Day 1 Mon, November 11, 2019最新文献

{"title":"A Case Study of High H2S Aquifer Production Testing : Planning and Execution","authors":"Muhammad Kamal Aman Shah, K. Mudaliar, Mohammad Shahrin Mamat, Zaimi Salleh","doi":"10.2118/197448-ms","DOIUrl":"https://doi.org/10.2118/197448-ms","url":null,"abstract":"\u0000 This paper shares a case study of production testing of a large Middle East dolomitic aquifer containing high concentration of H2S. The aim of this paper is to discuss on the HSE aspects primarily on wellsite and operation safety by sharing the issues, challenges and mitigations at various stages of planning and execution.\u0000 As part of field X development strategy, water flooding is required to maximize recovery. However, due to water scarcity Operators had to look into ground aquifers to support water injection leading to dolomitic reservoir being identified as the best source. The initial planning was based at 30 ppm H2S limit centered on samples obtained from nearby field located 400 km from field X. Based on actual bottomhole samples from field X, it was found that the reservoir contained higher H2S concentration which requires the operator to re-strategize the production testing operation within a limited time frame to cover safety and security aspects.\u0000 The operation involved multidisciplinary collaboration encompassing DST design, process safety and security. As the well is located in a densely populated area, a first of its kind H2S dispersion study in aqueous solution was introduced.\u0000 The DST operation was successfully conducted with no major HSE and security incident recorded. The well was tested up to a maximum rate of 20 kbl/d and through the introduction of multiple injection point, the concentration H2S was successfully reduced to 2 ppm.\u0000 The H2S dispersion study in aqueous phase played a pivotal role, assisting in risk identification and quantification. Through the study, many critical HSE aspects were addressed and resolved, expediting the planning stage and improved the whole system. The modelling was based on worst case scenario where all 18,000 ppm of H2S will disperse to air. On the other hand, for normal operation, some portion of H2S is expected to dissolve in water during discharge. It is also noteworthy to mention that understanding the limitation of the model is equally important to assist in planning and executing the operation effectively.","PeriodicalId":11061,"journal":{"name":"Day 1 Mon, November 11, 2019","volume":"37 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88736915","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Versatile Base Oil that Breaks Drilling Barriers","authors":"Nandakumar Supramaniam, Farah Shakina Ezani","doi":"10.2118/197895-ms","DOIUrl":"https://doi.org/10.2118/197895-ms","url":null,"abstract":"\u0000 This paper presents the technical development of an operator's drilling base oil produced from their MG3 plant which was evaluated through extensive laboratory studies and field trials prior to commercialization.\u0000 The base oil is based on a majority iso-paraffin component which gives an optimum kinematic viscosity, flash point and pour point for drilling applications. In addition, the drilling fluid has minimal aromatic content to fulfil international eco-toxicity standards set by CEFAS and US EPA, 821-R-11-004 Method 1619. The base oil is compatible with various oil/synthetic mud systems and additives with its low viscosity characteristic lesser than 2.4 cSt at 40 deg C which offers excellent drilling performance for Shallow and Deepwater wells. Furthermore, the base oil exhibits high flash point of more than 90 deg C to reduce potential fire hazard while drilling HPHT and ERD wells. At the same time, its superior pour point (as low as -42 deg C) suitable for storing base oil in sub-zero conditions and to be used as deep-water drilling fluid in extremely cold countries like Russia. Its unique high-performance properties provide exceptional temperature stability and optimum rheological properties throughout the extreme temperature profile of a Deepwater or HPHT well, thus resulting in a very low ECD despite drilling with high ROP.\u0000 Field trials were carried out to verify the base oil's performance under laboratory conditions. The base oil was tested as base fluid in SBM for both Shallow and Deepwater wells. The Shallow well was drilled vertically in water depth of 105M with a maximum mud weight of 14.6 PPG and bottom hole static temperature of 280 deg F. The Deepwater well was drilled vertically in water depth of 1008 M and subsequently side-tracked to a maximum inclination of 46 degree. Both wells were drilled successfully without any drilling fluid related issues as compared to severe losses experienced with respective offset wells.