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Al-Busaidi, Salim (Petroleum Development Oman) | Hinaai, Qasim (Petroleum Development Oman) | Kumar, Rajeev Ranjan (Schlumberger) | Chen, Ying Ru (Schlumberger) | Al Lawatia, Redha Hasan (Schlumberger) | Yu, Dai Guo (Schlumberger) | Singh, Amit Kumar (Schlumberger) | Subbiah, Surej Kumar (Schlumberger)
Abstract The field under study is witnessing an increasing trend in NPT events while drilling vertical wells through high stressed shale formations and the underlying depleted sandstone reservoir in the same section. The field has multiple sets of faults with lateral variations in stress azimuth and completion quality with the regional strike-slip regime. High angled wells are being planned to increase reservoir coverage and perform hydro fracturing. This paper provides details of capturing stress regime variation along with the effects of depletion in offset wells and identify suitable azimuth of planned well with drilling risks through a 3D geomechanical study. Comprehensive 1D mechanical earth models are constructed using open hole logs, core data and available hydro-fracturing results for wells in the field. Rock mechanical properties have been calibrated at well scale as per core data. Poro-elastic horizontal strain method at well scale indicates a strike-slip to reverse fault variation with significant horizontal stress anisotropy as evident from the closure pressure range of 9,500 psi to 12,500 psi. 3D numerical geomechanical model has been constructed considering structural discontinuities, rock mechanical properties and formation pressure to estimate the principal stresses. Stress direction data from dipole sonic measurements and breakout azimuth from borehole image logs are used for calibration in 3D model incorporating faults. Stress path for depletion has been estimated. Results from the study suggested change in casing policy specifically to have a liner isolating the overburden formations where more than 800 m should be drilled prior to entering the depleted reservoir formation. 3D geomechanical analysis reckons that the mud weight should be in the range of 12.7 kPa/m to 13.1 kPa/m during building up the well profile at 80 deg inclination in overlying shale while 1D study suggesting a range of 13.2 kPa/m to 13.7 kPa/m. Along well path at 80deg to 90deg deviation within reservoir layer toward minimum horizontal stress azimuth, mud weight requirement was found to be much lower at 11.5 kPa/m to 12.1 kPa/m. Apart from mud weight, BHA and chemicals were optimized to avoid differential sticking and better hole cleaning for respective sections. Actual mud weight used was in the range of 12.8 kPa/m to 13.1 kPa/m for building up with no torque and drag issue while running liner and BHA trips. Mud weight was maintained in the range of 11.5 kPa/m to 11.8 kPa/m in the horizontal section with minimum breakouts and smoother hole condition. Cuttings shape and size analysis were performed regularly to check well behavior and manage downhole pressure higher than shear failure limit. Using 3D Geomechanical study and continuous monitoring of drilling parameters in near real-time, the buildup and reservoir sections have been drilled within schedule with no major NPT event and saved at least one week of rig days.
Summary Field-development optimization and optimization at the pattern scale are crucial to maximize the value of thermal enhanced-oilrecovery (EOR) projects. Application of a field net-present-value (NPV)-based pattern optimization algorithm honoring field-scale surface and subsurface constraints for in-situ-upgrading (IUP) projects has been described in the recent past. We integrate this new capability into a robust field NPV optimization platform. A two-stage field-development optimization algorithm is developed in this work. First, the steady-state pattern is optimized using the field-scale pattern optimization algorithm while honoring field-scale constraints and using a combined surface and subsurface performance-indicator-driven objective function. Ramp-up pattern designs are optimized separately using a solely pattern-scale performance-driven objective function in this stage. A preliminary pattern-delay time optimization follows next to precondition the problem for the subsequent field-scale optimization stage. The ramp-up pattern and pattern-delay times are optimized using a constant steady-state pattern in the second step of the algorithm. An appropriately penalized field-NPV-based objective function is used in this step to enforce field-scale surface and subsurface constraints. Optimization results on a realistic example application indicate that the time to oil-rate plateau could be significantly reduced on the order of multiple years while honoring the surface production constraints. This requires the use of an optimized ramp-up pattern in conjunction with the optimal steady-state pattern. The ramp-up pattern is approximately two patterns wide and features an increased heater density to deliver production acceleration. It is also notably more robust against the effects of subsurface uncertainties. Introduction Carbonate reservoirs hold large volumes of heavy oil among the Earth's heavy-oil resources (MacGregor 1996; Meyer and Olsen 1998; Meyer and Attanasi 2003). As such, they represent a major opportunity for the energy industry. Surface mining has been used for shallow (typically less than 100 m deep) resources.
