The jack-up platform will face the risk of punch-through failure when pilling in areas where a stronger-thinner layered soil overlays a softer soil layer. The punch-through failure that occurred in the South China Sea indicates that there are still shortcomings in the existing punch-through failure assessment methods. Therefore, this paper improves the shortcomings of the existing punch-through failure assessment method based on the simulation experiment. Firstly, the shortcomings of the existing punch-through failure assessment method were analyzed based on the case of punch-through incidents occurred in the South China Sea. Then, the main factors of punch-through were analyzed by means of simulation experiment, and the shortcomings of the existing method were improved. Meanwhile, a punch-through failure assessment method considering the spudcan tip height and loading process was established. Finally, taking a case of the South China Sea as an example, the improved model guided the penetration of jack-up platform and avoided punch-through failure successfully. By analyzing the case of the punch-through failure occurred in the South China Sea, the soil layer in which punch-through failure occurs has the characteristics that the thickness of stronger-thinner layered soil is close to the height of pile tip. In order to explore the main factors leading to punch-through failure, a set of experimental system simulating the spudcan punch-through was designed, and a series of punch-through simulation experiments were conducted. Simulation experiment results show that the reduction ratio of bearing capacity will decreases with the ratio of stronger-thinner layered soil thickness and pile tip height (d/h) increases. When the d/h is greater than 2, the reduction ratio of bearing capacity is less than 5%; When the pile tip height is equal to the thickness of stronger-thinner layered soil, the reduction ratio of bearing capacity is more than 95%. The innovation of this paper is that punch-through failure assessment method considering ratio of pile tip height and soil layer thickness was established.

Formation sand production is one of the major production challenges in most of the mature fields in Malaysia. Often, failure in primary sand control equipment requires the operators to adopt through-tubing sand screens as a remedial sand control. Current remedial sand control techniques utilizing metallic through tubing sand screens experience rapid wear, forcing the operator to control sand production by beaning down wells and thereby managing sand production at surface, in worst cases wells have to be shut-in. More robust technologies replacing conventional metallic screens are required. For these applications, alternative technology with ceramic sand screens have been deployed to enable higher productivity and offer enhanced resistance against erosion. Ceramic sand screens passed through a technical qualification process at Petronas and deployed in field applications both in oil and gas producers for through tubing interventions. To date 30 well interventions have been performed in various Petronas assets of Offshore East Malaysia with mixed results. Eight screen failures were observed with longevity ranging from 2.5 days to 15 months of production after installation. On average, ceramic sand screens greatly enhanced productivity return through longer performance than the conventional through tubing metallic screens from previous deployments. However, it was both the intent of product provider and Petronas to further improve Through Tubing Ceramic Sand Screen (TTCSS) performance based on the lessons learned from these failures. The TTCSS failures were first presented in the paper: SPE 196479 MS published at SPE APOGCE October 2019, Bali, Indonesia which which focused on the failures of these first generation TTCSS screen designs. This paper describes in more detail the value driven process and collaboration steps between 3M and Petronas to improve TTCSS field performance as a methodology to increase incremental field production to further increase longevity of downhole sand control in these applications. To enable this goal, a root cause analysis process entailed involving tear down investigation, hypothesis of failure characteristics, application review and investigation analysis with tools such as CFD and laboratory testing resulting in the implementation of ceramic sand screen design enhancements to improve performance in further Petronas deployments.

