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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
21 - 40 of 581 results
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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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