This paper proposes a method for solving mixed-integer nonlinear programming problems to achieve or approach the optimal solution by using modified genetic algorithms. The representation scheme covers both integer and real variables for solving mixed-integer nonlinear programming, nonlinear programming, and nonlinear integer programming. The repairing strategy, a secant method incorporated with a bisection method, plays an important role in converting infeasible chromosomes to feasible chromosomes at the constraint boundary. To prevent premature convergence, the appropriate diversity of the structures in the population must be controlled. A cross-generational probabilistic survival selection method (CPSS) is modified for real number representation corresponding to the representation scheme. The efficiency of the proposed method was validated with several numerical test problems and showed good agreement.

The Nong Yao field is a marginal oil field that presents many challenges, both geological (thin hydrocarbon column and structural uncertainty due to shallow gas effects) and with well design (shallow depth and unconsolidated reservoirs). The field has been on production for almost five years with water cut in most wells now over 90%. The key to extending field life is identifying new infill locations, with advanced technology required to identify and drill these targets. To improve seismic image and structural definition, the seismic data was reprocessed in 2016, utilizing the latest technologies including Broadband Processing and Full Waveform Inversion. This detected local unswept structures and thin reservoirs allowing for identification of infill targets. New generation hydrocarbon saturation cased hole logs were run in wells to identify swept versus bypassed oil areas. Many infill opportunities required complex 3-D well trajectories and innovative completions. To achieve these objectives, technology such as high build rate rotary steerable systems, advanced real time survey corrections, a multilayer bed boundary detection tool, rotational friction transducer and inflow control devices were implemented. After four years of production, a key well exhibited significantly more production than expected, indicating a much larger reservoir than modelled. However, water cut in this well had reached 98%, so infill wells were required in order to extend production. The reprocessed seismic indicated that the structure extended further to the east of the existing producer than initially modelled. A cased hole saturation log was acquired in an existing well drilled near the planned landing location, which showed that the reservoir was actually swept in this area. Instead, the infill well was landed and drilled in the opposite direction in this eastern part of the structure, keeping the heel away from the water, but providing a much more challenging well path. A high-build rate rotary steerable system, advanced real time survey correction and rotational friction transducer were used to safely deliver this complex 3-D well profile and avoid collision risk from offset wells. The multilayer bed boundary detection tool was then used to ensure the horizontal well stayed as high as possible whilst remaining within the reservoir. Lastly, an inflow control device was installed in the horizontal section to delay water production. The well came online with 0% water cut and is an excellent producer. Similar methods have been adopted at other locations to identify and drill infill targets with great success. Collaboration across disciplines is key, as input is required from the geologist, geophysicist, petrophysicist, reservoir engineer, drilling engineer and completion engineer to identify, drill and produce these infill targets. Implementation of this approach continues to add new volumes and extend field life.

This paper describes the successful application of Autonomous Inflow Control Device (AICD) technology in the Nong Yao oil field located in Block G11/48 within the Gulf of Thailand. Water injection in the Nong Yao field, is often into unconsolidated sands drained at different depletion levels. This can lead to formation failure and the transportation of sand back through the annulus and tubing. This AICD bypass valve technology provides a solution by only allowing injected water into the formation but not in the opposite direction hence preventing downhole crossflow. An AICD Bypass Valve was installed into two injection wells that were completed as Multi Zone Completions (MZC). It was planned that multiple zones would be opened simultaneously to provide ongoing waterflood support. The expectation was that the AICD technology would prevent crossflow between zones, due to pressure difference during any injection shutdowns, thereby eliminating the chance of formation failure and transportation of sand from the reservoir into the annulus and tubing. At first, these reservoirs were produced through depletion, and waterflood of these reservoirs did not commence until reservoir pressures had reached between 5.5–7.0 ppg. This led to differential depletion across these reservoirs, hence increasing the risk of downhole crossflow immediately upon any injection shut down, which may come with sand production resulting injectivity impairment. This has been observed across other wells in the field not fitted with AICD Bypass Valves. The concept of the AICD Bypass Valve is that the device requires a positive injection pressure differential to activate and open and allow fluid to pass through and it will close if the well is shut in due to a drop in the required pressure for valve activation. Since the installation of AICD Bypass Valves, these wells have been shut in multiple times due to platform shutdowns for rig mobilization and each time no drop in injectivity has been observed on restart, and sand production has been observed as predicted. AICD Bypass Valves were installed into two new injection wells in the Nong Yao field, providing a low cost alternative to recompletion or redrill that may be required, if screens become plugged due to sand production triggered by crossflow between reservoirs during well shut-in. This has provided more reliable production for the field and the success in this project means that more AICD Bypass Valves will be planned for future MZC, for injection wells in unconsolidated sand.