\u0000 A total of approximately 138 oil and gas wells were drilled by the operator utilizing their own base oil till 2018 after completing the technical evaluation in 2014. From the field trials and actual drilled wells, a comprehensive database analysis was developed for future improvisation and broader performance portfolio. The main technical challenge for the operator was to engineer a drilling fluid system with base fluid and chemical additives to obtain minimal ECD for reducing lost circulation risk. The base fluid properties are ideal for Shallow, HPHT, ERD and Deepwater applications whereby the ECD margin for Deepwater and ERD drilling is often narrow as compared to shallow wells. The successful project execution of base oil for drilling represents a significant milestone, elevating the company's base oil progress at par with other global base oil producers.","PeriodicalId":11061,"journal":{"name":"Day 1 Mon, November 11, 2019","volume":"28 2 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82720475","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Rotating Equipment Switchover Dashboard","authors":"Khalid Alzahrani, Abdulaziz Alzahrany","doi":"10.2118/197477-ms","DOIUrl":"https://doi.org/10.2118/197477-ms","url":null,"abstract":"\u0000 \u0000 \u0000 This Instruction outlines the procedures for testing spare pumps. The text includes: DefinitionResponsibilitySwitching IntervalsSwitching TimeSwitching ProcedureSwitchover Dashboard\u0000 \u0000 \u0000 \u0000 This procedure outlines switching between \"Main Pump\" (running pump) and \"spare pump\" (the one to be tested). All other type of equipment's (rotating and/or stationary) will be switchover based in the following:PM (Preventive Maintenance) program.Inspection ProgramTest and Inspection T&I program\u0000 \u0000 \u0000 \u0000 \u0000 \u0000 \u0000 \u0000 \u0000 \u0000 \u0000 \u0000 \u0000 \u0000 \u0000 \u0000 \u0000 \u0000 \u0000 Switching between spare pumps and main ones shall be done once every 4 to 6 weeks to ensure the equipment availability and reliability. It shall coincide with the monthly vibration survey. For the compressor lube oil system, the functional test is preferred to be scheduled before a planned compressor shutdown.\u0000 Discussions were held with the rotating equipment manufacturers, specialists and users to clarify all corrosion, electrical and mechanical concerns regarding the switching periods between alternate pieces of rotating equipment. The compilation of all of these discussions and concerns resulted in the following two basic guidelines which within themselves comprise the heart of the Rotating Equipment Operating Strategy.\u0000 \u0000 \u0000 \u0000 \u0000 Equipment of this voltage type should be switched from the stand-by mode to the operational mode once per month.\u0000 Note: Excluding any stand-by equipment that is not required by Operations should be run a minimum of one continuous hour every month.\u0000 \u0000 \u0000 \u0000 Equipment of this voltage type should be switched from the stand-by mode to the operational mode once every two weeks. This includes the switching between the main and auxiliary lube/seal oil pumps.\u0000 Note: Excluding any stand-by equipment that is not required by Operations should be run a minimum of thirty continuous minutes every two weeks.\u0000 \u0000 \u0000 \u0000 \u0000 \u0000 Switching between critical pumps shall be conducted during the normal working days in day time where the support organizations are available.\u0000 \u0000 \u0000 \u0000 This RIM covers four different pump startup scenarios. Each one of these scenarios includes important checks and procedures that need to be followed to ensure a reliable pump start-up. Below you will find a detailed start-up procedure for each scenario. The procedure will be detailed but general, additional steps may be required for some particular process.\u0000 \u0000 \u0000 \u0000 \u0000 \u0000 Switchover = (Total Equipment comply with switchover/Equipment Schedule Switchover) X 100%, Target 90%\u0000 Note:\u0000 Switchover the pump:\u0000 \u0000 \u0000 \u0000 \u0000","PeriodicalId":11061,"journal":{"name":"Day 1 Mon, November 11, 2019","volume":"26 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82867100","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Bullhead Stimulation and First Real-Time Fiber-Optic Surveillance in Extended-Reach Horizontal Laterals to Maximize Reservoir Recovery in a Giant Offshore Carbonate Oil Field Abu Dhabi","authors":"Rajes Sau, Ahmed Kiyoumi, Alaa Amin, Gladwin Correia, A. Barghouthi, Alqasem Almheiri, Edward Jason Wheatley, Y. Ali, B. Seabrook, Renzo Angeles, C. Shuchart","doi":"10.2118/197752-ms","DOIUrl":"https://doi.org/10.2118/197752-ms","url":null,"abstract":"\u0000 