The original lower completion strategy for the 13 oil producer wells in X Field was open hole standalone screens (OHSAS). The lower completion string comprised 6⅝-in. premium mesh screens inside the 8½-in. open hole. On the basis of updated predrill well data, stakeholders decided to change the well design to a cased hole gravel pack (CHGP). This paper discusses the feasibility study that was conducted to switch the design, the justification used to maintain the original strategy but with an increased use of swell packers for better compartmentalization in the OHSAS design, and the production results of the completed wells. Based on the most-recent data, maintaining the original design would increase the risk of water breakthrough and subsequently lead to a loss of production. Furthermore, all past campaigns in X Field were completions with CHGPs. To address these concerns, additional studies were performed to evaluate the potential of using the existing inventory combined with the concept of mounting shunt tubes onto the 6⅝-in. mesh screens for CHGP and to evaluate increasing the quantity of swell packers using different swelling materials for OHSAS completions. The assumption was that with a sufficient number of swell packers placed in the open hole with the sand screens, which would create a higher differential pressure, zonal isolation could be achieved in an open hole similar to the effect of having a bypass barrier in a cemented cased hole completion. Studies have showed that installing shunt tubes for 6⅝-in. screens for CHGP poses additional risks because of the tight clearance inside 9⅝-in. casing, and they can only be mounted with two shunt tubes. Isolation between zones is achieved by means of multizone shunted cup packers. However, as a result of the long lead procurement time for the multizone shunted cup packers, this option requires expediting to meet the project timeline. However, simulations performed on the enhanced OHSAS design using an increased number of swell packers became a promising solution to overcome the water breakthrough problem. The challenges were to determine the optimal quantity of swell packers required and the precise placement along the open hole. Other challenges are increasing drag effect on high dogleg well to accommodate the large quantity of swell packers. Sensitivity analysis of swell packer quantity had been run and compare with existing successful track record to further optimize the completion design. To meet the budget and schedule for the campaign, OHSASs with swell packers were successfully installed in Q4 2021 to isolate the water contact zone in the first three wells. Additional swell packers and short screens were used to mitigate the water-production risk and enable the completion and isolation of thin zones. Well unloading was performed immediately following the completions, with positive results in terms of water production in two of the three wells. The production performance of these three wells will be evaluated to determine the sand-control design strategy for the remaining wells on the next platform in Q3 2023.

Sustained casing pressure (SCP) is a very costly event for any operator either at production phase or at the end of a well’s lifecycle. SCP is a result of incomplete hydraulic isolation across hydrocarbon bearing zone. In one of the gas fields in Malaysia, notoriously known for shallow gas hazard, drilled development wells which have reportedly been suffering SCP. In the past, various improvements in cement slurry design and placement methods were deployed in order to provide complete zonal isolation, especially at the shallow gas sand, yet SCP issue was encountered occasionally. In the current development campaign, different strategy to providing annulus sealing was adopted. This paper discusses proactive steps taken in the slurry design, fit together with the dual stage cementing approach, as a primary means of placing cement above the shallow hazard interval. During the design phase, essential key parameters that would lead to successful placement of cement in the annulus as well as unique slurry design that suits for two stage cementing methods were studied. Risk involved in first stage cementing is one of the most important steps that should be analyzed in detail and put mitigation measures in place to ensure the second stage cement job can be performed as planned. In addition to the slurry properties, such as fluid-loss value, gas-tightness, etc., thickening time and top of cement (TOC) of the lead slurry in the first stage cement job has become enormously critical in designing dual stage cementing job in order to assure cement ports in the stage collar are not covered with hard cement forcing the termination of second stage job prematurely. Besides cementing design, careful selection of the stage collar location and casing annulus packer in the string is also of significant importance in leading to successful two stage cement job. Two development wells with above approached has been delivered and no sustained casing pressure has been experienced. This proactive approach to use two stage cementing as primary plan has proven to successfully eliminate the risk of SCP, which was a frequent struggle in their sister wells drilled with primary cementing in the past in the same field. The risk analysis combined with careful considerations of critical cementing design parameters and selection of stage tool location have become a novel approach to combat against SCP in this gas field.

