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As fields mature, the drilling and completion design and execution for infill development becomes challenging. In a deepwater environment, one of the strategies to address this challenge is to optimize subsea facilities by targeting several reservoir packages in a single wellbore. However, this technique comes with technical challenges because penetrating different zones requires active reservoir management, an allowance for zonal isolation, and an adequate response to potential crossflow. A smart completion architecture should overcome these constraints and reduce overall capital expenditure while maximizing production. Furthermore, for wells requiring sand control, the completion solution must ensure a reliable and proven approach that minimizes the potential completion failures introduced by unsuccessful sand retention. This paper presents the completion strategy implemented in an intelligent well completed in the Malaysian deepwater Block K, during the field development of Siakap North Petai (SNP) Phase 2 and executed in Q1 2022.

Amongst the challenges encountered during infill drilling and completion is the requirement to penetrate depleted zones drained during the early phases of the field development. This condition is exacerbated for completions requiring openhole gravel pack as the maximum openhole lengths are traditionally limited by the effective circulating density experienced during the openhole drilling and gravel packing. This paper discusses the techniques implemented in four openhole gravel pack completions with openhole lengths up to 858m marking a new record for the longest openhole completed by PTTEP in this field. The wells were deployed by PTTEP in the Malaysian Deepwater Block K, during the field development of Siakap North Petai Phase 2, executed between Q4 2021 and Q1 2022.

In Q4 2017, the first extended-reach horizontal oil producer was completed in S-Field, with the horizontal section designed with nine isolation compartments with swellable packers. Each compartment was configured with an inflow control device (ICD) and an integral sleeve (on/off function) attached to the ICD’s joint. This paper discusses the effectiveness of the ICD technology in terms of sustaining incremental cumulative oil production by delaying water-breakthrough and subsequently reducing undesired water cut after water-breakthrough.An extensive post-job evaluation on production performance was conducted to evaluate the performance of the installed ICDs. The workflow was divided into three stages: history matching, forecasting, and post-job ICD evaluation. During history matching, the horizontal well with the ICDs was modeled using a high-resolution numerical simulator, and the reservoir model was calibrated with production data from a well test. Actual production rates and the water-breakthrough time were matched by revisiting key subsurface uncertainties from the sector model, such as aquifer strength, oil/water-contact, and relative permeability using the Corey correlation. The history-matched model was then used for the forecasting stage to predict cumulative production on a longer-term basis. Lastly, the performance of the ICDs was quantified after 4 years of production by comparing the oil increment from the ICD completion to the non-ICD case as baseline that would have been a miss of additional oil cumulative.Over the past 4 years, this horizontal well produced more than expected, with approximately 2–4 times more oil production than the estimated rate provided in the field development plan (FDP), whereby the lower completion is design optimally based on real-time ICD modeling updates. There were few uncertainties in the subsurface parameters such as fluid contact, fluid characterization, and the nature of an aquifer, were incorporated in the history-matching stage using sensitivity analysis and uncertainty range estimation. On the basis of actual and history-matched production performance, the well with the installed ICDs is projected to produce more than the non-ICD OH case with an improved cumulative oil production gain of as much as 6% and an 8% water reduction over 12 years of production. In addition, the ICD enables downhole influx balancing to delay the water breakthrough by 4 months compared to the OH case. The reduction or delay of water production is beneficial to the field to enhance oil recovery from the well. This case study demonstrates a successful ICD deployment under uncertainties, where during a real-time study in 2017, similar uncertainties were incorporated in high-resolution ICD modeling conditioned with real-time petrophysical data from logging while drilling (LWD) measurements.The use of ICD technology in this well demonstrated that zonal control efficiency could be achieved across the horizontal section and increased oil production over time. The ICDs were designed to deter early water breakthrough supported by well tests and manual fluid sampling indicating the water production only occur after 4 years of production and sand-free till to-date.

