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A Customised Solution Using Catenary Coiled Tubing to Deploy a Gas Lift Valve Deepening System With Straddle Packers For a Challenging Horizontal Well Offshore Brunei
Lim, Hong Chean (Halliburton Energy Services Sdn Bhd) | Leong, Azemi (Halliburton Energy Services Sdn Bhd) | Azizan, Yusri (Halliburton Energy Services Grp) | Yusoff, Khairul (Brunei Shell Petroleum) | Sabri, Daniel (Brunei Shell Petroleum) | Hu, Ziwei (Brunei Shell Petroleum) | Adizamri, Rudzaifi (Brunei Shell Petroleum)
Abstract An offshore horizontal oil well was identified as having multiple tubing leaks and depleting reservoir pressure. Intervention was required to reinstate the well and optimize the gas lift system performance to maximize oil recovery. Various challenges were identified in the project design stage due to the horizontal well trajectory and its potential to cause debris obstructions combined with the absence of any capability to monitor downhole parameters. Software simulations were performed to determine the downhole reach limitations of the rigid tool string to ensure that the deepest Gas Lift Valve (GLV) could be successfully deployed to the target depth under live well conditions. The viability of safely deploying such a long Bottom Hole Assembly (BHA) from a limited deck space with a short riser height also needed to be resolved. To accomplish this while maintaining a double barrier on a live well without setting a deep plug and killing the well required detailed planning. A specific space out of the Coiled Tubing (CT) Pressure Control Equipment (PCE) was tailored to enable the simultaneous holding of a 350 meters long gas lift string while also allowing make-up of the packer assembly on surface. Due to the completion design not containing a suitable profile for depth reference with a conventional mechanical locator tool, the Real-Time (RT) catenary CT system was selected as an ideal method of achieving reliable depth correlation. The catenary CT system, equipped with a BHA containing various RT sensors such as pressure, temperature, compression, tension, inclination, Casing Collar Locator (CCL), Gamma-Ray (GR), and torque, was critical in monitoring the downhole parameters in this challenging trajectory to allow decision making and confirmation during the packer setting process. Despite the complexity of job design, preparation, and operational planning with challenges involving pumping, flowback, and the CT package set up in an offshore environment, this customized solution successfully deployed 350 meters of GLV deepening string with precisely set straddle packers to isolate the leak points without any issues. The completion of this project successfully reinstated significant production following a prolonged shut-in period, and gas lift performance was optimized for maximum oil recovery from the considerable remaining oil reserves in the reservoir. This project marked the first successful deployment of a thru-tubing GLV deepening system on a horizontal well for the asset operator. The catenary CT system was an effective solution that managed to safely achieve all of the objectives while overcoming all the challenges faced throughout the project.
Abstract HPHT wells are typically associated with high complexity, technically challenging, long duration, high risk and high NPT as many things could go wrong especially when any of the critical nitty- gritty details are overlooked. The complexity is amplified with high risk of losses in carbonate reservoir with high level of contaminants compounded by the requirement of high mud weight above 17 ppg during monsoon season in an offshore environment. The above sums up the challenges an operator had to manage in a groundbreaking HPHT carbonate appraisal well which had successfully pushed the historical envelope of such well category in Central Luconia area, off the coast of Sarawak where one of the new records of the deepest and hottest carbonate HPHT well had been created. This well took almost 4 months to drill with production testing carried out in a safe and efficient manner whereby more than 4000m of vertical interval was covered by 6 hole sections. With the seamless support from host authority, JV partners and all contractors, the well was successfully delivered within the planned duration and cost, despite the extreme challenges brought about by the COVID-19 pandemic. This paper will share the experience of the entire cycle from pre job engineering/planning, execution, key lesson learnt and optimization plan for future exploitations which includes an appraisal well and followed by more than a dozen of development wells.
- Well Drilling > Pressure Management > Well control (1.00)
- Well Drilling > Drillstring Design (1.00)
- Well Drilling > Drilling Operations (1.00)
- (11 more...)
