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 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.

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.

Challenges associated with horizontal wells production in a barefoot or only standalone screen are well documented in the industry. Inflow control devices have been around for years and have been the answer to mitigate the challenges typically associated with heterogeneity in horizontal wells, as was applied in an offshore brown field in East Malaysia, Field S. However, as the field gets more mature, increasing production challenges posed by the reservoir leads to conventional passive inflow control device solution becoming less effective. Over time, as water production from the reservoir increases due to the rise of aquifer column, new infill wells have to be completed shallower and closer to gas oil contact to maximise recovery leading to risk of high gas production. The risk is further compounded by uncertainty in the fluid contacts in a complex dipping reservoir. In order to mitigate these challenges, Autonomous Inflow Control Device (AICD) was selected for Field S infill wells to control excessive gas production anticipated due to the wells placement. AICD's ability to choke production based on the fluid properties allows for improved flow control together with influx balancing from segmentation into compartments by swellable packers. In total, seven (7) horizontal wells were completed in an infill drilling campaign in Field S, with the wells placed at around 5 m from prognosed gas oil contact. AICD was installed with premium sand screen and swellable packers in the wells’ lower completion and has managed to control excessive gas production while enabling production at the targeted oil rate. This paper describes the implementation of AICD in Field S infill drilling campaign with challenges of complex dipping reservoir and fluid contact uncertainty. The workflow to investigate the feasibility of the candidate and the completion design process will be discussed. Well modelling (nodal analysis) using production data was performed to characterise the well performance and to understand the impact of AICD in controlling gas and inflow of producing fluid into the producing horizontal section.

The added value of greater reservoir contacts with horizontal wells will be minimisedby an uneven reservoir sweep along thewellbore as the well may intersect heterogeneous formationswith varying properties. This results in early water and/or gas production in thewell. These challenges can be mitigated by deploying Autonomous Inflow Control Devices (AICDs)that can manage the reservoir fluid influx alongthe wellbore and therefore optimise the performance of well.The design of the well completion with inflow control devices is oneof the important steps in field development planning with a strong influenceon the production profileand thereby the economics. An integrated workflow was followed to deliver successfully the first AICDapplication for PETRONAS-Malaysia in an offshore oil reservoir with huge uncertainties in remaining oilthickness and current fluid contacts. The workflow comprised pre-drilling studies including AICD flow looptesting, well candidate selection, flow performance evaluation (static/dynamic modelling) and post-drillinganalyses including real-time completion design, history matching and comparison ofproduction data with neighbouring wells. In the 2018 infill development campaign, improved productionwas targeted by the installation of AICDs in wells atoffshore Sarawak. AICD completions ensurebalanced contribution from all reservoir sections and limit gas and water production. The chosenhorizontal well was drilled in a very thin formation with the oil rim average thickness of 13ft, the thinnestAICD application to date. The well intersected two geological layers with differentproperties.Alarge gas cap and an aquifer were located above and below the well. The oilproduction from this well was expected to be impaired significantly due to a high probability of early waterand gas breakthrough, potentially within days or weeks. Two analogue wells drilled in 2013 suffer from both issues despite being completed with passive ICDs. Through teamwork between the companiesinvolved in the campaign, the well was successfully completed with an RCP AICD completion. The wellwas segmented in several compartments and a tailored AICD completions was designed to restrict theproduction of unwanted fluids properly. The AICD completion has delivered a 200% increase in oilproduction while it has significantly reduced GOR (up to 90%) and water cut compared to several offset wellswith various other completions.The AICD is an active flow control device that delivers a variable flowrestriction in response to the properties of the fluid and the rate of flow passing through. The lessonslearnt from pre and post-installation studies will be discussed here. The AICD completions enabled theoperator to implement an optimum reservoir drainage strategy that uses downhole control which willbe manipulated autonomously based on well dynamic condition instead of surface control.

Novel well completion technique is used to ensure dual tubing performed under fatigue condition in Field B TLP. Based on initial tubing stress analyses, the dual strings are under compression during production. Also due to the Single Combo Top Tension Riser (SCTTR) design, first in the industry, the riser must be isolated from hydrocarbon flow. All 10 producers completed to date were tensioned successfully using this technique. This paper discusses various methods of string tensioning and executing the completion.