A mature deepwater asset of 1,330 m of water depth offshore Sabah, Malaysia, has been delivering notable production since 2007, and currently the field is in its declining mode. The second phase of the field development focused on producing from the thin-bed layers of the reservoirs, which were found less efficient in pressure maintenance given existing water injection support as the primary support. Initial conceptual studies were conducted between 2012 and 2014 to determine which improved oil recovery (IOR) initiative would be the most effective and economical way to retain declining production of the field, extend end-of-life, and ultimately protect reserves. Further in-house engineering studies and follow-up with a field mini-trial in 2014 demonstrated that providing gas lift to the spar wells would improve and revive production of the targeted wells. A permanent coiled tubing (CT) with gas lift completion (CTGL) was determined as the most efficient and cost-effective solution. Single-point gas injection is sufficient given available injection pressure, static/dynamic fluid level, and the available maximum depth of the injection tip. Modifications of the dry tree on the spar facility were required to accommodate the changes; changes included a new 5-in. gas lift pipeline; topside piping at the spar; and installation of associated control, metering, and instrumentation devices. Specific CT bottomhole assembly (BHA)/components were determined to safely deliver gas inside the 3.5-in. and 4.5-in. production tubing to slightly above the well’s downhole safety valve. A total of 14 dry-tree wells were selected for this project and the project has successfully completed installation of CTGL in 11 wells by mid-year 2019. Wellhead modification was carried out by installing the tubinghead spool and gas injection arm. A CT rigid riser well stackup was rigged up directly on the tubinghead spool. The 1.25-in. outer diameter (OD) chrome CT string and gas lift BHA of specific simulated venturi sizes were deployed to the targeted depth in each well. Downhole completion safety valve and gas lift BHA double flapper check valves were then be inflow tested. Blowout preventer (BOP) was engaged against the 1.25-in. OD CT string, and pressure in the well stackup above the rams was bled off before cutting off the CT string. The CT tubing hanger was made up directly on the cut CT string. Finally, the CT tubing hanger was installed into the tubinghead spool with a 4-in. flow release pulling tool. An additional simulation study was performed to confirm the ability of the 1.25-in. OD CT BHA to inject up to 3 MMscf/D. The executed wells were brought online, and a comparison of the well tests was performed. The CTGL wells responded very well whilst being assisted with gas lift, which delivers an outstanding result by adding incremental gain of 20%, and even adding value to revive idle wells, which has significant value by doubling the base production figure without gas lift. An estimate of more than 50% protected reserves can be achieved with the 11 CTGL wells at the end of field life. The installation and execution of CTGL came at the right time as the field requires lift assistance to stay productive.

Objectives/Scope This paper shares results from the first field deployment of an active sealing device in a narrow margin deepwater well in the Black Sea. The active sealing device represents a clean-sheet design approach purpose built for deepwater MPD operations. This paper shares highlights from the detailed design through the prototype testing to the first-use stages of the program. Methods, Procedures, Process This paper discusses three distinct program phases covering the overall process from concept development to field operation. First, the detailed design phase is discussed, introducing the reader to system components and functionalities. The second phase of full-scale testing is discussed from the design verification, system optimization, and systems integration testing perspectives. Finally, field results are shared detailing findings from the first deployment on a dynamically positioned deepwater rig drilling a narrow margin MPD well in the Black Sea. Results/Observations/Conclusions The paper shares findings, insights, and results from each of the phases of the active sealing device development program. Upscaling passive RCD technology for deepwater has negative effects on system performance. A non-rotating, externally functioned seal sleeve element eliminates multiple high wear components. Elimination of bearing assemblies and rotary seals removes common failure modes seen in deepwater. Redundant, actively controlled seal elements ensure wellbore seal quality throughout the seal life. A lubrication system injects mud between seal elements, enabling seal condition monitoring. Active seal condition monitoring alerts the rig crew when to replace the elements prior to failure. Full-scale testing has been completed demonstrating the system under simulated drilling conditions. Seal life demonstrated to outlast most deepwater MPD hole sections. Operational testing and integration testing reduce commissioning and testing time consumed on the rig. Active sealing device successfully integrated into the drilling riser and MPD specialty joint. Multi-modal system provides rig crew with distinct operational strategies to meet current parameters. Consistent seal life enables rig crew to drill MPD sections with confidence in the wellbore seal. Deepwater well with multiple MPD sections successfully drilled using new active sealing device. Novel/Additive Information The project includes secondary novel aspects such as drilling contractor ownership of the subsea and topside MPD equipment. The MPD system is integrated into the drilling control system allowing communication between the rig, subsea, MPD topsides, and all third-party systems, while also sharing commonality with other rigs in the fleet. An objective of the MPD system design is to enable new models of fleet management to meet drilling contractor operations.

