A leading exploration and production company in India drilled a high-pressure/high-temperature (HP/HT) well in eastern offshore India and required drillstem testing (DST) to be conducted using the service company's multiple-set HP/HT retrievable packer, multicycle circulating valve, and multicycle tester valve. The bottomhole temperature at reservoir depth was approximately 460°F. This case study discusses the recently conducted DST of the HP/HT well by one of the largest global oilfield service providers in collaboration with the operator. The HP/HT environment presented many challenges. The operator initially decided to deploy a permanent packer; however, after comprehensive preoperation planning with the service provider, the decision was made to run a retrievable packer to save time and costs associated with setting and milling/retrieving a permanent packer. The hook-wall concentric bypass, 7-in. retrievable packer was designed and tested for HP/HT environments. It was decided to deploy a full-suite multicycle DST tool string rated to 450°F. To help ensure a higher success rate for the long duration of the test, a clear fluid system of lower weight (14.6 lbm/gal) was used for reliable functioning of the annulus pressure-operated DST tools after a hermetical test and heavy kill mud (15.7 lbm/gal) was used for the well kill operation. Deploying a full suite of annulus pressure-operated, multicycle DST string rated for HP/HT conditions permitted the testing of the well to be performed safely and efficiently without any breach to safety and service quality. The initial cleanup, three-bean study, and downhole buildup were successfully completed. Temperature recorded in this well at the 7-in. retrievable packer depth was 436°F, and the reservoir temperature was extrapolated to approximately 460°F. The reservoir was successfully tested with an annulus pressure-operated multicycle DST string designed to withstand the challenging HP/HT environment. The operation set a new global record, which is the highest recorded bottomhole temperature during DST using the service company's retrievable packer and multicycle DST tools.
Underbalanced drilling (UBD) is a method where equivalent circulating density (ECD) is kept less than the effective pore pressure of the zone being drilled by 100 psi or more. Drilling in an underbalanced state provides a unique opportunity to gather real-time virgin reservoir data that would never be observed again after typical damaging effects from conventional overbalanced drilling. This condition allows formation fluid to flow into the wellbore during the drilling process, helping prevent drilling mud and associated contaminants from penetrating the producing formation, which protects the producing zone and minimizes the potential for formation damage. Proper instrumentation and drilling procedures allow acquisition of data that is then interpreted and analyzed to extract information about the reservoir. UBD benefits include: Increased rates of penetration by up to 50%Increased value by producing hydrocarbons while drillingIncreased production rates mean quicker payoutsReduced formation damageReduced lost circulation costsReduced potential risks of differentially stuck pipe An operator in India was truly the first to implement UBD technology within depleted reservoir sections of identified wells in an offshore asset. Three wells were planned as a part of the project. Project objectives, feasibility studies to determine applicability of the UBD technology to the selected field, an operational summary, and results of UBD operations on the first well are discussed. Objectives for implementing UBD technology within the identified field included helping prevent reservoir damage, thereby enhancing oil production and recoverable reserves from the wells, and helping improve drilling performance within the reservoir section by eliminating mud losses, hence increasing lateral length and reservoir contact.
A leading exploration and production company in India needed to conduct high-pressure/high-temperature (HP/HT) testing on a deepwater well. Deployment of the drillstem test (DST) tools in a kill-weight mud system as a testing fluid could have resulted in challenges with tool operation and retrieval of the DST string at the end of the test. Appropriate kill-weight clear fluid was not available at the time of the project execution. This paper describes the method developed to achieve underbalance Drill Stem Testing in Deepwater KG offshore India. The data also describes careful preparation of the tool string for HP/HT environment and operation of DST tools in underbalance annulus brine. The well test was planned with the available low-density clear fluid system (brine). During pre-job planning, multiple DST tool combinations were considered before finally deploying a full-suite, multicycle DST tool string. The operation was designed to perform the DST with the underbalance testing fluid to test the reservoir potential and later to displace the kill-weight fluid into the well during well kill operations. Multicycle DST tools were deployed with a 7-in. retrievable packer, 3-in. subsea safety system, and 15K surface well testing equipment. The test string, featuring the multicycle DST tools, performed successfully with the available underbalance fluid (brine). The tools also operated as designed in the kill-weight mud, thereby meeting the defined test objectives. The testing operation was performed in a single run, reducing rig time and associated expenses to provide overall cost savings to the customer. Maximum bottomhole pressure and bottomhole temperature recorded was 11,000 psi and 365°F during this job. This was the first HP/HT underbalance well testing job carried out in a deepwater environment in India. This job provided the platform to perform similar underbalance well testing operations in a subsequent job on another deepwater well. Using the multicycle DST tool string, the customer was able to safely and effectively test the reservoir potential with an underbalanced test fluid in two deepwater wells, achieving the desired test objectives.
This paper describes the use of managed pressure drilling (MPD) and managed pressure cementing (MPC) technology on a high-pressure high-temperature (HP/HT) well in North-Eastern onshore, India by Oil and Natural Gas Corporation Ltd. (ONGC), a leading exploration and production company in India in collaboration with Halliburton, one of the major oilfield service providers globally. The bottom-hole temperature recorded in this well is 151°C and bottom-hole pressure of over 15,000psi at target depth. The MPD technology was utilized for drilling the well for the first time in ONGC. The near wild cat well was successfully drilled and cemented to a depth of 4,840 mMD and made history by tapping into Lower Bhuban and Barail sands for the first time, while successfully drilling in uncertain pore pressure environments, managing gas and water kicks, coping with loss zones, and identifying production zones together with pore pressure estimation. The well posed many challenges including uncertain pore pressures, highly unstable formations, likelihood of differential sticking and high-pressures/high-temperatures. The operator had attempted to drill the well conventionally in the past which had to be abandoned due to technical complications owing to high pore pressure gas and water sands as well as high differential pressure. MPD uses a closed-loop system that adds an increased level of environmental protection and allows for the use of an automated early kick detection system for increased safety. The automated MPD system was incorporated for the two well sections (12-1/4" and 8-1/2" hole sections) to provide control, flexibility, and safety required to drill and mitigate these risks. This implementation allowed to drill 2,013 meters (6,604 feet) in an extremely challenging zone in stable and safe conditions. The well was drilled to a target depth of 4,840 meters (15,880 feet). Deployment of an extensive MPD surface control system (along with rotating control device, fully automated choke manifold and back-pressure pump) allowed drilling and cementing of the well in a safe and efficient manner without any breach to safety and service quality. The MPD technology enabled ONGC to reduce the mud weight while drilling the well by balancing the formation pressure with application of additional SBP from surface using MPD choke manifold. This helped ONGC tackle the narrow drilling window along with early-kick management in HP/HT environment. The well was drilled to target depth of 4,840 mMD, making it the deepest drilled and cased hole in Tripura, Asset India. Major formation information on Lower Bhuban and Barail sands was obtained along with ascertaining zones of interest by allowing early detection of formation changes and hydrocarbon zones. The formation was non-drillable through conventional approach and implementation of MPD technology made it possible. The operation was carried out with extensive remote support from team in global and region considering pandemic situation.
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