A Breakthrough Solution to Set ESP Packer at Higher Inclination by a Creative Combination of Re-Designing Slick-Line Tool String, Completion String and Well Trajectory Saving up to 30% of Completion Time in a Middle East Depleted Oil Field.
Almuallim, Mustafa (SLB) | Ullah, Syed Zahoor (SLB) | Ruzhnikov, Alexey (SLB) | Silva, Paul (SLB) | Al Shaikh, Jaffar (SLB) | Agarwal, Rohit (SLB) | Al-Herz, Mohammad (SLB)
Abstract After years of oil production in the Middle East, conventional electric submersible pump (ESP) placement at inclination of 45° is no longer deep enough to enable inflow of hydrocarbons. As a result, in some fields a packer placement is pushed deeper and closer to a reservoir at 55°-70° inclination which negatively impacts the ability to set packer with conventionally slick-line run plug system. The paper provides information on technologies used to overcome challenges associated by use of creative solution of modified slick-line run tubing plug system aiming to set the production packers at high inclination, in excess of 45°. This optimized system eliminates risk of weakened slickline jarring action across deviated wellbore by optimizing landing plug design, completion string configuration and landing profile criteria at which plug is deployed to pressurize tubing and set completion packer. The manuscript discusses torque and drag modeling utilized to plan and monitor deployment of modified slick-line system across high deviated and extended reach (ERD) wells. Finally, paper concludes with a detailed deployment BHA, execution road map and contingencies. The abovementioned system was successfully implemented across 5 extended reach wells (ERD) with packer set at an inclination up to 70°. Revised approached enabled optimization of both slick-line BHA and completion string such, that cost is reduced by over 30% compared to other wells where packer was set with conventional approaches like coiled tubing and wireline tractor. Furthermore, time associated with completion operation has been reduced by more than 2 days. Utilized model of slick-line deployment is currently adopted by the operator as standard practice to set ESP packer across highly deviated trajectories for both multi- and single lateral extended reach oil wells. The document provides a novel approach to set production packer at high inclination by utilization of optimized deployment BHA comparing to more expensive and time-consuming alternative approaches. It also provides technical feasibility analysis for slickline deployment into wellbores of high inclination. The proposed approach can be implemented any project worldwide to optimize both wireline and slick-line operation and thereby improving the performance.
- North America > United States > Texas (0.28)
- Asia > Middle East > UAE > Abu Dhabi Emirate > Abu Dhabi (0.15)
Abstract A Dual ESP system is a redundant ESP concept that provides backup ESP system to be put on stream immediately if the primary ESP fails, which minimizes workover ESP replacement requirements and cost. An enhanced Dual ESP system for a harsh environment is installed to prolong ESP run life. These harsh environment Dual ESP system are equipped with full Metal-to-Metal Motor Lead Extension as well as H2S Scavenger seal sections on both upper and lower pumps to enhance their durability. Moreover, auto-check valves are included in the system to enhance dual ESP daily operation and maintenance. This paper will share the new dual ESP system design for harsh environments, enhancements, and successful applications in offshore fields. Two identical, complete, and independent ESP systems are installed with standard Y-Tool (bypass system). All if which was achieved by installing the Metal-to-Metal Motor Lead Extension (MLE) Dual ESP application which acts as backup ESP system to be put on stream immediately after the primary ESP fails. Thus, avails the well potential and postpones the requirement of workover rig mobilization to replace failed ESP. Backup dual-ESP system extend overall ESP system run life in areas with limited rig availability. The cutting-edge technologies that were deployed in this completion include: Metal to Metal MLE on both lower and upper ESPs, which proved the increase in the run life compared to the standard MLE. Severe Service Seals (H2S Scavenger Seals), which protects the motor from corrosive subsurface elements. Dual Y-Tools to allow reservoir intervention below the ESP through bypass for logging, acid job and any Wireline / Coil Tubing jobs needed. Non-Return Valve (NRV) which facilitate auto switching between the upper and lower ESPs eliminating the costly offshore barge and wireline conventionally required to install isolation sleeves and blanking plugs. Dual penetration bore Aflas Packer which allows using two cable penetrators and has an Aflas material for sour applications. This paper will provide in-depth information about each of the cutting-edge technologies deployed in this completion along with the added technical value of utilization. It will further provide the estimated significant cost avoidance achieved in offshore ESP fields following the deployment of this completion.