Produced fluids, from a tight deep carbonate reservoir extended laterally from West to South East Kuwait experienced severe asphaltene deposition along production tubing. This flow assurance challenge significantly increases well operating cost, risk and production deferment periods due to frequent Coiled Tubing (CT) cleaning jobs using considerable amount of expensive organic solvents. This flow assurance challenge is caused mainly due to the absence of any of strong reservoir aquifer support, continuous decline in reservoir pressure and high draw down across this tight reservoir in order to meet production targets. The objective of this pilot trial was to provide a long term solution with redundancy feature to convey chemicals safely from surface to down-hole through capillary tubes and pressure regulated chemical injection valves. Different techniques have been introduced since 1980 including batch chemical squeeze treatment, coated tubulars and Radio Frequency Vibration tools. Results of these trials have shown either short term production gain or no improvement on asphaltene build-up rate and well productivity. In order to dynamically mitigate this challenge, a dual in-situ chemical injection system was installed to convey chemicals deep inside the well on a continuous basis. The system was successfully installed and has provided a safe & reliable field qualifying tool to verify chemical performance at different injection parameters. The novelty of this technology is the ability to provide a continuous asphaltene management system to achieve production sustainability using dual injection conduits and down-hole pressure regulated valves utilizing relatively small amount of chemicals. This paper highlights the adopted approach of continuous asphaltene management system from hardware design & installation prospective to chemical qualifying process in the field and also shed light on the pilot trial lessons learned.

Most 5 1/2in-casing mature wells need to be re-fractured for improving the ultimate recovery. Over the last decade, operators focused on the sidetracking well completion for maximizing wellbore contact. Acid fracturing tend to be performed to treat the reservoirs and make fractures system more complicated as much as possible. The irregularity of slim hole has negative influence on the deploying of completion or fracturing assembly. Isolation tools are usually subjected to heavy corrosion caused by acid or proppant fluid. The 3 1/2in Open-hole packer-sleeve (OHPS) completion assembly including improved external casing packer (ECP) were proposed for sidetracking well completion. The water-swellable packers (WSPs) with anti-corrosive thermo-plastic vulcanizates (TPVs) was used as the alternative to current mechanical-set ECPs. The TPV matrix was prepared by physically blending high-strengthen carboxylated nitrile (XNBR) with polyamide (PA6). To improve the swelling performance, newly-developed Porous Super Absorbent Resin (PSAR) was mixed and distributed into XNBR/PA6 system. The new swellable TPV exhibits the advantages of high strength, anti-corrosive property and high reliability over traditional packing materials. The TPV material characterization and annular sealing test of 3 1/2in prototype was conducted in the lab. One 5 1/2in mature oil well was selected for field validation. One 3 1/2in OHPS string with four stages was successfully tripped into large-deviated slim borehole. During the stimulating operation, WSPs acted as effective barriers and any communications between stages did not occurred. It is concluded that the new OHPS using improved WSPs meet requirements of slim-hole sidetracking well completion and stimulation.

The challenges, experiences, and best practices established from cementing in high-pressure high-temperature (HP/HT) offshore wells in India are discussed along with the design and tailoring per the parameters of each well, real-time operation analysis, post-operation evaluation, and lessons learned from 10 years of experience. Challenges encountered, associated potential risks, and solutions implemented to overcome such challenges in a bid to achieve desired zonal isolation are presented. The obvious presence of high temperature (>400°F) and high pressure (>15,000 psi) as well as a narrow range of fracture gradient and pore pressure created challenges in cement, spacer design and field execution. Another task was to maintain desired rheological hierarchy and fluid compatibility of fluid pumped to achieve the desired displacement efficiencies under these vital well conditions. The introduction of specialty chemicals to develop cement and spacer fluid, which can help maintain downhole properties under these extreme conditions, has been vital to the success of dependable cement barriers in these wells. The wells presented multiple issues during the course of planning, and a few of them had to be sidetracked one or two times. Losses during drilling, gas flow, etc., were commonly encountered in both 12 1/4- and 8 1/2-in. sections. This caused a reexamination of cementing practices, particularly for production sections completed with expandable liner hangers (ELHs). The successful liner operation in these wells encountered an additional challenge—placement of the cement sheath with a higher top of cement in a HP/HT environment. An integrated basis of design was developed to help mitigate challenges and achieve objectives, and it primarily included the following: Successful running-in and placement of an expandable liner system Using specialty chemicals to sustain the downhole extreme environment throughout the life of the well Using computer-aided simulators to achieve excellent zonal isolation across and over the zones of interest An expansive additive was used to enhance hydraulic isolation of the zones of interest because it helps the cement expand in an HP/HT environment and fill any microchannels. A 3D displacement fluid dynamics simulator played an important role in determining efficient placement of cement. This helps pinpoint potential fluid channeling caused by reduced standoff, poor displacement efficiency, or abnormal in-hole geometries. Specialized additives were introduced when designing spacers to modify their parameters to withstand downhole HP/HT conditions, which generated the necessary friction pressure under a low pump rate to achieve rheological hierarchy, and eliminate compatibility problems with all drilling fluids. The successful design and cementation of more than 20 HP/HT wells was executed, including the deepest well in the operator's history throughout the previous 10 years.

