Enhanced Oil Recovery (EOR) techniques helps to recover residue oil after Primary and secondary recovery of reservoir. This paper deals with a new Carbon Di Oxide (CO2) EOR technique, "HOT CO2" which includes combination of thermal and solvent techniques where miscibility and viscosity reduction are primary concern. In the proposed method CO2 will be superheated above the reservoir temperature to reduce the oil viscosities at the same time partially mix with crude oil which improves oil mobility. Heavy Oil field-Bati Raman from Turkey which is under CO2 Flooding, after the application of HOT CO2 flooding theoretical calculation shows it reduces the viscosity and partially mix with oil to increase the swelling factor which ultimately increase the recovery factor comparative with the CO2 flooding.Thus the screening criteria for HOT CO2 Flooding can now include highly viscous oil and covers wide variety of reservoirs which was not possible with CO2 flooding earlier. For the injection of HOT CO2 a special surface facility requires to prevent corrosive and thermal effect. Before implementation of HOT CO2 flooding method simulation model work, laboratory work and pilot field test are necessary areas to work. HOT CO2 flooding should be preferred absence of any major fault makes this technique more effective. "HOT CO2 flooding" will going to be one the best option for EOR in future. Introduction: There are mainly two methods of carbon dioxide (CO2) injection: Continuous injection of CO2 during life of flood and Intermittent injection of CO2 followed by Water Alternating Gas (WAG). "HOT CO2" name came because it's a combination of two-method .i.e. thermal and solvent. The using solvent is CO2 because after water (H2O), CO2 is most economical, soluble in oil up to great extend and it swells the oil and also recycles after recovering the oil. The HOT CO2 flooding firstly heat the reservoir at the same time it partially miscible with the oil. The operating temperature of HOT CO2 which depends upon reservoir temperature and oil property. It is above the critical point of CO2 phase diagram as shown in three phase diagram below. CO2 is a unique fluid that has potential to perform either as an immiscible or a miscible enhanced oil recovery agent. The nature of its behavior dependent upon the composition of the oil and the reservoir pressure and temperature. In the supercritical phase CO2 is partially miscible with Oil.
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Subsea blowout preventer (SBOP) reliability is a major challenge in Deepwater Drilling & Completion operations, accounting for one of the major equipment failures and Non-Productive Time (NPT) costs yearly. This paper focuses on SBOP technological advancement since the Deepwater Horizon/Macondo incident in 2010, with additional emphasis on reliability, equipment condition monitoring and statistical root cause analysis. After finishing a deepwater well, the SBOP must undergo maintenance, repair if needed and pressure testing before being deployed on the next well. The rig owner is under great pressure to complete this turn-around to avoid waiting time. On an average, in-between wells, rig contractor took approximately 2.6 days extra time (NPT) waiting after completing top hole to get ready to deploy SBOP during 2019-20 exploration and appraisal campaigns. This can be critical during development campaigns where number of rig moves are involved quickly or in cases where top holes are batch drilled the waiting time for SBOP readiness can be as high as 7-8 days per well. Some operators are collaborating with drilling contractors in number of ways to arrange for a second fully assembled and (offline) pressure tested SBOP to be available on the rig (Dual SBOP); deployment of additional trained subsea engineers for performing maintenance/repair. SBOP pressure-testing time can also be drastically reduced by using comparative pressure-testing software to eliminate human error and accelerate pressure testing. Furthermore, leak detection time can be eliminated by installing sensors, and real-time test monitoring providing increased reliability with the additional advantages that conditional monitoring can be enhanced with the same digital sensors. SBOP dashboard that simplifies existing diagnosis and allow remote monitoring of the subsea SBOP control system will improve communication of SBOP health also serve common platform across rig fleets that allow standardization of SBOP diagnostic data and aids in operational decision making Ensuring additional SBOP redundancy especially while operating Emergency Disconnect System (EDS) available through Remotely Operated Vehicle (ROV) control panel or acoustic system. In addition, it is mandatory for the SBOP to have Autoshear and Deadman systems to be able to shut in the well in case of an emergency. Furthermore, technological workshop with several major service vendors have being held to ascertain current advances like Multifunctional profile, Accumulator recharged by ROV, ROV DP system, An Auxiliary Accumulator System and upgraded Acoustic System. In the end, the development of new technologies applied for the SBOP targets the overall cost optimization of the well lifecycle but also assure SBOP functionality. This paper is intended to provide considerations for operators in developing their future campaigns to frame scope of work for SBOP and rig contracting strategy.
