This paper provides an overview of an engineering design methodology which uses a tubular design analysis validation software program that provides an analytical method for assessing tubing loads, design integrity, and buckling behavior under complex mechanical, fluid-pressure, and thermal-loading conditions. The design methodology is applied to complex wells (e.g., multizone, multistring completions, and intelligent completions). Tubing load evaluation cases for different operating phases are presented for two complex completion types viz. Intelligent Completion and Mutlizone Dual Completion. Two (2) well study models are presented for discussion and evaluation of thermal and stress-loading analysis: the first model analyses a dual string completion, and the second model analyses an intelligent well completion. Thermal simulation is first performed followed by tubular stress modeling for tubular selection and design. Well models are focused to present tubing-design integrity analysis for multistring and intelligent completions with various anticipated operating loads during the life of the well. Analysis includes scenarios for simultaneous production/injection, commingled zonal flow control with multiposition interval control valves (ICV), and various other well-operating conditions. Results show temperature/pressure changes for each simulated load scenario in the modeled wells. Also discussed are the impacts of well-operating temperature and pressure change on tubular axial loading, burst and collapse limitations, pipe movement and buckling potential, and resultant forces on completion packers in a multistring (dual completion) caused by tubular stress loading. Furthermore, tubular thermal and stress analysis is discussed for a multizone commingling intelligent well completion having multiposition ICVs with varying flow/injection rates. Results of thermal and stress modeling are evaluated to select and optimize the well completion design as well as identify well operating limits with respect to a set of combined ICV opening positions during commingled well operations. Dynamic and complex offshore conditions can cause variations in operating temperatures and pressures in multistring and intelligent well completions in which design margins are slim because of production-casing diameter limitations. A detailed stress-loading analysis aided by thermal- and stress-analysis software provides methods for balancing completion design vs. risk. This process provides savings by optimizing well design to meet design integrity standards without being overdesigned.

Wells 1A, 2A, 3A & 4A are designed as four (4) horizontal oil producers to maximize the oil recovery from the XXYY heterogenous sandstone reservoir in Offshore Malaysia. The reservoir has been producing since 1975 on natural depletion before gas injection (1994) and water injection (2019-2022) were introduced. XXYY reservoir is expected to have wide permeabilities ranges from as low as 1-mD to 4-D and high uncertainty of gas-oil contacts from recent saturation logging acquisition. Coupled with the complex reservoir nature of massive gas cap and thinning oil rim observed between 30-50ft-TVD, historical production of oil with optimum GOR in XXYY reservoir remained the main challenge towards late field life. For such challenging condition, pre-planning with multiple Autonomous Inflow Control Device (AICD) valve placement scenarios across the horizontal sections were analyzed using integration of reservoir and well models for valves optimization process to achieve well's target production and reserves by the end of PSC. Specific drawdown and production targets were set as critical design limits in managing sanding and erosional risks while still achieving production target. Ultimately, these models provided both instantaneous and long-term forecasts of AICD impact on the wells’ performance – key factors in the final design. The workflow presented in this project synergized scope of multi-domain from subsurface, completion and drilling. This case study demonstrates the value of detailed design steps on AICD placement across horizontal segments and optimizations based on actual open-hole logging interpretation, mainly – permeability, saturation and vertical stand-offs from gas-oil and oil-water contacts. The horizontal wells drilled are susceptible to "heel-toe" effect, resulting in dominant production in the heel section while the toe section contributes less, subsequently inducing gas coning at the heel. XXYY reservoir is also sand prone and requires sand control. For these reasons, all 4 wells are designed to be completed with Open Hole Stand Alone Screen (OHSAS) with the use of AICD to balance production withdrawal across the horizontal segments and provide GOR control. The four (4) wells penetrated 30-60ft-TVD of oil column with 10-15ft-TVD vertical stand-offs from gas-oil contact (GOC) to maintain a 2/3 column ratio from oil-water contact. Given these marginal stand-offs to GOC, integration of AICD sensitivities workflow were performed on-the-fly to analyze instantaneous and time-stepped oil and GOR rates allowing the team to achieve required production sustenance. The installations of optimized AICD have resulted in successful GOR control below 6 Mscf/stb targeted, resulting in delivering higher instantaneous production rates against planned of 4,600bopd. The success of AICD optimizations integrated with OHSAS completion, reservoir mapping and petrophysical evaluation have been proven as ultimate solution to deliver the wells oil production for a brown field rejuvenation project. The pre-drill and post-drill results calibrated to actual well tests are compared for further sensitivity analysis, to be used in the continuous improvement of production management strategies in the field.