Often, casedhole petrophysics provide essential information for reservoir surveillance and monitoring in mature field reservoirs for recovery optimization. One of the vital casedhole data acquisitions involves a pulsed-neutron tool for formation evaluation. The service company's recently developed multidetector pulsed-neutron tool (MDPNT) with a long-spacing detector provides a unique measurement [sigma, carbon-oxygen, and saturation gate (SATG)], which significantly helps improve sensitivity for formation gas saturation. The multidetector pulsed-neutron tool (MDPNT) is the only casedhole formation evaluation tool within the industry to be used with a memory system simultaneously acquiring the inelastic carbon/oxygen (C/O) ratio and capture (sigma) logging modes. The high-power battery pack provides up to 11 hr of continuous logging with superior data quality. A memory-based logging system provides advantages in terms of a smaller footprint, improved operational safety, and easier logistics handling, which results in significant operation cost reductions. A successful application of the first MDPNT memory logging on slickline deployment in Field A of Peninsular Malaysia is discussed. Pulsed-neutron data were acquired in the well with the objectives of validating hydrocarbon fluid types for additional perforation operations and determining current hydrocarbon saturation to derisk openhole log interpretation uncertainties and fluid contact delineations. The targeted sand is located above the top packer section, and based on openhole logs alone, there is a high uncertainty of distinguishing between the presence of oil and water. The well consists of a complex completion string with 3.5-in. tubing inside a 7-in. casing along with a packer and sliding side door (SSD). Gas trapped under the packer is a common scenario and poses another challenge in saturation computation. Post-data acquisition results exhibited a positive indication of oil presence within the targeted reservoir. Gas-oil contact (GOC) was successfully determined within one of the reservoirs despite the thin oil rim presence, which could be easily overlooked. The discovery has led to the assessment of a nearby well to be the potential add-perf candidate within the same reservoir for quick gain monetization. The add-perf operation was conducted in two reservoirs and flowed successfully at 500 B/D instantaneous production. The effort was well paid in reactivating an almost four-year idle well status with sustained production and a 0.2 MMSTB reserves addition. In other words, the three-phase pulsed-neutron analysis consisting of the C/O, sigma, and SATG combination has convincingly generated a robust saturation computation covering all the zones of interest. The case study described in this paper emphasizes the benefits of the MDPNT memory logging, particularly within a challenging offshore environment with a limited footprint profile and logistics arrangement, and yet successfully unlocked the low-hanging fruits for production enhancement.

As the industry rebounds from recent pricing challenges, operators are searching for methods during each stage of their well—from drilling to production—to make the field more economical without compromising safety, health and quality. This paper describes a different method for offloading a newly drilled well. In 2017, a well drilled in north Iraq targeted five productive zones. This directional well had a good potential to flow from upper zones which were producing around 3,000 BPD cumulative production. To get production from the upper four zones, conventional coiled tubing (CT) was utilized, and the well started to flow after lifting the drilling fluids. After testing the upper zones, the operator planned to evaluate the lower zone for the production. The well completion had sliding sleeve doors (SSD) and was installed for every zone separately. This well used a jet pump for offloading fluids from the last zone. The upper four zones were plugged using the SSD, so only the last zone was open for flow. A jet pump was designed using jet evaluation and modelling software (JEMS). The design was based on the optimum size of the nozzle and throat selected for the lowest zone. A downhole jet pump was modified, based on the existing SSD, and installed in the well using slickline. High-pressure power fluid was injected into the well from the annulus and returns were taken from the tubing. The well was successfully offloaded using the jet pump. The well was then tested for production using the same jet pump system, which resulted in around 1,300 BPD production. Jet pump systems require critical observation and proper understanding of the system for this kind of application. The well was economically offloaded using a jet pump system. This method saved a significant amount of time and money for the operator. Additionally, the jet pump system can be easily installed, designed and modified as per well and completion specifications. The nozzle throat combination can be changed on-site, depending on production results. The installation and operation procedure will be explained in detail for a comprehensive understanding of the system.