Multizone single-trip gravel-pack (MZ-STGP) completion systems not only save rig time to complete wells with long multilayer intervals but can significantly reduce capital and operational expenditures by standardizing completion design and simplifying operation complexity. It can also help improve quality, health, safety, and environment (QHSE) performance for a long-term project development. This paper discusses a case history of an operator in Indonesia developing a major offshore field primarily with MZ-STGP completion systems to produce marginal reservoirs. A MZ-STGP system was selected to reduce multizone gravel-packing operation time as compared to conventional stacked-pack systems. The main focus was to standardize completion design and help improve system reliability and operational efficiency, which is associated with both logistic preparation and field execution. Despite exploring cost-effective solutions, operational safety—including well control, particularly for developing a shallow-gas field—was the number one priority, as usual. A new concept type of safe running system was developed and implemented as part of a field operation standard to help ensure a safe and efficient operation. Based on MZ-STGP system trial results and lessons learned during the early stage, a standard MZ-STGP completion instruction was approved and applied as a guideline to standardize completion operation and identify and mitigate potential operational risks quickly to improve safety, performance, and efficiency. By understanding the principle of MZ-STGP system limitations, the system-working envelope was expanded and refined without jeopardizing system reliability and performance. With more than 170 wells with MZ-STGP installation and more than 650 zones gravel packed in a 12-year time span, a case history review provides an opportunity to share lessons learned and fundamental success factors and explore the future of this technology.

A major operator manages multiple deep water projects in the Gulf of Guinea. This paper describes the latest 44-well project in Nigeria. The operator required an ISO 28781 qualified bi-directional subsurface isolation barrier valve (IBV) (Fig. 1) to be installed in each well. This work presents results of IBV deployment in the field. The wells were drilled and completed from sixth generation drillships. To comply with the operator's dual barrier policy, a bi-directional IBV was installed in each well to help ensure reservoir isolation for temporary well suspension or before running upper completion and tree installation. Careful attention to well fluid cleanliness, sound quality assurance/quality control (QA/QC), and operational procedures were considered paramount to successful remote opening of the IBVs and were identified as best practices by both parties. The IBV is run in the open position as an integral part of the lower completion. A collet shifting tool closes the ball isolating the formation, enabling inflow and positive pressure testing to be performed. The reservoirs are isolated by the closed ball in the IBV, allowing safe installation of the upper completion from a floating rig or well suspension without a subsea tree. The use of an ISO 28781 Type CC V1 qualified IBV provides both zonal isolation and fluid-loss control. Once a well is completed and the subsea tree installed, the IBV is remotely functioned to the open position by applying multiple tubing pressure cycles. The first batch of wells were drilled and completed with lower completions and suspended while waiting for subsea tree deliveries. Later, wells were drilled and completed with both lower and upper completions, and trees installed later from an offshore inspection maintenance and repair (OIMR) vessel. IBVs were successfully closed and inflow and pressure tested during the lower completion phase. IBVs are run in sieved non-aqueous based mud (NABM). Filtered high viscosity pills are spotted across the IBV before closing. Once closed, the casing above the IBV is displaced to filtered completion brine at a rate ensuring any debris is lifted to the surface. The wells remain suspended with IBVs closed until the operator performs flowback and injectivity testing from a drillship. Additional injectivity testing was also performed from an OIMR vessel. Well suspension duration with IBVs closed varied between two months and 2.5 years. All valves cycled opened without issues. Four coiled tubing (CT) interventions were performed in the field, passing through the open ball without issue, confirming the IBVs were in the fully open position. This paper describes full QA/QC and operational procedures, which led to successful deployment and excellent functionality of the IBVs.

Pressure testing completion tubing prior to setting the production packer has been an accepted procedure in the past. However, over the years, complications and time (cost) to run a plug (on slick line) in high angle wells plus the advent of premium tubing connection and use of torque-turn monitor has made that practice almost redundant. Reliance on a metal to metal seal provided by premium connection, mill end quality control and tubing thread inspection are the main reasons for avoiding completion tubing pressure test prior to setting production packer. This paper described the painful recovery, costing over US$ 4.8 million from a tubing connection leak despite the use of premium connection and torque-turn monitoring system. Troubleshooting the location of the leak is time consuming. Is the packer leaking or any of the completion components or the tubing leaking? In this case one of the 13 Cr completion tubing connection was leaky. The completion string had an Integral Tubing Conveyed Perforation gun below the retrievable packer so it was time consuming and risky to retrieve tubing completion with a life gun. Over 40% of tubing had to be rejected due to galled thread when the completion was pulled. A description of field trouble shooting the leak location is described. Analysis of the torque -turn graph and reasons for imperfect tubing make up causing the leak are discussed. Simulating field make-up process at the Yard and pressure testing the made-up premium connection are described. Lessons learned are presented.

