Uncontrolled sand production has caused serious complication and monetary loss in oil and gas assets worldwide especially in mature fields. It is known to be drastically limiting the production rates and damaging downhole and surface equipment, inducing the risk of catastrophic failure. Sand production is commonly associated with contributing factors such as unconsolidated formation, initiation of water breakthrough and changes in rock stresses due to depleted reservoir pressure. To mitigate sand production, operators often opt for applying mechanical or chemical downhole sand control methods. This paper will discuss about the performance results and lessons learnt from the application of chemical treatment for downhole sand control over several mature fields in Malaysia. Chemical sand consolidation (SCON) and sand agglomeration have been identified as effective chemical treatment to control sand production downhole. Both treatments involve injection of chemical into immediate near wellbore area of the reservoir with the aim to improve the strength of the incompetent formation and thus reducing the tendency for sand production. In most cases, SCON treatment consists of injecting fluid containing adhesive or resin for binding the sand grains while the main mechanism of sand agglomeration involves increasing the attraction between sand particles through processes such as polymer bridging interactions and charge neutralization. Stringent candidate screening and detailed pre-job planning are crucial in ensuring the success of both SCON and sand agglomeration treatment. Over the past few decades, there were about 20 SCON treatment jobs and 3 sand agglomeration jobs were performed across several Malaysia fields with varying service providers and chemicals. The overall success rates for sand consolidation and sand agglomeration are 75% and 66% respectively. To evaluate the effectiveness of the chemical treatment for downhole sand control, analysis was conducted to study the effects of parameters such as completion type, perforation length, formation permeability, clay content, well preparation, formation temperature and placement methods. This paper presents lesson leamt and best practice from several chemical SCON and sand agglomeration treatments performed over mature fields in Malaysia. Case studies for several wells will be examined to highlight the lesson learnt which are essential to further enhance the success of chemical SCON and agglomeration treatment. Best practice shall be incorporated into future campaigns to ensure chemical treatment as a successful means to control sand production downhole in a low-cost environment.

Many small oilfields in poorly sorted and highly non-uniform unconsolidated formations with high fines content cannot be developed economically using the preferred sand control method, gravel pack. ‘J’ Field in Malaysia is a small oilfield with marginal economics that was developed successfully using stand-alone screen (SAS), a cost-effective open hole (OH) sand control method. Deployment of SAS in ‘J’ Field does not meet the industry-accepted criteria for sand control methods but provided the operator adequate sand control while fulfilling its economic needs. Recent advances in OH sandface completion technologies such as multi-layer mesh screens, inflow control devices (ICDs), and zonal isolation using swellable packers provided improved performance and reliability of recent SAS installations. This project marks a few firsts in sand control screen technology: World's first installation of multi-layer mesh screenMulti-layer mesh screen is the current state-of-the-art in premium mesh screen technology. It uses several layers of woven metal mesh filters of gradually decreasing micron rating and diffusion-bonded together, which creates a filter that provides better plugging resistance and solids retention capacity.Malaysia's first installation of tube-type ICDICDs are passive flow control devices that are used in OH horizontal (Hz) wells to delay the onset of water breakthrough and minimize its effect by balancing inflow from toe to heel or between high-perm and low-perm zones. ICDs are integrated with sand control screens for use in unconsolidated formations. Swellable packers are used in ICD completions to provide compartmentalization. This paper highlights the recent success of utilization of these cost-effective OH sandface completion technologies in the development of ‘J’ Field.

Formation sand production is a major concern in brown field operations, especially as the field depletes and water production commences. There are many methods to control sand production in primary well completion; however, it becomes more challenging in producers where no primary sand control is installed initially, and it starts producing sand later in the well life. Selecting the right method for remediating these wells has become a hot topic with both Operators and Service Providers alike striving to discover effective and economical solutions for their brown-field operations. Currently, the solutions for through-tubing sand control in existing producers are screen hang-offs, through-tubing gravel packing1 (TTGP) and chemical sand consolidation. Through-tubing sand screen (TTSS) hang-offs above the producing zone, is an inexpensive sand control method. Unfortunately, these installations are typically short lived, often requiring regular well interventions due to screen plugging or erosion, or sand clean-out operations to remove sand accumulated in the production tubing. Alternatively, TTGP is a robust method to control sand production; however, more equipment is required to deploy the gravel pack which subsequently increases costs significantly in offshore applications. To simplify TTGP and make it economical, a major Interventions Service Provider devised a methodology to install TTGPs utilizing Slickine that reduces the overall installation cost tremendously. The methodology has been proven a great success in the US Gulf of Mexico where over 1,200 applications have been installed. The pilot implementation of slickline deployed through-tubing gravel pack (SL-TTGP) was executed in three S-Field wells in late 2018 which were shut-in due to higher than permissible sand production. These were challenging intervals in that they were uphole recompletions between cement packers in dual string 9-5/8" casing which had produced sand. The results from the installation proved that the methodology provides effective sand control and enables reinstatement of production from these wells. Further, the installations were achieved with lesser resources and at lower costs; less than half that of a CTU deployed TTGP. This success has led to further installations in the following year. This paper presents in detail the case study of the pilot implementation of SL-TTGP, key successes, as well as critical lessons learnt during execution and production phase. It includes the challenges, risks and their recommended mitigation plans, as well as the well performance comparison before and after the implementation both in terms of production and sand count.

