To ascertain reserves and future development of low permeability formations drilled with oil-base mud (OBM) in a highly deviated offshore well, low contamination hydrocarbon samples were required. With limited sampling time allowed, due to historical stuck-tools cases within the same environment, different sampling technologies were appraised. Focused sampling was selected based on detailed near wellbore formation simulation. The sampling technique was successfully deployed, with a single tool string descent, in a complex 3D 6" slim wellbore (S-profile with 51 degrees inclination followed by a tangent, then a J-profile followed by another tangent). Different sampling techniques were attempted earlier to sample in the low permeability formation using various single probe sizes and inflatables, but none were successful to prove hydrocarbons, mainly due to the allowable sampling window, and tool sticking indicators that prevented longer cleanup duration. A rigorous pre-job near wellbore simulation modeling was performed to envisage varied scenarios and be prepared for contingencies. Sensitivities were run for thickness, kv/kh, sampling depth and permeability. Consequently, elongated focused probe sampling technique and straddle packer were selected. The inflatable straddle packer was kept as a contingency. Focused sampling has undergone dramatic changes over time by combining different probe sizes / types. This type of sampling technology uses the outer flow produced at a guard inlet to prevent mud filtrate from migrating into the sample inlet. Three sampling points were selected based on the pressure data. Despite the long tool string and harsh environment, samples were successfully collected. When compared to the previously drilled well within the same reservoirs, this is considered as a major achievement to secure samples which eventually proved oil and secured a license. Cleanup time varied between 2.0 hours and 3.5 hours, with 96 to 142 liters pumped volume. The inflatable straddle packer was not used. This saved more than 12 hours of rig time and secured risk-free samples with a smooth operation. Laboratory Analysis of the hydrocarbon collected samples indicated OBM filtrate contamination ranges between 3.0% and 5.0%. Pre-job near wellbore simulation proved to be a powerful tool to study sensitivities and extremes at sand face, which helped deploy the optimal sampling solution in a time constrained and mechanically challenging scenario. The post-job near wellbore simulation helped to fine tune some of the reservoir parameters such as thickness, which would be helpful for future applications. This was the first deployment of extended range probe focused sampling (elongated focused probe sampling) in the low permeability reservoirs in Malaysia and Petronas, and the same was successful. The risk of using inflatables in slim hole was avoided. The high-quality sampling was achieved in one tool string descent, allowing timely well completion and met the first oil timeline.

The scope of the paper is to share a case study of a successful horizontal well completed within an extremely thin oil rim of ~10ft with bottom water. This paper highlights the differentiating activities undertaken to deliver the well despite the challenges of extremely thin oil rim, strong water drive and uneven current fluid contacts. Prior to drilling this well, attempt was made to mitigate the uncertainty regarding the current gas-oil contact (GOC) and oil-water contact (OWC) by carrying out cased-hole logging in some of the adjacent wells, and re-sequencing and re-optimizing the location of two of the wells targeting the reservoirs below. This obviated the need for the pilot hole and thereby resulted in a cost saving of ~USD 1Million. Furthermore, the dynamic simulation model was updated to create a fit-for-purpose model with the latest OWC and GOC, so as to be able to test various trajectories. While drilling, the well was drilled with real-time reservoir mapping-while-drilling technology and integrated with real-time reservoir characterization, fluid typing and trajectory modification, while maintaining Dog Leg Severity (DLS) below 3 deg/100ft for the ease of completion run. Completion was then optimized with viscosity-based inflow control orifices. Post drilling, dynamic and well models were calibrated to the actual results to determine optimum production rate for the well life. The horizontal well was successfully navigated and optimally placed in the extremely thin oil column. Tilted contacts were encountered in the targeted subunits where actual current contacts came in ~20ft shallower at heel and ~10ft deeper at toe compared to prognosis. Consequently, the heel landed at a 5ft stand-off from water, and the toe landed 18ft stand-off from water and 6ft stand-off from gas. The well was successfully unloaded and tested at a controlled oil rate of 2887 bopd, 50% higher than planned target. This paper presents the entire process from well planning until well production tie-in. This was achieved through the integration of subsurface understanding with the utilization of the appropriate technology. Finally, the management's trust in the capability of the team members ensured deliverability of the target production rate and the consequent booked reserves.