A giant carbonate field offshore Abu Dhabi is being redeveloped using extended-reach-horizontal-laterals up to 20,000 ft with open hole un-cemented liner, drilled from artificial islands. Long horizontal wells provide significant profitability in unit development cost; however it is critical to ensure effective stimulation of the complete lateral to maximize reservoir recovery. Earlier, SPE171800 introduced an innovative liner design for long open hole horizontal completions, namely Limited-Entry Liner (LEL) that enables high rate aggressive stimulation by bullheading technique. This paper will present the field stimulation results of more than five LEL laterals ranging several-kilometers in open hole completions, demonstrating the impact of LEL stimulations in accelerating production and maximizing reservoir recovery.\u0000 Several LEL horizontal wells were completed in low-permeability rock to enable high rate bullhead matrix stimulation. ExxonMobil proprietary software is used to design fit-for-purpose LEL that enables acid injection conformance along the lateral and at the same time creates deep-wormholes by high-velocity acid-jets through 3-mm/4-mm holes in liner base-pipe distributed non-uniformly along the lateral, compartmentalized with oil/water-swellable-packers. The execution of the stimulation campaign was made possible through the use of modularized-equipment packages installed on an ADNOC-vessel, utilizing a unique mechanism that locks the package components to frames installed to the vessel-deck. The stimulation package consists of 6×2000HHP pumps delivering up to 60bpm at 10,000psi. The liquid-additive system, 140bbl vertical mixing tank and more than 190,000gallon raw-acid storage tanks are fully automated to enable acid mixing and pumping on the fly at the desired rates, concentrations and recipes.\u0000 In order to demonstrate the effectiveness of acid placement and effective stimulation across the entire lateral, real-time Fiber-Optic surveillance techniques (DTS-DAS) were utilized. The recorded thermal and acoustic profiles provided a qualitative and quantitative measurement of the effectiveness of the mechanical diversion delivered by the LEL design. These data will help in corroborating and fine-tuning the model used in lower completion design of maximum reservoir contact wells in future field development. Along with well performance and real-time surveillance, production/injection logging data demonstrates effective stimulation of the entire lateral.\u0000 This paper presents field performance results from successful bullhead stimulation of extended reach horizontal well completed with LEL in low-permeability-reservoir. This paper also presents our first application of fiber-optic-DTS-DAS real-time-surveillance during stimulation and post-stimulation water injection. Advanced surveillance data demonstrated the success and effectiveness of the LEL completion and stimulation in extended-reach long horizontal open hole laterals.","PeriodicalId":11061,"journal":{"name":"Day 1 Mon, November 11, 2019","volume":"13 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87651468","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"New Corrosion Growth Model Based on Pipeline Intelligent Pigging Data - Correlating Corrosion Defects Numbers with their Depth","authors":"Mohamed Zouheir Trojette, Anouar Zebibi, Abdallah Hammadi, K. Hosani","doi":"10.2118/197958-ms","DOIUrl":"https://doi.org/10.2118/197958-ms","url":null,"abstract":"\u0000 As part of their integrity management system, Oil and Gas operators carry out internal inspection of their pipelines by intelligent pigging. State of the art MFL and UT inspections are used to detect and accurately size the defects, which are present in the pipeline. The predominant type of defects reported is due to internal corrosion.\u0000 It is well established that corrosion is a naturally occurring phenomena. When the conditions are right for corrosion to develop, it starts by a single defect or very few defects which are shallow. Then as the pipeline is operated and corrosion further develops the defects increase in size and numbers.\u0000 This paper review several intelligent pigging reports data, and analyze the reported defects in terms of numbers and depth for several pipelines, in order to establish a correlation (mathematical model) between the number of internal corrosion defects and their depth. Defects counts will be made and equations will be developed for several pipelines. These equations will basically establish the number of defects as a function of their depth or vice versa.