Ensuring long-term integrity of existing plugged and abandoned (P&A) and active wells that penetrated the selected CO2 storage reservoir is the key to reduce leakage risks along the wellpath for long-term containment sustainability. Restoring the well integrity, when required, will safeguard CO2 containment for decades. Well integrity is often defined as the ability to contain fluids with minimum to nil leakage throughout the project lifecycle. With a view to develop depleted gas fields as CO2 storage sites in offshore Sarawak, it is vital to determine the complexity involved in restoring the integrity of these P&A wells as well as the development wells. Leakage Rate Modeling (LRM) was performed to identify and evaluate the associated risks for designing the remedial action plan to safeguard CO2 storage site. The P&A wells in the identified depleted gas fields were drilled 35–45 years ago and were not designed to withstand high CO2 concentration downhole conditions. Corrosive-Resistant Alloy (CRA) tubulars and CO2 resistant cement were not used during well construction and downhole pressure and temperature conditions may have further degraded the material strength and elevated the corrosion susceptibility. As a proof of concept, single well was selected to assess the loss of containment along the wellbore and to determine the complexity in resorting the well integrity, multiple scenarios were considered in LRM and composite structure and barrier parameters were assigned to estimate possible leakage pathways. Detailed numerical models were simulated for estimating leakage from reservoir to the surface through possible leakage pathways. Risks were identified and remedial action plan was designed for restoring well integrity. Post remedial plan covers Marine CO2 dispersion modeling to design comprehensive monitoring and mitigation plan for potential CO2 leakage in the marine environment. This study summarizes the unique challenge associated with estimating well integrity and re-entering existing P&A wells. Leakage rate modeling along these wells involves uncertainties but when carried out with realistic parameters, it can be used as a predicting tool to determine the nature and complexity of leakage. Integrating with site survey results for any indication of gas bubbling, decision can be made to restoring the well integrity. The paper outlines the detail strategic options to safeguard CO2 storage by restoring well integrity using LRM and integrating with marine CO2 dispersion modeling. Assessing well integrity of P&A wells on individual basis, risk is assessed and identified. Proper remedial actions are proposed accordingly. Quantification of all the uncertainties involved needs to be conducted that may affect long-term security of CO2 storage site.
As conventional drilling learning curves mature from drilling simple vertical wells to deviated wells to complex multi-lateral horizontal wells, the boundaries needed to be broken to reach much deeper depths rather than consuming the time in drilling multiple shorter laterals. Horizontal ERD wells in Qarn Alam cluster were planned to be drilled in four sections where the 17.5-in section is drilled vertically followed by a deviated 12.25-in section and continued by landing in 8.5-in section and finally the 6.125-in horizontal lateral. Many attempts of performance improvement initiatives were executed over many years however there were always flaws and inconsistency in drilling performance delivery. As the need of ERD grew, a detailed offset wells analysis had to be performed where all the deficiencies and issues had to be pin pointed, RCA (Root Cause Analysis) had to be performed and plans for success had to be laid out. From challenges achieving required dog legs in the top sections with increased risks of axial and lateral vibrations, to the difficulties faced in the landing section drilling through unconsolidated and reactive shales, to the difficulties transferring weight to the bit at deeper depths in the horizontal laterals drilling highly porous zones of sticky limestones resulting in severe torsional vibrations. A new approach of drilling had to be executed with a renovated set of drilling parameters envelopes, revised trajectory designs, re-engineered BHA designs, right choice of fit for purpose bits and effective real-time performance monitoring.
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