The ‘B’ Field is located about 40 KM, offshore Sarawak and was discovered in 1967 with 70-80 m water depth. Structurally, ‘B’ field is charaterised by a simple relatively flat, low-relief domal anticline which is bounded to the north and south by the north-hading growth faults. The major faults are acted as effective lateral seal, which is indicated by the difference in the fluid type and fluid contacts across those faults. ‘B’ field consist of multiple hetereogenous sandstone reservoirs with permeability and porosity ranging from 25 −1700 mD and 16 −29% respectively. ‘B’ Field injectivity conformance for reservoir pressure support is very crucial as the field is undergoing severe depletions over years and unable to meet the production target. The Operator realized the importance in order to further increase the recovery factor, hence has included ‘B’ field in the Improved Oil Recovery (IOR) project to boost the production and prolong ‘B'field's life. Based on comprehensive IOR/EOR screening study, water injection process has been identified as the most amenable IOR process in ‘B'field. Hence, in Phase 1 drilling campaign, two (2) water injectors were drilled in 2016 in order to achieve the target oil recovery. Both well BWI-01 and BWI-02 were completed with Intelligent completions (IC) and expected to come online in Q4 2018. This paper further discusses the injection strategy in ‘B’ field multi-zones to meet the zonal injectivity and reservoir zonal voidage replacement requirement for pressure maintenance over field production life. The discussion covers the reservoir characteristics and zonal injectivity challenges with surface constraints that require intelligent completions solution for IOR phase. Completions architecture and customized metallurgy needs is crucial to meet operational challenges. Fit-for-purpose and maintaning development cost is pre-requisite to achieve well injection performance for optimal production

Open Hole Stand-Alone-Screen (OHSAS) design have been used in the oil & gas industries to monetize unconsolidated reservoirs. Design steps includes optimum screen selection, drill in fluid & breaker design, running in hole procedures, bean up plan & post tie in monitoring. This paper will discuss in detail on overall strategy implemented during OHSAS deployment in Field A, involving 4 horizontal oil wells in AABB reservoir & its post-production results. OHSAS is selected based on sonic travel time info showing >90usec/ft, Unconfined Compressive Strength (UCS) value ranging from 3000-5000psi & historical sand production. History from offset wells completed with pre-perforated liners, suggested 8 out of 9 wells had history of sand production once producing with high water cut. Screen selections was design based on Particle Size Distribution (PSD) data performed through Laser Particle Size Analysis (LPSA) & Sieve Analysis using samples from conventional & side wall cores. Several samples were then selected to execute the sand retention test (SRT) on different screen sizes & types. Screen placements across the horizontal open hole was designed into segmented zones with swell packer & Autonomous Inflow Control Device (AICD) were used to balance flow contributions along the horizontal sections and GOR control. Modelling work was performed to decide on well segmentation, sensitivity on rates, pressure drop across completion and erosional risks assessments. Selection of drill in fluid & breaker fluid system were designed to ensure the horizontal segment can be drilled effectively with optimum bridging, less susceptible to formation damage & screen plugging. Lab tests conducted to facilitate selections for all wells were production screen test, Permeability Plugging Test & Return Permeability Testing using core samples. OHSAS deployments were strategized to avoid stuck risks associated through dog leg severity management, torque & drag analysis with deployment of optimum centralizer placements to reduce dragged & placement of optimum number of swell packers. Optimization on lower completion were performed based on actual logging resu lts to improve overall well performance through isolation of shaly or gassy segment using blanks, use of tandem swell packer in gas segment & use of optimum AICD valve numbers. Post completion, specific bean up program was followed to ensure natural sand packing is properly established in the annular space between screen face and the open hole segment within allowable drawdown. Real time monitoring on flowing parameters especially bottomhole pressure through PDG & sand rate (if any) were performed during well tests. Multi rate test & Pressure build up (PBU) test verified that all 4 wells were able to meet at least 20% higher production rates than plan, with no major sand productions produced at surface. The holistic approach outlined in this paper is important in achieving long lasting application of OHSAS in unconsolidated reservoir right from design to production phase.