After the successful delivery of two mammoth deep water projects in Sabah, Shell Malaysia turned its attention to develop cost competitive solutions to further develop and generate growth for small/marginal field development. The initial focus was to develop a low cost, minimal facility platform, which meets all the HSSE and operational requirements for a marginal gas field in Sarawak. To do things differently, new but proven technology had to be utilised and for this initial low-cost development wellhead platform, solar panels were employed to generate power for the platform facilities. Electricity generated by this technology is currently limited to 1200 Watts and due to this, the design of the controls of automation systems had to morph along with this limitation. Equipment such as pumps, control and safeguarding systems had to run on 24VDC supply. A low powered integrated control and safeguarding systems, limited to a power consumption of no more than 250 watts, suitable for installation and operation in outdoor hazardous environment, with temperatures reaching 50°C, had to be employed. Due to the power supply limitation, pressurised control rooms to house controls and safeguarding systems now are a thing of the past. And the design of the wellhead control panel was optimised by minimising the number of 24VDC pumps and utilizing pressure boosting regulators to achieve the different required pressures.

Completing well in a carbonate formation is often a big challenge due to occurrence of severe losses in highly fractured limestone formations. In some cases, total losses might lead to prolonged operation time and/or well abandonment with attendant cost implications. Traditionally, Loss Circulation Materials (LCMs) are used to combat losses before completion operation commences. However, there have been limited success with this approach especially in this case where Karst was encountered. Originated under Managed Pressure Drilling (MPD) system, Pressurized Mud Cap Drilling (PMCD) with continuous seawater injection was introduced in XT Carbonate Oil Development Project. Due to the subnormal formation pressure, seawater was injected continuously down the annulus to maintain the hydrostatic pressure of the hole while ensuring that no formation fluid or gas entered the well bore. By injecting at a rate higher than the loss rate, an artificially induced surface pressure allows for wellbore monitoring while completion assemblies are being deployed. Prior to running in Lower Completion, a composite bridge plug was set at deepest possible location in production casing instead of the conventional Downhole Deployment Valve (DDV) resulting in the savings of about USD 1 Million. Some modifications were made on initial completion string whereby a sacrificial motor and a bit were included in Lower Completion string design. With the well in static mode, this modified lower completion string which consists of mud motor, drill bit and pre-drilled liner was used to drill out the bridge plug effortlessly. PMCD mode with continuous sea water injection was activated once the plug has been drilled out and while Lower Completion string was run to Total Depth (TD). After setting the Liner Hanger Packer and closing Fluid Isolation Valve, the well was back to static mode and ready for wellbore cleanup and upper completion runs. Five (5) high temperature wells have been designed employing the above technique which resulted in significant savings in rig time and cost as well as formation damage reduction and increased operating efficiency. This paper summarizes the practical experiences gained during the planning and deployment of lower completion string with perforated liners in a total losses condition with PMCD .

Considering the scope of work necessary to batch-complete six wells within a tight deadline, the initial outline for an offshore Vietnam completion program required multiple slickline well interventions, not only while on the rig critical path but also during simultaneous operations (SIMOPS). This high frequency of well intervention added considerable time, cost, and potential risk to the overall completion campaign, warranting incorporation of an alternative cost-effective interventionless concept. Remotely operated barrier valves were evaluated and determined to be a low risk but high value-enabling alternative to running conventional plug-and-prong type barriers during the completion installation. The remotely operated valves' multiple open and close capabilities provided further efficiencies that could be achieved as part of the completion running phase, as well as during SIMOPS when the wells were flowed for cleanup and later suspended for four months until topsides were commissioned. Two remotely operated barrier valves were pre-installed in their respective nipple profiles (one above the production packer and one below) and run in each of the six completions. The upper valve added value by allowing the production tubing, which included gas lift mandrels, to be pressure tested to full working pressure before setting the production packer. The lower valve facilitated circulating the well to underbalance fluid before setting the production packer and then allowed for subsequent setting and testing of the packer from above. It was later used as a deep-set barrier, allowing blowout preventer (BOP) retrieval and christmas tree installation on the rig critical path before performing further operational steps during the planned SIMOPS. Using the remotely operated valves in the project provided significant rig time savings of 30 hours per well by eliminating 15 well interventions. This also contributed to reduced health, safety, and environmental (HSE) risks and non-productive time (NPT) potential that are historically associated with slickline-related activity. This paper illustrates, in detail, the completion installation practice adopted and the many benefits and added value the technology provided to the overall project, both on the rig critical path and during SIMOPS.