In this paper, the authors will discuss a systematic approach to digitalize field surveillance and identify Production Enhancement (PE) opportunities by incorporating dynamic Well Operating Envelopes (WOE). The approach considers multiple components of the producing well's technical restrictions and constraints such as reservoir management, downhole completions, tubing/piping erosion and surface production facility. It is always a challenge to operate production wells daily as it involves multiple factors such as reservoir depletion, formation damage, and/or aging equipment. The failure of not being able to recognize and control well production behaviors may lead the producers unable to meet production targets and other severe issues like well integrity. In the oil and gas industry, well performance management is a vital component of optimizing production systems. Hence, WOE must be accurately defined to maintain asset integrity as well as reasonable production forecasts from available resources. The digital solutions include the development of prescriptive model-based technical workflows that employs a visualization tool to graphically represent the WOE with integrated performance dashboards to enable informed and optimal decision making. The solution leverages traditional petroleum engineering analyses and continuously enriched lookback knowledge base workflow combined with proven business logic to automatically and autonomously: Identify underperforming wells through their performance signatures.Check the quality of multi-disciplinary input data and engineering models integrated with a digital ecosystem to ensure the back-end solution engine can generate valued information for actionable recommendations.Predict potential concerns to ensure the producers are functioning in a safe and stable manner.Determine root causes and recommend appropriate remedial actions/opportunities to optimize production performance.Probabilistically quantify production gain, evaluate economic viability, and estimate the chance of success. This method has been used in several fields and wells with various completion types and field-wide constraints, and it has proven to be flexible enough to accommodate the possible differences between well types and field peculiarities. The case study presented in this paper will demonstrate some of the benefits realized including improved reservoir management and optimization opportunities identified (i.e. flowline pressure debottlenecks, reservoir stimulation, gaslift valve change, well bean-up, behind casing opportunity, etc.). In addition, the visualization tool has been used for exception-based surveillance (EBS), which has proven to improve our response time resulting in better deferment management. Furthermore, the visualization tool has been used to carry out exception-based well surveillance that has proven to improve our response time on well deviations for better deferment management. The collaborative approach between Operator and Solution Partner has enabled digitalization of field surveillance and PE candidate identification for an effective and efficient Reservoir, Well and Facility Management (RWFM) to protect the base production and maximize asset value within the safe limits on a day-to-day basis.

Carbon emissions due to oil and gas exploration and production activities remains significant. In general, the industry widely continues its conventional operations, while it slowly navigates its way through energy transition towards net zero carbon emissions. This paper presents a suggestion on the importance of incorporating a sustainable risk assessment register and matrix in all current operations planning to address carbon footprint before the industry fully transitions itself into a net zero modest of operandi. Due to the growing demand in considering socially responsible criteria's in managing day-to-day oil and gas business through the principals of Environment, Social and Corporate Governance (ESG), carbon emissions are the key focus area in this implementation of a sustainable risk assessment register and matrix for the oil & gas industry. The five different risk assessment categories which oil and gas companies should consider when addressing carbon emissions through a dedicated sustainable risk assessments register and matrix for each operational activity are classified as: qualitative, quantitative, generic, site-specific and dynamic risk assessments. Actual quantification of expected carbon emissions which is not commonly in practice [CM1]now becomes utmost important as an input to define mitigating actions, working towards carbon capture and/or eliminating carbon emissions. Creative problem solving such as through the adaptation of new technologies, process improvement and revamping well unloading program to reduce carbon emissions [CM2]through a sustainable risk assessment register and matrix, will allow the industry to demonstrate actual data and efforts in addressing climate change issues as the industry transitions to net zero carbon. The Reservoir, Wells and Facility Management (RWFM) organization becomes crucial to pull together and facilitate different stakeholders’ involvement throughout the lifecycle of a project to ensure every aspect of the project planning takes into consideration risks exclusively associated to carbon emission and work towards minimizing or eliminating them. The development of this sustainable risk assessment register and matrix will contribute to social implications by acting as a reference point for all oil and gas operators and service providers in the world to produce sustainably and responsibly at the current moment while the industry makes a shift to net zero emission. This initiative will also provide an opportunity for the oil and gas industry through the collaboration of RWFM to work in accordance and embrace Sustainable Development Goal 7 and Goal 13 (SDG 7 and SDG 13) of the United Nations.