\u0000 More over when multiple intelligent pigging runs on same line are available, these derived equations will be compared with the objective to establish a novel model to determine corrosion growth rate in a non-conventional manner. In fact the models (# of defects and their depth equation) established for different inspections will be compared and a corrosion rate model establishing the increase in number of features and their number over time will be thereafter derived.","PeriodicalId":11061,"journal":{"name":"Day 1 Mon, November 11, 2019","volume":"6 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81829513","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Lessons Learnt from the use of a Quantitative Risk Based Approach to Manage SIMOPS Activities","authors":"Prashanth Ignatius, Saud Al Hammadi, G. Basile","doi":"10.2118/197622-ms","DOIUrl":"https://doi.org/10.2118/197622-ms","url":null,"abstract":"\u0000 A number of major process industry accidents have involved SIMOPS. Company conducted construction (modifications) activities inside its own plant during the period from November 2017 to May 2018. The Group Risk Acceptability Criteria Guidelines have been defined by Company for the purpose of providing Senior Management with quantitative information about the risk profile during SIMOPS activities and to help them in taking informed decision about the execution strategy to ensure safe operations.\u0000 A DNV-GL Phast based model of the plant has been used to assess the risk level. Using Group Risk guidelines for On-site personnel based on the FN (Frequency – Number of Fatalities) Curve, Company evaluated and compared several SIMOPS options prior to the actual works to identify the optimal manning level and schedule to ensure the overall Group Risk laid in the ALARP region.\u0000 The quantitative risk assessment served as a tool to derive the optimal manning levels and shutdown schedule during the SIMOPS activities. The manning levels were controlled through additional administrative measures to ensure its implementation.\u0000 Moreover, the overall SIMOPS Risk (FN Curve) for the current activity was compared with the risk undertaken during similar previous activities conducted in 2015 and 2016. After the successful completion of the activities, the Risk Assessment was updated to take into consideration the actual manning and schedule inputs for the Pre-Shutdown and Partial Shutdown phases. The actual overall Group Risk (including Pre and Partial Shutdown) was within the Company Group Risk Acceptability Criteria.\u0000 Additionally, valuable Lessons Learned were identified such as purging (with inert gas), rather than just the depressurization of the equipment in the units during Shutdown, can contribute to a significant risk reduction.\u0000 This paper presents a novel approach to evaluate SIMOPS risk on personnel using a Group Risk criteria based on FN Curve. This provides an additional re-assurance to stakeholders involved in the activity to take informed decisions based on a quantitative risk analysis rather than a qualitative assessment.","PeriodicalId":11061,"journal":{"name":"Day 1 Mon, November 11, 2019","volume":"15 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83900217","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Middle East Gas Field Case Study Proves Step Change in BHA Reliability Through New HFTO-Isolation Tool","authors":"D. Heinisch, Armin Kueck, Christian Herbig, M. Zuberi, Volker Peters, H. Reckmann","doi":"10.2118/197409-ms","DOIUrl":"https://doi.org/10.2118/197409-ms","url":null,"abstract":"\u0000 Self-excited torsional vibrations of the bottomhole assembly (BHA) at frequencies above 50 Hz, so-called \"high-frequency torsional oscillations\" (HFTO), can damage drilling tools and can increase non-productive time (NPT). A recently developed HFTO-isolation tool protects the drilling tools above this tool from these harmful vibrations. More than 200 field runs were investigated to evaluate the changes in reliability and benefits.\u0000 The concept of the isolation tool works similarly to a two-mass flywheel used in automotive drive trains. The design was simulated, lab-tested and first deployed in a field run in 2018. Since then, the isolation tool was successfully used in various fields and applications in the Middle East. HFTO severity while drilling was measured and recorded below and above the isolation tool to verify functionality and to quantify reduction in torsional loads (torque, tangential acceleration) for the measurement while drilling (MWD), mud pulse telemetry (MPT), and logging while drilling (LWD) tools above the tool. In addition, HFTO-related incidents and other drilling performance indicators with and without the new tool were analyzed.