To appraise hydrocarbon and its properties of a low permeability formation within deep Baram delta reservoirs. Formation X is low permeability silty sandstone. It forms along other formations stacked sandy shale reservoirs. The stacked formations are interpreted as Hydrocabon bearing formations based on the openhole and pressure data. However, the reservoir in question, showed features different from the adjacent reservoirs. This manuscript appraises the reservoir and illustrates the workflow followed to identify its fluid type and the best method to produce the hydrocarbon. Triple combo logs identified formation X as hydrocarbon bearing with low permeability and low porosity. Formation pressures gradients indicated the formation to be oil; however, the bottom hole sample, when pumped out, indicated alternating of oil and gas despite the low differential pressure. During the PVT measurement the sample was first re-pressurised until a single phase was achieved and it was then subjected to Differential Liberation and Constant Composition Experiments (CCE). These experiments showed the Bubble Point pressure of the sample to be higher than the reservoir pressure, thereby indicating two mobile phases in the reservoir and the probability of a Gas-Oil Contact (GOC). The Experiments were also successfully simulated and matched using the Peng Robinson Equation of State. The Laboratory experiments directly contradicted the interpretation of Wireline Logs and pressure gradient both of which, indicated single phase light oil. The collected bottom hole sample indicated that both oil and gas are mobile at reservoir level, this finding is supported by PVT laboratory experiments. The Differential Liberation, CCE experiments and EOS fitting demonstrated the fluid to be two Phases at Reservoir Condition where both phases are likely to be mobile. Therefore, it is suspected that the fluid will go from being Gas to Oil with increasing depth without going through GOC, i.e. with continuous compositional grading as is possible for fluids near their critical temperature. This phenomenon could not be captured using open hole conventional logs and therefore the is team is currently investigating the best practice to identify such reservoirs.

Originally, an infill well from project H was approved in 2013 to be completed as a single zone Open Hole Gravel Pack (OHGP) to produce gas commingled from three sands located at the shallowest reservoir in that field. Interpretation of recent logs from a nearby producing well indicated that there was significant water threat at two of the sands which would lead to water influx from the beginning of production if the well was to be completed as a single zone OHGP. The well was then redesigned to be completed as a Cased Hole Gravel Pack (CHGP) in order to have mechanical isolation from the water zones with an inner string and internal isolation packers to allow feasibility of zonal isolation to shut off the water producing zone in the future. This feature however resulted in higher well cost as compared to the approved design. Due to recent hostile low oil price, a more cost-effective sand control design was evaluated to reduce the well cost while maintaining similar performances as a CHGP design in terms of the capability to delay water breakthrough. Design feasibility study was performed on multizone OHGP with open hole mechanical packer and an inner string design to evaluate its performance and magnitude of cost reduction relative to a CHGP design. Skin analysis was performed for both OHGP and CHGP completion designs to evaluate any additional pressure loss for each sand. Prior to compartment optimization, an OHGP completion without packer placement was simulated in a dynamic simulation to generate the production profile as a base case. This was followed by a compartment optimization that was performed with OH mechanical packer placement at various standoff distances from the Gas-Water Contact (GWC) such as 5ft, 10ft, 15ft, 20ft and 30ft respectively. Subsequently, similar analysis was then performed on the CHGP completion design with a higher skin value estimated for the CHGP completion to reflect a higher degree of damage resulting from the cementing and perforation operations. Several production sensitivities were simulated by varying the perforation length and standoff from the GWC to replicate the same scenario of the open hole mechanical packer placement in the OHGP design analysis. Finally, analysis on the effectiveness of the base case (OHGP with no packer) against the cases of OHGP with optimum packer placement and CHGP with optimum perforation depth were compared and ranked over cumulative gas production, cumulative water production, operational complexity, and risk as well as total well cost. Based on the dynamic modelling, the base case (OHGP without packer) showed water breakthrough occurring right at the start of production as expected. Once breakthrough occured, water production would rapidly dominate production. On the other hand, packer placement sensitivity analysis for the OHGP design showed that the optimum depth for packer placement was 20ft or 30ft above the GWC depth where it provided highest gas cumulative and lowest water cumulative production throughout the well life. With offset distance of at least 20ft away from the GWC, the cumulative gas production for the OHGP and the CHGP cases were found to be similar and the cumulative water production for the OHGP case was slightly lower than the CHGP case. Mechanical open hole packer was recommended instead of swell packer after considering the risk of inadequate isolation by swellable packer that would lead to early water breakthrough which would subsequently reduce the cumulative gas production. As a result, an OHGP with open hole mechanical packer and inner string was selected to be the most optimum design for this well with estimated cost reduction of nearly 13% from a CHGP design. In general, an OHGP with OH mechanical packer at 20ft or 30ft standoff from the GWC brought benefit to the infill well in terms of cumulative gas production gain and low water production while eliminating sand production.

