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.

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.

A total of 5 production wells were planned in a gas field development project located in offshore Sarawak, Malaysia. The reservoir section of the field is comprised of two massive pinnacle carbonate structures, characterized by heterogeneous porosity and permeability, with high occurrence of vugs and faults. Severe to total loss circulation was expected while drilling this reservoir coupled with high temperature environment with prognosed bottomhole temperature (BHT) of 370°F. Considering the high risk of loss circulation, the drilling fluids strategy involved designing and testing of a high temperature tolerant Water Based Mud (WBM) system as a base case plan to drill the reservoir in the scenario of sustainable losses. The HT WBM system was designed using HT polymers for filtration control and viscosity. The fluid was stressed at 370°F and prepared at a density of 14.5 lb/gal (1.74 SG). The high density mud system prompted the requirement to control the rheology for improved ECD management while drilling the reservoir section. Other criterias for the fluids design were the ability to demonstrate low barite sagging tendencies at extended static aging time as well as improved HTHP filtration control. The final formulation was also subjected to a formation damage testing to evaluate the fluids impact towards reservoir impairment. The HT WBM system was a milestone for the operator as being the hottest HT WBM ever deployed in Malaysia operation. High geological uncertainties in the area led towards unexpected long shale exposure while drilling the reservoir section in both mainbore and sidetrack wells. While the mainhole was drilled successfully with the HT WBM system, the sidetracked well experienced significant reduction in the rate of penetration (ROP), suspected from bit balling despite having additional inhibition material in the system. The field observations, prompted additional learnings towards improvement of the HT WBM formulation as well as recommended lab testing considerations to further evaluate the performance of the mud system.

Coring and core analysis are considered the only direct and physical data to provide a true reflect to the reservoir properties. The measured properties are used to calibrate subsurface models and ensures close to reality properties. Representative data is critical to allow achieving such target. Coring planning and close follow up from the day decision is taken to core is important to achieve representative data. The approach followed in this manuscript allowed a high probability of successful core cutting, and representative core analysis. Field A is planned for appraisal phase and reservoir is expected to be of low permeability with sequence of shaly sands which adds complications to achieve the objective in cutting and analyzing the core. Different coring technologies were evaluated against the main coring objective of potential hydraulic fracturing field development. Conventional core is selected to offer the best value in both cost, and data coverage in compare to sidewall core. However, due to financial impact only one run was allowed, consequently it was critical to get the highest possible recovery and highest quality in one shot. An extensive planning phase investigated all variables to ensure high recovery. Rock strength and its mechanical properties allowed the selection of optimum coring parameters, coring accessories, and coring bit. It is critical to the project to collect the core and the added challenge of only single run required detailed workflow. Borehole size, mud wt, rate of coring and coring parameters were challenging due to the given one time opportunity. As a result, successful 100% core recovery is achieved, core retrieval to surface ensuring least core damage, this is demonstrated by CT scan which indicated no tripping out induced fractures. Well site core preservation reduced any weathering alteration, the selected stabilization method allowed minimal invasive to the core. Electrofacies guided by the whole core CT scans allowed the best coverage to the reservoir's properties. Long and large diameter plugs were achieved. Cleaning pilot study facilitated the selection of least damaging cleaning and drying method. Pilot small core analysis programs, and close follow up, and the analysis of raw data reduced the risk of unrepresentative core analysis results. Conventional core analysis data allowed refining and enhancing premeasurement electro facies and allowed a distinctive rock typing. The detailed planning permitted us to secure 100% core recovery and ensured core is reached the surface with least possible damage. The followed core analysis strategy reduced redundant experiments and allowed representative results at the same time optimized on the cost. This paper demonstrates the best practice that is followed in challenging environment of shaly sand sequences to successfully cut core and develop a program, and workflow which reflects the uncertainties to be solved.