\u0000 Analysis of the recorded vibration data from several field runs with an additional high-frequency MWD-tool reveals that the isolation principle works consistently. As predicted by simulation, the measured torsional vibration amplitudes above the tool are significantly lower than without using it, demonstrating the effective protection for MWD-, LWD-, and MPT-tools in the BHA.\u0000 The tool has proven consistent performance in more than 16,000 accumulated circulating hours. Tool failures caused by HFTO were eliminated, compared to 22 percent of all failures without the isolation tool. The results of an analysis of individual MWD- and MPT-tools used in runs with and without the isolation tool show a significant increase in distance drilled per tool deployment and re-run decisions. This directly translates to increased asset utilization, fewer trips for failure, and BHA handling operations that results in less non-productive time (NPT) and enables drilling in extremely challenging environments more efficiently.","PeriodicalId":11061,"journal":{"name":"Day 1 Mon, November 11, 2019","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88537950","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Fluid Property Prediction with Unified Equation of State in a Compositional Surface Network Comprising 5000+ Wells","authors":"K. Mogensen, Jyotsna Asarpota, Y. Bansal","doi":"10.2118/197494-ms","DOIUrl":"https://doi.org/10.2118/197494-ms","url":null,"abstract":"\u0000 ADNOC has embarked on the second phase of its ambitious integrated capacity model (ICM) project with the overall aim to optimise its fluid production portfolio from the well level to the processing facilities. A key feature of the new software tool is the ability to track and predict fluid properties over time across the entire production network, comprising thousands of wells and a myriad of pipelines.\u0000 The reservoir fluid composition is assigned at well level for each producing reservoir. The compositional tracking over time is straightforward for many wells, but complicating factors do arise, such as\u0000 Lateral compositional variation related to complex reservoir charging history Vertical compositional gradients, especially for near-critical fluids The presence of initial and secondary gas caps, resulting in gas coning Injection of miscible gas for enhanced oil recovery\u0000 The fluid systems range from medium-API oil to gas condensates and the key chemical components vary as follows: C1 [5-80%], CO2 [0.5-8%], and H2S [0-35%].\u0000 Mixing of pressurized fluids with different compositions at various junctions in the network requires a robust thermodynamics model to capture the associated variation in fluid properties, particularly density and viscosity as a function of pressure and temperature. We demonstrate that it is possible to constrain one unified equation of state applicable to all fluids, as long as the fluid systems used for the tuning span the entire range of compositions observed. Mixing of fluid streams is computationally much simpler if each stream is made up of the same components (although in different amounts) with the same component properties. On average, the predicted fluid density is within 1% of the measured value from a multi-stage separator test.","PeriodicalId":11061,"journal":{"name":"Day 1 Mon, November 11, 2019","volume":"128 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87945543","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"A Novel Thermochemical Fracturing Approach to Reduce Fracturing Pressure of High Strength Rocks","authors":"A. Al-Nakhli, Zeeshan Tariq, M. Mahmoud, A. Abdulraheem, Dhafer Al-Shehri","doi":"10.2118/197593-ms","DOIUrl":"https://doi.org/10.2118/197593-ms","url":null,"abstract":"\u0000 Current global energy needs require best engineering methods to extract hydrocarbon from unconventional resources. Unconventional resources mostly found in highly stressed and deep formations, where the rock strength and integrity both are very high. The pressure at which rock fractures or simply breakdown pressure is directly correlated with the rock tensile strength and the stresses acting on them from surrounding formation. When fracturing these rocks, the hydraulic fracturing operation becomes much challenging and difficult, and in some scenarios reached to the maximum pumping capacity limits. This reduces the operational gap to create hydraulic fractures.