Berantai field is a Marginal field locatedoffshore East Coast of Peninsula Malaysia. Berantai is the first Risk ServiceContract in Malaysia with gas production commencing ca. 2 years after signingthe RSC. A minimum size unmanned Wellhead Platform was installed in 2011 accommodating18 wells in 9 × 36in. conductors. The Splitter Wellhead system is a 2 (wells) in1 (conductor) system and is selectedto assist in designing minimum size platform deck facilitating surface piping and manifolds for 3types producer (highpressure gas, low pressure gas, and oil wells). As the production ratedemand certain size production tubing be used, unconventional casing designconcentrically inside the 36 in. conductors has been selected in order to allowsuitable size production casing be used. Inconductor sharing wells, it is standard that the 2nd casing string is a guide(sacrificial) casing string terminating at the conductor shoe depth. In Berantai the Operator optedto set this guide string some 600 m deep in up to 60 degrees inclination, believed to be the 1st time this conceptis used. Extensive " offline" work in conjunction with batch drillingand completions allow the Operator to save significant time and cost. Accesories werebuilt andprocedures developed to allow a multitude of tasks, such as cementing casing, installing lower and upper landing ring, Xmas tree, slick line operationsperformed "offline"saving rigtime in the order of 48 hrs per well

Gas wells often produce sour gas (H 2 S) along with significant quantities of CO 2 , and when it is suspected that these conditions will be encountered, corrosion-resistant alloys (CRAs) must be used in completions. This paper discusses an unusual development strategy for an offshore gas cluster off Peninsular Malaysia. The planning for the project had to consider that the environment contained approximately 57% CO 2 in addition to H 2 S. To meet the needs of this project, a dedicated team from the operator and service/engineering company developed a completion strategy incorporating several "firsts" for this area. This paper will discuss the unusual completion strategies selected, why they were used, and the resulting success of the well completions. This was the first usage of 25Cr by this operator in Malaysia. Some of the changes included: Alloy 25Cr was used for all 3–1/2- and 4–1/2-in. completion equipment The equipment was rated for 5000psi and 7500psi The wells were completed without any issues relating to the use of any of the new strategies, and these have become the standard for all future Monobore/Dual completion wells with high CO 2 content and low H 2 S content for both upper and lower completions. The wells have been in operation for more than one year, and production has been as anticipated. This case history covers the early stage planning (including materials recommendation stage), technical design review, equipment design, CRA handling and equipment preparation onshore, CRA handling offshore, and completion execution throughout the campaign. Results of the operation from a mechanical perspective will also be presented.

The use of Dope-Free tubulars in offshore operations have been increasingly adopted by different operators since its debut in the North Sea in 2003. Dope-Free tubulars replaces the storage and running pipe dope historically used in Casing and Tubing by a dry coating applied on pipe threads in an industrial controlled environment. The elimination of dope simplifies greatly the supply chain of the preparation of Casing and Tubing for offshore increasing the efficiency, safety and lessening the environmental impact of the process. The main benefits of this technology are: - Improved Operational efficiency - preparation, running, pulling management of rig returns; - Reliability: connections are installed in a more consistent and repetitive manner as the coating is an industrial process replacing a manual operation; - Improve well productivity: eliminating the damage to the formation created by the pipe dope and Health Safety & Environment. Operators experience, after a short learning curve, showed great reductions in installation time, reduction on connections re-make ups and rejects, improvement on workers' Health & Safety conditions by eliminating unsafe tasks and creating cleaner work areas, and minimization of the Environmental impact. This paper describes the experiences and benefits of the use of Dope-Free tubulars in offshore operations in the main offshore oilfields including the North Sea, the Barents Sea, Brasil, Indonesia, Gulf of Mexico and the Persian Gulf.

This paper discusses validation and verification considerations for large-bore sub-surface safety valves, particularly with respect to use in natural gas completions producing high flow rates to 450 MMSCFD and beyond. With natural gas wells, it is generally desirable from an economic standpoint to use larger production tubing than typically used for conventional oil wells. The larger sub-surface safety valves used in gas wells are exposed to unique conditions during operation. An estimate of the expected production rate of a given gas well is written into the statement of requirements for completion equipment. Validation and verification of the valve design to meet these requirements is a great challenge for equipment designers and test agencies, particularly for high flow rate analysis and testing. Only a small number of facilities have the capability to meet the volume and pressure requirements for testing the closure performance of large-bore safety valves against high gas flow rates. Production gasses flowing through the tubing string encounter discontinuities in the form of stepped changes in diameter at each tubing connection. As these large-bore safety valves are in the full-open position, changes in the diameter from entry to exit are only slightly larger than those at the tubing connections. During closure, and especially closure while flowing, the transient state of the valve provides a significant discontinuity to the flow path in the immediate vicinity of the closure mechanism. Discussion of valve design utilizing various analysis models is provided to understand how these high rate flow characteristics affect valve performance. In addition to unique analysis methods, these large-bore valves also require physical validation to ensure reliable performance in high gas flow rate conditions. Validation testing for these conditions is highly desirable and lends additional confidence in the performance of these products in emergency high flow rate scenarios. By including the proper design and testing protocols as shown in an actual case history, these large-bore valves capable of high flow rate applications are shown as fit for purpose in the most demanding of gas fields.