A rigid riser system has been designed, built, and proven as an effective method to conduct coiled tubing operations on floating platforms. This system is installed above the Christmas tree which is supported by the platform's production riser and riser tensioner system. The rigid riser set up is a passive system that does not require the use of a crane or other mechanisms to support or hold up the coiled tubing injector head during operations. The axial load resulting from the weight of the injector head, coiled tubing, and snubbing/pulling forces on the pipe are carried in compression through the rigid riser to the tree and wellhead. The excess capacity of the top tensioner riser (TTR) supports these loads while allowing for relative motion due to tide, waves, and platform motion. The rigid riser system uses a purpose-built, heavy-wall riser and a spider beam insert to resist buckling effects and bending moments. In practice, this system has improved the rig-up time and mitigated HSE issues as compared to the conventional motion-compensated lift frame method. In addition, the system has a support frame that increases the rigidity of the injector head and accessories, resisting the excessive bending and torsional loads imparted by back tension and movements of the coiled tubing (CT) reel. An engineering study was performed to determine the dynamic loads and stresses for the various operational and contingency conditions on all the components of the rigid riser system and to confirm sufficient capacity of the TTR system. The rigid riser system has proven to be a safe and cost-effective solution for coiled tubing operations from a floating platform compared to current motion-compensated jacking frame systems. Coiled tubing well interventions were executed using the rigid riser system, and the operational results have been convincing. The passive nature of the system provides an HSE advantage by eliminating mechanical or human intervention during operation. This paper reviews the design aspects of the rigid riser system, its advantages over the current coil tubing intervention systems, and the operational results after executing the coiled tubing interventions.

The sliding sleeve has been widely used in upper completions as a useful flow management device to enable selective communications between the production tubing and the annulus. Traditional sliding sleeves are mechanically operated by standard wireline method, which not only results in non-productive time and potential operational risks but also restricts sliding sleeve applicable in vertical wellbores only. To overcome the limitations, this paper introduced an innovative Hydraulic Controlled Sliding Sleeve (HCSS), which eliminates interventions with conventional wireline shifting tools. HCSS offers instant open/close operation by surface controlled hydraulic pressure through a single control line. HCSS features unique advantages over mechanical sliding sleeves, by its operational simplicity, independence on wireline units, and applicability in deviated wells and horizontal wells. The application of HCSS could save non-productive time, reduce operational risks and improve operational efficiency and economics. This paper will give a comprehensive demonstration of HCSS and illustrate the working principle in detail. Unique features and capabilities over traditional sleeves will be discussed explicitly. HCSS will be opened by applying hydraulic pressure from the surface control unit to activate the movement of the inner sleeve, and it will be closed simply by releasing the pressure, which will allow the inner sleeve to return to its original position. In the case of hydraulic control failure, HCSS also equipped with a secondary open/close mechanism by the special shift tools operated by coiled tubing. The authors conducted two representative case studies of HCSS application in offshore upper completion in Bohai bay in China to further highlight the improvement of operational efficiency and well economics.

The reliability of subsurface barrier valves has long been an industry problem. This can lead to costly interventions, especially apparent in deep-water subsea markets. This paper describes the world's first deployment of multicycle barrier valves in 2 subsea wells in Australia that uses innovative methods of both remote activation and triggering, that have been previously unavailable on the market, and attain a step change in reliability. The remote activated barrier valves were deployed as part of a subsea gravel pack system. They were initially run in hole (RIH) open as part of the lower completion, then closed mechanically. The valve was subsequently opened via Radio Frequency Identification (RFID) tags and then closed again mechanically to allow the running of the upper completion. Frequency modulated pressure cycles were applied to the well to open the valve and allow the well to flow. The valve functioned exactly as planned, and it was demonstrated that it could be closed multiple times on a semi-sub vessel. The valve was then opened via RFID tags conveyed on wash pipe. This is a much more reliable method when in high debris environments. The valve was opened for the final time via frequency modulated pressure cycles. These are better able to be transmitted through debris and are not affected by other hydraulic events in the well. The hydraulic pump that is used to actuate the tool provides a constant force directly to the ball valve mechanism and is not subject to failures over time like existing gas charges, ratchet mechanisms or springs. The RFID, Mechanical or pressure cycles used to trigger the valve offer a huge increase in operational flexibility that have never been able to be realized with existing technologies.

