of rock properties. To achieve this objective, the established framework in this research is based on analyzing the effects of each of the rock properties on another and the value and impact that each can add to the models most critical parameters. By this technique, the gap of pore and pore-throat network is resolved through Multiple Properties Intersection. This Integrated Carbonate Rock Typing technique starts with capturing the heterogeneity of carbonate rock by generating matrix of core permeability, capillary pressure (end point, threshold pressure and Plateau), pore-throat size distribution and porosity. Then intersecting this matrix to construct weighted links between these properties and identify unique groups. Resulted classes are novel carbonate rock type classes that entered to feedback analysis node to explore and validate the logic of linked physics to tune the classes’ thresholds and assure no overlap between any of classification properties. Finally for utilizing this technique in non-cored wells, an analog with logging data is structured through novel permeability, capillary pressure and saturation function called the C-Function to be the replacement of the J-Function in Carbonate.
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