Pan, Lijuan (Sinopec Northwest Petroleum Bureau Engineering Technology Research Institute & Sinopec Key Laboratory for Enhanced Oil Recovery in Fractured and Vuggy Reservoirs) | Liu, Huifeng (CNPC Engineering Technology R&D Company Limited) | Long, Wu (Sinopec Northwest Petroleum Bureau Engineering Technology Research Institute & Sinopec Key Laboratory for Enhanced Oil Recovery in Fractured and Vuggy Reservoirs) | Li, Jiaxue (China University of Petroleum, Beijing @Keramay) | Li, Jianbo (PetroChina Tarim Oilfield Company) | Liu, Qi (CNPC Engineering Technology R&D Company Limited)
Abstract Many mature gas reservoirs in China have very low formation pressure, like Yakela, Dalaoba, Kekeya etc. The formation pressure coefficient ranges from 0.6 to 0.9. Conventional well killing fluids easily leak into the formation and damage the well productivity. There are alternative well killing fluids in the industry to kill low-pressure formations, including foamy fluid, oil-based emulsion fluid and well killing fluid with density reducing agent. However, the densities of these alternative well killing fluids are mostly higher than 0.8 g/cm, and the cost is high if large volume of density reducing agent is used to decrease the density to lower than 0.8 g/cm. In this paper, a formula of nitrogen foamy well killing fluid is developed and successfully used in sand removal operations in low-pressure gas reservoirs. A series of tests are conducted to select the optimal foaming agent, foam stabilizer and other additives. Sodium dodecyl sulfate is selected as the foaming agent. However, the properties of Sodium dodecyl sulfate are not stable in hard water, so we use dodecyl dimethyl betaine with sodium dodecyl sulfate together to increase the foaming ability in tough water environment like in the desert area. Xanthan gum is selected as a foam stabilizer because it can thicken the fluid phase and reduce the drainage speed. Gelatin is also added into the formula because it can form stable coacervate with xanthan gum. The concentration of each additive is also optimized through lots of tests. Then the properties of the foamy well killing fluid are tested. Its density is between 0.50-0.80 g/cm and is adjustable. Under the temperature of 150°C, its plastic viscosity is 51mPa.s; its yield point is 51.5 Pa; the half-life period reaches 3055min. These basic properties meet the requirements of being used as well killing fluid. Salinity tolerance and oil resistance tests are also conducted to see the toughest environment that the fluid can be used in. The results show that the formula can be used in the oilfield where the water salinity is less than 100000 mg/L and the oil content is less than 15%. A model of calculating the equivalent density of the foam is developed. Scenarios of field application and onsite maintenance are also established. If a completion operation or a workover operation lasts for more than 24 hours, the foamy fluid needs to be maintained every day to guarantee its performance in the wellbore. The newly formulated well killing fluid has been used in three wells in Yakela condensate gas filed in Tarim Basin, western China, where the formation pressure coefficient is 0.67 and the formation is strongly water sensitive. A foamy well killing fluid density of 0.72g/cm was used (surface density 0.53 g/cm) for the sand removal operation in well Ya2-2-4. No fluid loss has been observed during the whole operational process. Neither gas seepage nor oil overflow has been observed during well killing. The well has recovered from production after workover and the production rate reaches 90×10m natural gas with 12t condensate oil every day. The new formula of foamy well killing fluid not only shows good laboratory properties under 150°C, but also proves to be a good solution to the downhole operations in low-pressure and depleted reservoirs.
A conventional industry approach is to curtail seismic activity during a downturn, focusing on limiting new exploration and drilling production wells instead. This paper demonstrates how maintaining investment in high-quality 3D seismic during the last downturn, together with selective exploration, quality geoscience, application of new technologies, and efficiently maturing discoveries to early cash flow, was successful in sustaining future production while deploying capital efficiently. Investment in 3D seismic does not contribute to immediate cash flow and, when funds are scarce, is an early candidate for cost reductions. By mid-2014, the seismic sector was the worst-performing segment in the upstream industry. However, without continued investment in seismic, future exploration success is threatened. This poses a dilemma for energy companies as they balance short-term cash flow with long-term value generation.