In the 2018 infill development campaign, improved production was targeted by the operator through the installation of Autonomous Inflow Control Devices (AICDs) in a horizontal well at Offshore China. However, as the well requires gravel packing to manage the sand, the integration of AICD and gravel pack was an issue. The well was expected to intersect heterogeneous formations with varying properties resulting in an uneven reservoir influx toward the wellbore. In addition, water mobility in the reservoir is at least 150 times bigger than oil mobility and a strong aquifer is located near the well. Therefore, similar to the analogue wells completed with gravel packs, oil production from this well was expected to suffer severely from an early water breakthrough in a couple of weeks. These challenges can be mitigated by deploying AICDs that can manage the reservoir fluid influx toward the wellbore and therefore optimise the well performance. AICD, an active flow control device, delivers a variable flow restriction in response to the properties of the fluid and the rate of flow passing through. An integrated workflow was followed to deliver successfully the AICD application for CNOOC in an offshore heavy oil reservoir with huge uncertainties in remaining oil thickness and water-oil contacts. The well with the horizontal length of 440m was drilled in a thin formation with the oil column of 4.5m on average. The well intersected three different geological layers with different rock properties. The lower well completions comprised gravel pack, sand screens and RCP AICD valves were connected to an ESP pump lifting the fluids to the surface. The well was segmented in 4 compartments and a tailored AICD completions based on the real-time log data from the well was designed to properly restrict the production of unwanted fluid. Through teamwork between the companies, the well was successfully completed with AICD and gravel pack. The final modelling was performed just in the time span between reaching target depth and running the completion. Over a period of 12 months production, the offset well with no AICD devices encountered water production in the first two weeks and water cut has kept increasing to 88%. However, the AICD well not only has no problem in terms of sand production and has limited water cut to less than 15% but also has successfully delivered 200% increase in total oil production compared to the offset well. This well is an example that demonstrates the possibility of a successful combination of AICD and gravel packs. AICD completions ensured a balanced contribution from all reservoir sections and limited water production significantly while gravel pack kept the valves safe from impacts of sands.

Water and gas injection are widely used techniques to alleviate pressure decline and improve sweep efficiency in brownfield reservoirs. When variable reservoir properties exist, such as permeability, pressure, and thickness, the requirements for real-time monitoring and control become crucial to ensure zonal injection target rates and volumes are achieved. The Bokor Field is located in the Baram Delta area of the South China Sea, 45 km from the shore of Sarawak, Malaysia, in a water depth of approximately 70 m. This marks the initial use in Malaysia of a distributed temperature sensing (DTS) fiber optic cable installed and cemented behind casing in a multizone immiscible water alternating gas (IWAG) injection well. Injection profiling was monitored via the DTS across multistacked reservoirs having different horizontal permeabilities. The DTS detected injection profile patterns within each zone and enabled identification of high permeability streaks and thief zones. Inflow control valves (ICV) were then used for injection management and control. For Bokor well, offshore Malaysia, an intelligent completion system was chosen. The well comprised downhole flow control valves with 8 choke positions, permanent downhole gauges, and a DTS cable to enable optimum injection conformance. DTS provides real-time temperature measurements along a multimode optical fiber encased in a ¼-in control line. Enhanced measurement accuracy can be achieved by placing the DTS cable as close as possible to the reservoir by installing it behind the production casing in direct contact with the reservoir formation. Deployment of the DTS in such a way presents several challenges in the design and operational phases. The first challenge is to ensure the integrity of the cable while running and cementing the casing in a highly deviated trajectory. Special equipment was designed to ensure mechanical protection of the fiber while safeguarding the quality of the cement-to-casing bond. An innovative TCP perforating technique and cable detection system had to be developed to prevent damage to the DTS when perforating the casing. Several design interfaces and system integration tests were identified and carried out between multiple providers to guarantee a smooth and successful installation. Preliminary results demonstrate intelligent technology for real-time monitoring of the actual injection profile behind casing, and for controlling it remotely via an RTAC (real-time acquisition and control) software solution.