The operator of field S initiated a project with a key objective to unlock and increase oil recovery while maximizing the economical oil ultimate recovery and maintaining a daily production with a ceiling unit development cost. The targeted sandstone reservoirs are shallow with unconsolidated formation which require active sand control. To achieve the objectives, a Single Trip Sand Control and Cementing System was developed by the service provider utilizing existing proven technology which was adapted to be a fit for purpose solution. The main driver in developing the single trip system was operational simplicity. The high-level procedure of the system is: Drill open hole from surface to target depth in a single run. Make up lower completion assembly and production casing and run to target depth. In the same trip, set production packer and release service string. Gravel pack the lower completion or install as a stand-alone screens completion and cement the production casing in place before pulling out of hole. Once the single trip system was designed and developed, a detailed system integration testing was carried out to ensure that the technology performed as expected. The turnaround time from design to execution was reduced tremendously by utilizing existing proven technology with minimal modification required. From there, 2 wells were identified for a pilot technology trial where this novel system was implemented. The execution of these 2 wells was successful with the expected learning curve of implementing a new system. One of the key findings were the robustness of the system as it was applied in a well with higher than normal doglegs, highly deviated shallow reservoir and the sand screens were run through extended open hole shale sections which would have been cased off in a conventional completion approach. Additionally, the single trip approach allows for further optimization with multi-skilling personnel, and this led to an improved operational efficiency. Post well completion, the 2 wells have been successfully put on production and are producing sand free. This unconventional approach can unlock more marginal reserves that were previously not feasible to be developed economically.

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.

Improved cookstoves, which are designed to address the health and environmental damage caused by inefficient biomass cooking and heating, are generally engineered to prioritize technical emissions and efficiency improvements over practical user cooking needs. As a result, improved stoves are often only used alongside traditional technologies, or are rejected by cooks entirely, and may fall short in efforts to address health and environmental problems even if they are technically capable of doing so. A testing protocol for cookstove usability was developed by the authors to help stove designers and implementers evaluate user needs for a given stove technology and cooking culture, and balance them with technical design criteria more effectively. The protocol is based on established usability practices and includes ethnographic testing methods to increase validity in cross-cultural testing applications. This paper discusses evaluative trials of the protocol in 10 rural and urban households and 2 institutional kitchens near Lira, Uganda, 4 rural households in Antigua, Guatemala, and 11 stove designs in a US laboratory, as well as preliminary results from a usability study on 20 rural households near Gulu, Uganda by an international NGO. These trials, along with feedback from test administrators in Uganda and Guatemala, demonstrated that the protocol is a viable tool for increasing the understanding of cookstove usability, though more work is needed to improve its validity and connect the results to effective stove design and selection decisions, as well as health and environmental impact. As a result of this research, various improvements were made to the protocol, and opportunities for further validation, expansion, and improvement were identified. In addition, methods used by the protocol elicited related data from participants regarding their attitudes towards improved cookstoves and the relative importance of reducing air pollution and fuel use in the larger context of their lives. Finally, this research highlights the value of an interdisciplinary approach, in this case based in anthropology and engineering, to increase the accessibility of user input in international development more broadly.

While improved cookstoves have been designed and distributed for decades with the goal of addressing the human health and environmental issues caused by traditional biomass cooking, many have not achieved the impact intended. One of the main reasons for this shortcoming is that engineers tend to focus on technical attributes of cookstove designs, such as improved fuel and combustion efficiency, but neglect usability. If a stove design does not meet a cook's needs and preferences, however, the stove will likely be used only as a supplement to a traditional stove, or not used at all. To help close this gap, a testing protocol for cookstove usability was created. The development process and resulting protocol are described in this article. The proposed protocol is based on established usability practices from fields such as software and consumer product design, as well as usability criteria taken from existing cookstove research and interviews with subject experts. Ethnographic testing methods from the field of anthropology have also been incorporated to make the protocol more appropriate for cross-cultural applications, as well as adaptive to a wide range of testing scenarios. The protocol includes objective measurements and observation, as well as subjective survey and semi-structured interview questions. Usability criteria are generally assessed with paired Likert scale survey questions that elicit user perceptions of criteria, as well as the relative importance of each. These results are supplemented by interview results and objective measurements, wherever possible, for comparison and to identify bias or uncertainty in the results. This protocol may be useful to stove designers as a way to better understand users and validate designs, to implementers as a way to assist with the selection of the most appropriate stove for a given project, and to researchers as a tool to assess cookstoves and cookstove programs.