Behera, Chaitanya (Petroleum Development Oman) | Mahajan, Sandip (Petroleum Development Oman) | Annia, Carlos (Petroleum Development Oman) | Harthi, Mahmood (Petroleum Development Oman) | Obilaja, Jane-Frances (Petroleum Development Oman) | Abri, Said (Petroleum Development Oman) | Hamdoun, Lana (Petroleum Development Oman)
Abstract This paper presents the results of a comprehensive study carried out to improve the understanding of deep bottom-up water injection, which enabled optimizing the recovery of a heavy oil field in South Oman. Understanding the variable water injection response and the scale of impact on oil recovery due to reservoir heterogeneity, operating reservoir pressure and liquid offtake management are the main challenges of deep bottoms-up water injection in heavy oil fields. The offtake and throughput management philosophy for heavy oil waterflood is not same as classical light oil. Due to unclear understanding of water injection response, sometimes the operators are tempted to implement alternative water injection trials leading to increase in the risk of losing reserves and unwarranted CAPEX sink. There are several examples of waterflood in heavy oil fields; however, very few examples of deep bottom water injection cases are available globally. The field G is one of the large heavy oil fields in South Oman; the oil viscosity varies between 250cp to 1500cp. The field came on-stream in 1989, but bottoms-up water-injection started in 2015, mainly to supplement the aquifer influx after 40% decline of reservoir pressure. After three years of water injection, the field liquid production was substantially lower than predicted, which implied risk on the incremental reserves. Alternative water injection concepts were tested by implementing multiple water injection trials apprehending the effectiveness of the bottoms-up water injection concept. A comprehensive integrated study including update of geocellular model, full field dynamic simulation, produced water re-injection (PWRI) model and conventional field performance analysis was undertaken for optimizing the field recovery. The Root Cause Analysis (RCA) revealed many reasons for suboptimal field performance including water injection management, productivity impairment due to near wellbore damage, well completion issues, and more importantly the variable water injection response in the field. The dynamic simulation study indicated negligible oil bank development due to frontal displacement and no water cut reversal as initial response to the water injection. Nevertheless, the significance of operating reservoir pressure, liquid offtake and throughput management impact on oil recovery cann't be precluded. The work concludes that the well reservoir management (WRM) strategy for heavy oil field is not same as the classical light oil waterflood. Nevertheless, the reservoir heterogeneity, oil column thickness and saturation history are also important influencing factors for variable water injection response in heavy oil field.
Reviewing a myriad of papers presented at different conferences during the past year and attending some of those to hear the oral presentation versions, I can group the current trends in heavy-oil operations and research into two major categories: Process optimization and use of chemicals as additives to steam and water. Here are some highlights from those categories. Several papers focused on purely computational methods--including multi-objective optimization and proxy models--to optimize the steam-assisted gravity drainage (SAGD) method with specific attention on preferential steam allocation. Real-life examples of these applications consist of inflow- and outflow-control devices and steam splitters developed for diverting the steam to preferential zones, thus minimizing the use of steam. As an indirect method to provide supplemental data for the optimized solutions, seismic data were also used.
The full-field development plan for the Khazzan project in Oman is based on drilling approximately 300 wells targeting gas-producing horizons at measured depths of approximately 6000 m with 1000‑m horizontal sections. The first attempt to drill these wells had to overcome many drilling challenges, including wellbore instability and drilling dysfunctions. This paper shows how the application of existing technologies and processes is leading to performance gains and improvements in wellbore quality. BP has embarked on an appraisal drilling campaign that targets a tight gas reservoir in northern Oman. The subject field is an area of approximately 2800 km2 and contains the Cambrian Barik, Miqrat, and Amin reservoirs.
I was asked to serve on the JPT Editorial Committee for another 3-year term and happily accepted the offer. In preparing for this month's feature, I revisited my first Technology Focus writeup for the March 2016 issue. I concluded the piece by saying, "Before closing, I would like to bring your attention to two critical points as we experience one of the more severe economic downturns in the oil industry. First, research on technology for heavy-oil recovery must go on one way or another. What has happened over the last 3 years in relation to these two issues I raised in March 2016?
An operator has faced a number of challenges producing heavy oil (8000–20 000 cp) from the Khuff and Kahmah carbonate reservoirs at the Mukhaizna field since their discovery in 2010. The large, low-productivity reservoirs have few analogs in the world, so the operator established new approaches to bring these reserves to market. This paper covers the staged field-development methodology, including analysis and evaluation of various development concepts, that enabled the company to optimize both completion design and artificial-lift selection, reducing downtime and lowering operating costs by nearly 50%. The Mukhaizna field, located in the eastern part of central Oman, was discovered in 1975 by Petroleum Development of Oman. The Kahmah Group consists of shelf carbonate deposits of Cretaceous age, whereas the Khuff formation is of Permian age, with a major unconformity between the lower Kahmah and Khuff formations.
Developments in the processing of sour gas were the topics of several papers presented at the 2014 Abu Dhabi International Petroleum Exhibition and Conference (ADIPEC) last month. Sour gas reserves, historically left undeveloped because of the technical challenges and cost involved in their extraction and processing, are being revisited as potential sources of supply in areas with high demand for natural gas. Only in recent years has technology advanced to an extent that makes processing of sour gas with high carbon dioxide (CO2) and hydrogen sulfide (H2S) feasible. The Middle East region is particularly interested in tapping its challenging gas reserves, of which 60% are sour. The United Arab Emirates' annual rate of natural gas consumption is expected to increase from the current 2.8 Tcf to 5.2 Tcf by 2015, and 6.3 Tcf by 2020.