Abstract Slimline ESP technology advancement has been exceptionally fast in recent years. The development of high-speed and bottom intake slim ESP technology along with deep-set slim ESP packers has accelerated the deployment of slim equipment to overcome one of ESPs challenges, namely, the requirement of high production rate from wells that have smaller casing diameters. The journey to address this requirement started with the development of deep-set slim ESP packers and slimline ESP packer penetrators that were not available for small casing sizes. Likewise, in terms of the ESP system, the slimline technology had been developed only by a few ESP suppliers. In order to have a broader baseline, some additional suppliers were motivated to develop this technology based on current and future needs, as well as potential field implementations to test their product. This paper is focused on describing four main slimline technologies with the objective of stablishing their suitability, capabilities and limitations. From these 4 suppliers, there is a good selection in terms of rate capabilities depending on the application. Likewise, there are some differences in terms of wider field implementation record which depends on the technology development stage for each one of them. Additionally, two suppliers of deep-set slim ESP packers and slimline packer penetrators will be discussed. This paper describes four slimline technologies, detailing the challenges and solutions they offer in order to achieve the high desired production rates from wells with small casing diameter.
Horizontal Lateral Drilling and Completion with Openhole Gravel Pack through a Unique TAML Level-4 Multilateral Junction System: The Installation Case Study from South China Sea
Zhang, Wei Guo (CNOOC China Limited – Shenzhen Branch) | Rao, Zhi Hua (CNOOC China Limited – Shenzhen Branch) | Lei, Hong (CNOOC China Limited – Shenzhen Branch) | He, Yue (CNOOC China Limited – Shenzhen Branch) | Zhang, Leimin (SLB) | Huo, Ying (SLB) | Revheim, Kjell (SLB) | Shafiq, Umer (SLB) | Zhao, Geng (SLB) | Yu, Hua Jing (SLB) | Cao, Peng (SLB) | Zhang, Dong (SLB) | Bian, Jin Wei (SLB)
Abstract A Technology Advancement of Multi-Laterals (TAML) level-4 completion was installed in the South China Sea in 2022. The unique design of this multilateral completion system increased efficiency and reliability in drilling and completing the well and enabled selective production from the main bore, the laterals, or both. It also incorporated a safe way of combining an openhole gravel pack job with a multilateral application. The main bore was completed with 9.625-in. casing. An 8.5-in. sidetrack was drilled and completed by the TAML level-4 junction and 7-in. liner was cemented in place. The key components of this multilateral completion system are an anchor packer system to temporarily isolate the main bore; a sidetrack whipstock and milling system to drill through 9.625-in. casing for 8.5-in. lateral bore; a robust 9.625 in. × 7 in. TAML level-4 junction system that combines a main bore production tieback assembly, main bore junction assembly, lateral bore junction assembly, and a junction drilling diverter isolation system. A 6-in. horizontal lateral bore was drilled through junction. An anti-swab openhole gravel pack system was installed in the 6-in. horizontal section to prevent sand production. For selective production from target zones in each lateral, a 3.5-in. intermediate string was installed. A specially designed multilateral well shrouded shearable tieback seal assembly was run back into the lateral bore. A standard sliding sleeve (SSD) and landing nipple were installed above the tieback assembly. Comingled production is achieved by leaving the SSD open, and selective production is achieved from the lateral bore by closing the SSD. Selective production from the main bore is achieved by leaving the SSD open and setting an intervention plug into the landing nipple. The upper production string was completed with an electrical submersible pump system. In early 2022, the full system was successfully installed for the first time in the region with zero health, safety, or environmental incidents and zero non-productive time. The lateral bore 7-in. liner and TAML level-4 multilateral junction were installed in a single trip, and the 7-in. liner cementing operation and excess cement cleanout were completed efficiently in that same trip. The 6-in. slim-hole drilling tool and openhole gravel pack sand control system both passed the multilateral junction with no hang up issues. The intermediate tieback string was successfully run back into lateral bore. The successful installation of entire well completion verified the high reliability and efficiency of this robust 9.625-in. ×7-in. multilateral well completion system. A traditional multilateral junction only hangs one 7-in. liner inside the 9.625-in. main bore casing. In contrast, this robust new TAML level-4 junction system enables designing the main bore junction assembly and the lateral bore junction assembly separately; the two assemblies can be installed in the same single trip together with cementing operation. The openhole gravel pack operation was then performed in a conventional way through the 7in cemented lateral liner. This drastically reduced the overall operational risk, by separating the operational risk of installing the multilateral junction and the open hole gravel pack job. This newly designed junction system and separate gravel pack operation were key enablers to complete this well smoothly and safely.