Wassana oil field is located in the Gulf of Thailand with shallow water depth at approximately 60m. A major challenge is excessive water production which reduces reserves recovery and increases costs associated with produced water handling. The target reservoir is ~20ft thick with active aquifer support. The low oil/ water mobility ratio due to high oil viscosity (≥ 30cp) risks early water coning and high watercuts. All horizontal wells drilled in the Wassana field during the initial development and the first infill campaign were completed as non-ICD openhole standalone screen. For the second infill campaign, the non-ICD simulation showed water breakthrough occurring at the start of production. Once breakthrough occurs, water production rapidly dominates production prompting premature shut-in of production, leaving much unrecovered oil behind. To overcome this problem, Autonomous Inflow Control Devices (AICDs) were introduced to control the production influx profile across the entire horizontal section to delay water coning and to significantly choke back water production when it occurs. With intensive pre-drilled AICD modeling using 3D dynamic time lapse simulation, two wells in the second infill campaign were subsequently chosen to be completed with a configuration of zonal AICDs isolated by swell packers. This design enables isolation across horizontal reservoir section with high water production in tandem with compartmentalization across the contrasting permeability region. Once water breakthrough occurs, the unique autonomous ability of the cyclonic AICD is triggered by exploiting the physics of rotational flow of the vortex-inducing pressure drop principle through a restrictive funnel-type flow-path in a tool with no moving parts. The low viscosity of both water and gas phase promotes higher rotational velocity inducing higher pressure drop or back-pressure of inflow vortex breakdown towards the inlet into the tubing flow, thus helping to further reduce the influx contribution of the high water producing sections. Essentially, the higher watercut zones flowing through the device is restricted more rigorously compared to the oil-prone zones. Both wells were successfully drilled and completed with AICDs in February 2019. Based on actual and early-production history-matched performance, these 2 pilot AICD wells are projecting an improved cumulative oil production gain of up to +7% over 5 years of production. The reduction or delay of water production can benefit the field both in enhancing oil recovery and water handling cost saving.

A multizone cased hole completion with a bottom hole assembly of world-record length at 2,600 ft was installed in Malaysia in November 2019 where three zones were simultaneously gravel packed in a single trip utilizing shunt tube technology. This sand control completion was successfully executed with a combination of sand control pumping and sand control tools, unconventionally performed by two different service providers. The well consisted of three zones of interest approximately 1,000 ft apart. The bottomhole assembly was designed with two shunted cup packers for zonal isolation and shunted 12-gauge wire wrapped screens across each perforation. The shunts were left open ended below the cup packers, allowing the carrier fluid to exit the zone below with minimal friction. Downhole memory gauges were deployed along the washpipes for post job evaluation. Diligent lab testing was performed to select the carrier fluid, a clarified high-grade xanthan polymer with good 20/40 proppant suspension with less formation damage and acceptable dehydration to avoid bridging inside the shunts. Detailed risk assessment that was performed during the planning stage focusing on interfaces, equipment limitations, expediting, and decision flow charts between the two service providers led to flawless execution at the wellsite. Compared with conventional stack-pack completion, significant time savings of approximately seven days was observed with this single-trip design; the concept of open-ended shunts below the cup packers replaced the majority of the shunted blank pipes with standard blank pipes, eliminating the time required to install jumper tubes. Good results were observed during the injectivity test in addition to the well already having losses of 20 bbl/h. Hence, no acidizing was required prior to the gravel-packing operation. Based on surface monitoring, there was clear indication of sequential packing from the top zone to the bottom-most zone via shunt tubes, followed by a final screenout. Findings were further verified after performing the downhole bottomhole gauge analysis using the retrieved data from the memory gauges. The well has been in production since December 2019.

The Kraken field development was planned and executed through several batch drilling and completion phases to allow a review of each phase and incorporate the lessons learned in the next phase. All producers were drilled with an oil-based reservoir drilling fluid (OB-RDF). The lower completion with shunted sand control screens was installed in conditioned OB-RDF, followed by displacements to water-based fluids after the packer was set. Gravel packing was performed with a visco-elastic surfactant fluid, and a breaker treatment was spotted across the open hole prior to isolating the open hole with a fluid loss control valve. This paper discusses the design, execution and evaluation of the lower completion phase for the development of the Kraken field in the North Sea. This includes detailed reservoir evaluation, methodology followed for sandface completion selection, steps taken to improve efficiency through lessons learned and continuously extend well lengths to be gravel packed in a low frac-window environment, and well performance results in this 24-well field development, with focus on the 7 out of 13 oil producers, detailing 3 of them.

While improved cookstoves have been designed and distributed for decades with the goal of addressing the human health and environmental issues caused by traditional biomass cooking methods, they often have not achieved the intended impact. One of the main reasons for this shortcoming is that engineers often focus on technical attributes of cookstove designs, such as improved fuel and combustion efficiency, but neglect usability. If a stove design does not meet a cook’s needs and preferences, the stove will likely be used only as a supplement to a traditional stove, or not used at all. To help close this gap, a testing protocol for cookstove usability was developed. The proposed protocol is based on established usability practices from fields such as software and consumer product design, and includes usability criteria taken from existing cookstove research and interviews with subject experts. The protocol includes objective and subjective testing methods, is designed to elicit user perceptions of and the relative importance of each usability criterion in a given context, and incorporates ethnographic methods to improve validity in cross-cultural applications and in diverse testing scenarios. This protocol may be useful to stove designers as a way to better understand users and validate or improve designs, to implementers as a method to assist with the selection of the most appropriate stove for a project, and to researchers as a tool to assess cookstoves and cookstove programs. Preliminary field and laboratory work to test the validity of the protocol demonstrated a mixture of meaningful and uncertain results, indicating that while it is a reasonable tool to assess cookstove usability, the protocol requires interpretation of qualitative data and assessment of uncertainty to be most effective.