This paper describes a collaborative analytical technique employed by a team of subsurface, production and facilities engineering members on improving production allocation in a mature field producing at a high water cut. The field production allocation deteriorated sharply from 2015 when a field water cut was beyond 90%. The paper describes the entire workflow starting with problem identification, preliminary investigation, key actions taken, and collaborative analytical techniques utilized and proposed solutions to improve production allocation. The team conducted a primary investigation using several key investigative techniques and the result led to the identification of two main focus areas to resolve the production allocation issue; a) Improving the existing production allocation method, and b) Improving the current well-test measurement procedure. The team developed collaborative analytical techniques including fit-for-purpose mathematical modelling, specific design for field experiments and advance nodal analysis, which used as a means of identifying the potential root causes in well-test measurement procedure. Following primary investigations, the allocation methodology was updated to include the export meter oil volume readings as an extra step in the allocation algorithm. This helped removing the impact of physical conditions (e.g. weather) from the variations of tank dip measurements. Following implementation in July 2017, results indicated a clear improvement on allocation factors up to 26% on two platforms. Unfortunately, the remaining platforms barely showed any improvement. This was in line with preliminary findings that had identified these platforms as contributing the most to the overall field allocation factor deterioration. On the well-test measurement procedure, the result of collaborative analytical techniques concluded that the current Basic Sediment and Water (BSW) measurement by centrifuge method being deployed in the field was acceptable for crude with a low water content, while it tended to underestimate BSW in wells producing at relatively higher water cuts. With this realization, correction factors were developed and recommended to be applied to the measured BSW to mitigate the measurement uncertainty. The applied correction factors were found to better reflect the actual oil rate from the wells and better match the oil volume measured at platform export meters. The result showed immediate improvements the overall field allocation factor by up to 21%. This collaborative analytical technique to improve production allocation was uniquely developed for a mature oil field producing with extremely high water cut and located offshore in the Gulf of Thailand. Although the collaborative analytical techniques consisted of fit-for-purpose mathematical modelling, specifically designed for the field in question and adaptive approach of nodal analysis, the methods can easily be replicated to other fields, with a number of simply quantifiable potential benefits.

The multiple challenges associated with a large scale offshore water disposal project are set out in this paper, which goes on to describe how these challenges have been overcome using an integrated multi-disciplinary approach that optimizes disposal well performance, while at the same time significantly reducing the OPEX associated with produced water handling. The difficulties associated with maintaining injectivity in the disposal wells have been overcome through a combination of strategies, including targeting alternative aquifer intervals, which lie above existing oil-producing zones, modifying the completion design, improving the water treatment process and implementing topside modifications. A comprehensive surveillance program has also been implemented to ensure that well and flowline integrity is maintained, and to understand the distribution of injection between the aquifers. A key outcome of this project has been to scale back the requirement for high pressure water disposal (HPWD). The resulting low pressure water disposal (LPWD) strategy has achieved a cost saving of approximately $0.5 per barrel of oil produced which is highly significant in the prevailing low oil price environment.