Based on the production data from first development campaign in 2017, contamination reading of CO2 and H2S from gas production wells were observed increasing from 3% to 10% and from 3ppm to 16ppm respectively within one year production. These findings have triggered the revisit in 2019 development campaign optimization strategy in terms of material selection, number of wells, reservoir targets, and completion design. Thus, tubing material was upgraded to HP1-13CR for the upper part of tubing up to 10,000 ft-MDDF (feet measure depth drilling rig floor) to avoid SSC risk due to the geostatic undisturbed temperature is less than 80 deg C, however the material of deeper tubing remains as 13CR-L80 as per 2017 campaign. Moreover, the mercury content from first campaign was observed to be above threshold limit from intermediate reservoir based on mercury mapping exercise done in August 2018.As the mercury removal system is not incorporated in the surface facilities, the mercury reading from the well in the 2019 campaign need a close monitoring during well testing so that appropriate action can be taken in case the recorded contaminant reading is high. Dedicated zonal sampling plan to be performed if the commingle zone (total) mercury reading was recorded to be above the threshold limit, and that zones will be shut off to preserve the surface facilities. Opportunity was grabbed to optimize number of wells by completing both shallow and intermediate sections in a single selective completion to maximize the project value. However, this combination will lead to major challenges during operation due to the huge difference in reservoir pressure and permeability contrast in each perforated reservoir as the required overbalanced pressure of completion brine for shallow reservoir is much lesser than the requirement for the mildly overpressure intermediate reservoir. Thus, a potential risk of severe losses and well control is present at shallow reservoir. To mitigate this risk, loss circulation material was pre-spotted in the TCP (Tubing conveyed perforation) BHA prior to fire the gun to allow for self-curing process should losses take place. During the first development campaign, the completion tubing was running in hole in two stages. The lower completion was deployed via drill pipe and the perforated zones was secured with fluid loss device located between lower completion tubing and gravel pack packer. The upper completion tubing was then deployed and tied back to the lower completion packer. This approach was applied as mitigation to prevent fluid losses and to ensure the tubing can be safely deployed to the intended final depth. However, based on the actual performance and losses rate data during the first campaign, the completion design in second campaign was optimized and deployed in single stage. Since shallow and intermediate reservoir were combined in multiple production zones where five SSD (Sliding Side Door) were installed, the slickline option to set packer was waived due to the risk of setting tubing plug in deep wells. Pump out plug was considered as an option but then dropped due to high hydrostatic pressure. The packer setting pressure was too close to plug shear pressure. Therefore, a self-disappearing plug was utilized as it did not require any slickline intervention and can be ruptured by pressure cycle. With this option, risk of pre-mature rupture of plug was eliminated. The paper will discuss in detail each challenge mentioned above together with details calculation that was performed throughout evaluation and selection processes prior best solution being selected as these optimizations resulted in nearly three days saving of rig time, contributing to 2.6% of well cost reduction and the required number of wells were optimized to be three instead of four wells. Moreover, a safer production life of wells by selecting a suitable tubing material and eliminating the risk of mercury production above the above threshold limit.