Procurement of clean drinking water is one of the most important challenges facing 1 in 10 people in the world today. While there are many technologies available to disinfect water, there is still great opportunity for appropriate, sustainable technologies for low-resource or emergency situations. Pasteurizing water is an effective way to eliminate life-threatening pathogens such as bacteria, viruses, and protozoa, and requires a lower temperature (71° C) compared to traditional boiling (100° C). This research details the development and testing of a water pasteurization system that works with the 60 Liter InStove to produce upwards of 4,500 liters of safe drinking water per day at minimal cost to the users and the environment. This flow-through system uses a combination of a heating coil, thermostatic valve, fixed volume kill chamber, and heat exchanger for heat recovery immersed in a large pot of heated water. Initial performance testing revealed that the pasteurizer produced 6.7 liters of water per minute with an energy input of 9.1 grams of equivalent dry wood per liter (175 kJ/L) at steady-state operation accounting for startup time. Microbiological testing revealed that water initially inoculated with >100,000 bacteria/ml of E. coli had no colonies remaining after treatment, for a 99.999% reduction in contamination levels. Future work will include measurement and modeling of the flow and temperature profiles throughout the system to optimize its heat transfer performance and production costs, field testing, and user-centered system-level design that develops the end-to-end solution needed to acquire and deliver clean drinking water including maintenance, container disinfection, and development of business models to support local water production.

This paper covers the design, execution, and evaluation of the development of the Zawtika field operated by PTTEPI in Myanmar. This includes the study of the reservoir, the selection of completion methodology, the operational challenges, and the performance of the wells. The Zawtika field development focused on the laminated Plio-Pleistocene reservoirs. The formation comprises a thick sequence of mixed deltaic and shallow marine clastic sediments. A conservative geomechanics study indicated that any reservoirs shallower than 1,700 m true vertical depth (TVD) have high sanding risks and would require an active sand control method. A batch completion campaign was planned and deployed as a mix of single-zone and stacked dual-zone cased-hole gravel packs (CHGP). A pre-gravel pack acid treatment was tailored for formations with high chlorite content and fines stabilization. A fracture- and gravel-pack service was the primary gravel pack option followed by high-rate water pack (HRWP) depending on water zone proximity or a lack of stress barrier. The sanction that was placed on the country at the startup of this campaign and the limited infrastructure in place led to various challenges during different stages of the campaign. Over 15 months, 17 wells were completed on three platforms with eight single-zone wells and nine stacked dual-zone wells. This totaled 26 zones where 10 zones were completed with the fracture- and gravel-pack service and 16 zones with HRWP. These jobs were executed on a tender assist for the first platform and on a hydraulic workover unit for the following two platforms. These were among the notable points for the campaign: First CHGP completion in MyanmarAchieved production objective with zero sand productionIntroduced the technique of pumping HRWP in sweep stages for longer intervals in MyanmarIntroduced several fluid systems in Myanmar, including a polymer-free carrier fluid, acid system with diverting agent, fluid loss pill, and clay stabilizerCompleted all wells without downtime related to delivery of products despite the remote location and logistics between multiple countriesCompleted the campaign without any HSE incident and with high operating efficiency

The mode of gravel transportation in openhole packing is determined by the deviation angle of the interval - typically a gravity assisted (bottom up) mode occurs for deviations less than 50 degrees and alpha-beta mode for deviations exceeding 60 degrees. Experience in various fields in Brunei indicates a lower success rate when gravel packing intervals in the 50-60 degree deviation range using conventional gravel packing techniques. In fishhook wells, the critical 50-60 degree deviation range is equivalent to the uphill wellbore geometry 120-130 degree deviation range. This paper discusses the technique used to gravel pack two fishhook wells with deviations of 126 and 131 degrees respectively. The objectives of the completions were threefold: Achieve a complete annular pack, Provide the capability for zonal isolation Maintain bottomhole pressures below the fracturing pressure. Deliver a low skin completion. The world's first successful Shunt tube uphill gravel pack in a fishhook well was executed in September 2010. The same type of completion was performed for a second time a few months later. Completion design, component optimization, fluid design, gravel pack simulation and downhole gauge analysis for these wells are discussed.