\u0000 In the present research, a novel thermochemical fracturing approach is proposed to reduce the breakdown pressure of the high-strength rocks. The new approach not only reduces the breakdown pressure but also reduces the breakdown time and makes it possible to fracture the high strength rocks with more conductive fractures. Thermochemical fluids used can create microfractures, improves permeability, porosity, and reduces the elastic strength of the tight rocks. By creating microfractures and improving the injectivity, the required breakdown pressure can be reduced, and fractures width can be enhanced. The fracturing experiments presented in this study were conducted on different cement specimen with different cement and sand ratio mixes, corresponds to the different minerology of the rock. Similar experiments were also conducted on different rocks such as Scioto sandstone, Eagle Ford shale, and calcareous shale. Moreover, the sensitivity of the bore hole diameter in cement block samples is also presented to see the effect of thermochemical on breakdown pressure reduction.\u0000 The experiments showed the presence of micro-fractures originated from the pressure pulses raised in the thermochemical fracturing. The proposed thermochemical fracturing method resulted in the reduction of breakdown pressure to 38.5 % in small hole diameter blocks and 60.5 % in large hole diameter blocks. Other minerology rocks also shown the significant reduction in breakdown pressure due to thermochemical treatments.","PeriodicalId":11061,"journal":{"name":"Day 1 Mon, November 11, 2019","volume":"98 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76532866","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Urban Planning Creates Value for a Highly Congested Field in Sultanate of Oman","authors":"Abid Hussain, A. Ghufaili, Chaitanya Behera","doi":"10.2118/197225-ms","DOIUrl":"https://doi.org/10.2118/197225-ms","url":null,"abstract":"\u0000 This paper discusses the urban planning process applied for field development of one of the biggest and most congested field in sultanate of Oman. The field has a carbonate reservoir contains a light oil with associated gas. The reservoir is currently under waterflood development. The oil production is co-mingled with other fields at production station and the produced water is pumped back into the reservoir for pressure maintenance and the remaining is disposed into another reservoir. The field contains an area layout of 22 km °18 km. The new development proposal of further infill drilling at a narrower spacing was challenging in term of well interference with existing infrastructure, spacing, rig movement and accessibility.\u0000 The first pass of checking the wells locations feasibility shows that only 30 percent of the wells can be drilled due to massive amount of existing wells with surface infrastructure. It was not easy to develop and drill the majority of proposed wells with required surface infrastructure. A detailed urban planning study was carried out to address the inherent issues and challenges associated with re-development of the field. An integrated multi-discipline team was formulated consisting of, Concept Engineering, Geomatics, Production Geologist, Reservoir Engineering and Well Engineering. A close coordination was also maintained with other relevant disciplines to address the surface development issues and for making the quality concept decisions in early phase of the project. The process of urban planning applied in this study was documented as a best practice within the company and cross learnings were used as basis during the study and also captured in Urban Planning Guideline which was developed internally.\u0000 Resolving the challenges for placement of wells on surface and rig accessibility for drilling challenged the normal ways of working and triggered the un-conventional thinking to establish the well drilling feasibility and integration with surface scope. Consequently, project team have come up with ways to drill the wells that would not be drilled by following the normal way of working. Integrated urban planning enabled the proposed number of wells to be drilled despite the insufficient space to accommodate standard pits and pads. In conventional approach, initial urban planning assessment concluded feasibility of drilling only 30 percent of proposed wells. However, the team managed to improve the feasibility of drilling those wells up to 90 percent. This has allowed the maturation of the planned target hydrocarbon volume and created huge value in re-development of this field. Tangible benefits also achieved in early decision-making, up to two months schedule acceleration could be realized in field development through integrated urban planning approach. Study has demonstrated that urban planning can save approximately 10 percent in off-plot CAPEX. On top of this, urban planning has helped in lowering HSE risks during th","PeriodicalId":11061,"journal":{"name":"Day 1 Mon, November 11, 2019","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89692621","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}