Exploration well with carbonate reservoir is a challenging well to plan for due to risk of total losses because of karst presence. It became even more challenging for a subsea well with high bottom hole temperature (BHT) and prospect of well testing. Flow of HT reservoir fluids (BHT up to 175 deg C) to surface will resulted in significant heat transfer to adjacent casing & its annulus fluids, and lead to annular pressure build-up (APB). High APB will lead to loss of well integrity via 13-3/8" intermediate casing burst and 9-7/8" production casing collapse if left unmitigated. As per The Company technical standards, two APB mitigations were required in a subsea well. The first selected mitigation is an open casing shoe. The exposed shoe will act as a natural relief valve whenever APB exceeding its fracture pressure (FP), therefore, limit the APB to its FP. However, it is challenging to keep the 9-7/8" casing top of cement (TOC) below the 13-3/8" casing shoe and fulfil the open shoe barrier requirement for this well where the open hole interval is relatively short and subject to be plugged off by barite sagging, insufficient open shoe length for safety margin of excess cement and requirement of minimum annulus cement length for shoe integrity. Extra mitigations were addressed through extensive lab tested solids-free annulus fluid to mitigate barite sagging. Open shoe interval also designed with multiple weak sands exposure and higher FP were considered for worst-case APB simulation. The second barrier is the 13-3/8" intermediate casing and 9-7/8" production casing itself. Based on WellCAT simulation, the intermediate casing unable to meet The Company standards of burst (safety factor, SF < 1.1) in the worst-case scenario whereby APB is unmitigated. The casing burst pressure rating was recalculated using API Bulletin 5C3 equation with the inputs taken from minimum actual casing wall thickness measurement and internal yield pressure from its mill certificate. Technical derogations were raised and approved once the casing passed all the load cases using the revised burst rating by minimum SF of 1.0. The well was delivered successfully with the open hole barrier for both casing was executed flawlessly despite the complex fluid train while cementing.

This paper describes the application of key technique for splitter wellhead cementing of top-hole section in conductor-sharing wells in dozens of development wells in offshore Malaysia. Its objective is to elaborate on the challenges faced during the well planning phase, methodology of cementing technique, cementing slurry design as well as solutions outcome and lessons learnt. Limitations of current software in the industry to simulate the conductor-sharing well cementation and approaches to maneuver through these limitations are also discussed. During the well planning phase, cementing technique to address the risks associated with splitter wellhead cementing such as accidental cementation of dummy string, poor cement coverage in shared conductor, and losses uncertainties were analyzed. The cementing execution results of first batch of wells are examined, i.e. pressure profile, cement returns as well as opportunities for improvement were documented and translated into recommendations leading to eventual success for future well design. The cement slurry design for each casing in the splitter wellhead are also established based on its associated job objectives which is based on the unique approach in splitter wellhead cementing. The establishment of key cementing technique for such an unconventional well construction technology is important in order to ensure continuous success both in cement placement as well as cement slurry design. The best practices are currently being replicated by other major operators in Malaysia for all splitter wellhead cement design. The learnings from the technique are incorporated into the technical standard of Malaysia operator as well to serve as a specific mandated requirement for future operations. An integrated study of wellhead design, drilling practices and cementing technologies enabled a novel methodology to assure long term zonal isolation for the wells and innovation in the cementing approach enable cost savings for the operator as the wells can be drilled in a safe, efficient and cheaper way.

Infill well drilling was planned and executed to increase production in a significantly depleted field. A total of 3 infill wells were drilled in 2 different layers of reservoir for an offshore operator in Myanmar. In the offset wells, water production had become significantly higher throughout. Previously all offset wells in this field were completed with open hole sand screens was chosen to isolate the water bearing sand in the sand reservoir below. Pore pressure prognosis were calculated from offset well depletion rate. Reservoir formation properties is assumed to be same throughout the field. The first well was drilled and was found that there were two gas water contacts through the 3 targeted sand layers. The gas water contact and WUT (Water Up To) in this well were unexpected and it was prognosed that these gas water contact are there due to compartmentalization. The 7" liner were set and cemented throughout these reservoirs. The cement job went as per the plan and there were no losses recorded during cementing. However, initial cement log did not show isolation. 2 more runs of cement log were performed 6 days and 10 days later while conducting intervention activities on other wells. All three cement log came to the same conclusion, showing no isolation throughout the annulus of the 7" production liner. Significant amount of gas had percolated into the annulus over time. Despite no evidence of poor cement slurry design observed during running various sensitivity studies and post-job lab tests final cement log, which was conducted under pressure and confirmed no hydraulic isolation. A cement remedial job was planned and an investigation was conducted to identify the plausible root causes. This paper explains on the root causes of poor cement presence in the annulus, and the remedial work that took place to rectify the issue.