Laser applications provide unique advantages to applications in discovery, recovery, and production of hydrocarbons. A comprehensive numerical model would enable prediction, optimization, increase efficiency, enhance control, and further innovation. This work reviews the modeling methods, discusses key variables and physics, presents results, and introduces innovative solutions that make use of machine learning and artificial intelligence to solve an inherently multi-scale and multi-physics problem. Two possible methods have been explored to model laser-rock interaction: mechanistic and statistical — the former uses as a set of coupled partial differential equations that adequately describe the physics involved. The statistical method uses advanced statistical analysis and supervised-learning to elucidate relations between the experimental settings and observations. The full-physics or mechanistic model was developed using finite-element and finite-difference methods; it incorporates coupled solvers for electromagnetic, thermodynamics, and geomechanics. The statistical model uses advanced statistical analysis and machine learning to characterize the dynamics and build a prediction algorithm. A numerical model of laser-rock interaction must comprise physical dynamics that span over different time and spatial scales. When a laser beam impinges on a rock, a portion of the incident energy is absorbed as thermal energy, and a thermal gradient is created. The result is a distribution of physical and chemical changes such as spallation, melting, dissociation, calcination, or vaporization. The full-physical model can adequately capture the transient process; however, it requires a functional characterization of the dynamic rock properties, environmental conditions, and laser parameters. The statistical approach provides a prediction of the overall outcome of the process departing as a function of known input parameters, yet its precision depends on the availability of experimental data (outcomes and conditions). Key parameters are identified using statistical analysis. The modeling results agreed with experimental tests. Further, they evince that thermal properties and geomechanical stresses configuration have a significant impact on the process’ outcome. These methods can optimize and predict the interaction for multiple applications, ranging from heat treatment to stimulation. Subsurface laser operations could provide the next generation of stimulation and workover tools for Oil and Gas. Numerical models of laser-rock interaction are essential to predict, optimize, adapt, and evaluate subsurface laser applications during development, test, and operation. This work provides a basis for the development of future numerical models and enables the next generation of subsurface photonic tools.

Downhole fluid analysis (DFA) has proved to be an effective technology for assisting in understanding reservoir dynamics, fluid distribution, reservoir compartmentalization and in-reservoir processes. Until recently, DFA technology was only available with wireline-conveyed tools. It was typically performed after the well had been drilled, limiting the ability for real-time decision making. The recent advent of logging-while-drilling (LWD) DFA technology — also known as fluid mapping-while-drilling (FMWD) — allows operators to make informed and timely decisions early on well construction, landing, geosteering and completion without pulling out of hole. This paper presents the results of an FMWD campaign by Repsol in Malaysia. FMWD technology was deployed in five wells with different objectives but with the common goal of enabling real-time decision making prior to the bottomhole assembly (BHA) reaching the surface. The FMWD objectives were to assess reservoir connectivity, monitor pressure depletion, measure CO 2 content, and differentiate between formation fluids (gas, oil, and water). For exploratory targets, the service was run to confirm the presence of hydrocarbons and to assess in-situ fluid properties. In a highly deviated well, the technology was used to confirm fluid properties for geosteering the wellbore through a targeted zone if it proved to be oil bearing. The campaign was very successful, and the objectives were fully achieved. With the completion of more than 130 pressure tests, a comprehensive and complete pressure profile was obtained in each of the five wells, allowing for the selection of the most appropriate depths for DFA fluid scanning and sampling. Twenty-four DFA stations enabled clearly identifying fluid types in various exploratory and appraisal targets. This information was then used to make key decisions on well landing and completion strategy. In addition, CO 2 was systematically identified and quantified by the tool optical spectrometers; thereby, accurately mapping its distribution across the field. Real-time data transmission using mud pulse telemetry allowed for real-time monitoring and important operational decision making. In some cases, only 15 minutes of pumpout was sufficient time to identify the movable reservoir fluid phase. In other cases, physical downhole fluid samples were collected once the mud filtrate contamination had sufficiently decreased below the predefined acceptable limit. In general, the time on each station was brief, which was attributed to reduced depth of filtrate invasion because FMWD operations took place soon after drilling. This paper presents the lessons learned from introducing of the FMWD service in exploration, reservoir management and geosteering, within the same five-well drilling campaign. Until the present time, this technology was only available using wireline. However, the introduction of LWD DFA has been found to be disruptive for reservoir management, drilling, completion, and geosteering applications, similar to the way formation pressure-while-drilling (FPWD) was a gamer changer for the drilling industry when introduced in early 2000s.

Perforating an existing producer with a completion in place would typically be limited in terms of gun size and perforation cleanup ability, hence affecting the well performance. This paper is a case study of a through-tubing additional perforating job, its performance analysis, and finally the implementation of a wellbore implosion technique for perforation tunnels cleanup. Job design and the well performance analysis are also presented. The zone selected for the initial additional perforation was analyzed and a gun system simulation was performed. After the initial perforating job, surface and downhole surveillance data were collected for perforation performance analysis. Based on this analysis, a wellbore implosion technique was selected for perforation tunnels cleanup to enhance their productivity. Several wellbore implosion job simulations were performed based on various design scenarios. The optimal design was selected and executed successfully. Postjob well performance was then analyzed and compared with earlier performance. Although this implosion technique cannot improve or alter the reservoir rock deliverability, its ability to perform perforation cleanup is expected to be evident from the well performance analysis. Analysis of the well performance after initial perforations showed a lower productivity index (PI), which was expected considering that the perforating job was conducted through-tubing while the completion was in place. The subsequent well implosion technique was executed successfully, and after that operation, the PI of the well improved, indicating the success of the technique to clean the perforation tunnels. Because many wells suffer from improper perforation cleanup, this case study provides an important example for such wells, whether old or new, to replicate and instantly enhance their productivity. This technique can also be implemented in injector wells to enhance their injectivity.

Most of carbonate wells in PETRONAS Carigali Operated blocks in Malaysia are completed with pre-drilled liner. Barefoot completion is a new approach that is planned to be implemented in this particular carbonate field. This paper aims to share on how selection of lower completion based on in-house carbonate lower completion guideline could optimize overall well cost. The offset well in X field are all completed with pre-drilled liner. As an initiative to further optimize the well cost and delivering an economic field development plan, barefoot completion has been proposed as a completion strategy for the upcoming drilling campaign. Selection of this strategy has taken into account the wellbore stability during production, geochemical effect and critical drawdown, including unconfined compressive strength (UCS) based on the outcome of the geomechanical study. The advantages of the approach are mainly in reducing open-hole length thus reducing the drilling cost, secondly is eliminating all the equipment requirement for lower completion thus reducing completion cost by 14% in X field. This shows that the guideline is effective in choosing the fit for purpose and safe lower completion strategy for carbonate. The work evolved from replication of best practices and lessons learnt from the developed fields in Central Luconia. Complimentary to the existing in house completion selection guideline, the new guideline for carbonate lower completion and its implementation in this design has contributes by minimized risk uncertainty in developing carbonate reservoir to a controllable level, thus becoming reference for future similar development within PETRONAS.

What constitutes a marginal field varies greatly but it is certain that extended time periods of low oil prices only magnify the challenges in developing such fields as it can stir even the largest reservoirs to go from commercially viable to marginal. E field is a marginal development project that must contend with all these unique set of challenges. For many years the project struggled to achieve minimum thresholds for funding. To develop the field during a low oil price market represented a cost-opportunity whilst presenting a value challenge. It is an extremely challenging thin oil rim reservoir development, under a complex and heterogenous geological environment, involving six long-to-extended reach wells in a loss-prone karstified carbonate. While the well planning and design built upon the Operator's considerable experience in carbonate and long reach drilling in the region, the campaign remained unique as the characteristic resided beyond the envelope of what had been accomplished before. The key distrincions were the much longer lateral length and the combined scope to target the thin oil rim in addition to the gas cap, which was the first-time application in this area. This is where technology played a vital part, as an enabler for delivering a complex project in a competitive manner. This paper briefly describes the planning stage of the campaign to ensure that the project was competitively scoped and delivered a fit-for-purpose solution, with focus on the technology implementation to address specific drilling challenges. Furthermore, it explains how a robust front-end loading, replication, and strong collaboration were key to making developable what was previously uneconomic.

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 packing 1 (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.