- Europe > Russia > Volga Federal District > Bashkortostan > Bashkiria Field (0.99)
- Asia > China > South China Sea > Zhujiangkou Basin (0.99)
- Well Drilling > Drilling Operations > Directional drilling (1.00)
- Well Completion (1.00)
Abstract Different approaches and techniques were utilized in the industry to overcome challenges in sanding formations, including frac-packs, indirect fracturing, and resin coated proppants. Due to complexities in the results achieved, open hole multistage fracturing (OH MSF) with a sand control completion system was introduced with the goal of expanding the technology portfolio for controlling sand production and proppant flowback. Offset wells drilled in a prolific gas-bearing unconsolidated sandstone formation showed high sand and proppant production restricting the potential from these wells. Therefore, it was necessary to develop a new OH MSF completion strategy to address sand/proppant control and combine it with proppant fracturing at the same time. This paper highlights OH MSF technology that utilizes screened port sleeves capable of withstanding fracturing pressures and harsh environments. The new completion system consists of a hydraulic frac port opened by applying pressure in the first stage. In addition, the fracturing ports for the next stages are opened by dropping activation balls. Each stage needs to be equipped with a sleeve fused with a screen for sand and/or proppant control. Stages are separated by open hole packers for zonal isolation in the open hole section. It is an innovative system that combines MSF completion with sand control components. Due to the complex nature of the completion, rigless well intervention operations must be well planned, discussed, and conducted with close monitoring during all the operations. In particular, frac port opening/closing, sand screened sleeves opening with coiled tubing (CT) well interventions, proppant fracturing operations, and e-line production logging tools (PLTs). Besides, if the transmissibility is high with a high leak off and quick closure of fracture, then frac operations should be performed with the objective of creating a tip screen out (TSO) scenario to achieve good proppant packing close to the wellbore area. Production rates after completing proppant fracturing, CT milling, and shifting interventions exceeded the expectations without any sand or proppant flowback. The candidate well's rate remained higher than offset wells and no sand nor proppant were observed on the surface. The new OH MSF with sand control completion technology will enable performing OH MSF treatments in gas formations with a high sanding tendency. In addition, it helps to diversify technologies utilized to enhance production without producing formation sand or proppant. Utilization in the right candidate in conjunction with an optimum engineering approach and optimized design will ensure obtaining the benefits of this new completion system to overcome similar challenges.
- North America > United States (0.93)
- Asia > Middle East > Saudi Arabia > Eastern Province (0.28)
- Asia > Middle East > Saudi Arabia > Eastern Province > Al-Ahsa Governorate > Arabian Basin > Widyan Basin > Ghawar Field > Lower Fadhili Formation (0.99)
- Asia > Middle East > Saudi Arabia > Eastern Province > Al-Ahsa Governorate > Arabian Basin > Widyan Basin > Ghawar Field > Khuff D Formation (0.99)
- Asia > Middle East > Saudi Arabia > Eastern Province > Al-Ahsa Governorate > Arabian Basin > Widyan Basin > Ghawar Field > Khuff C Formation (0.99)
- (5 more...)
Application of New Technologies and Best Operational Practices to Accelerate the Learning Curve in Wells Drilled in the Ayatsil Field, Mexico
Merchan Nájera, Andrés Isaac (Petróleos Mexicanos, PEMEX) | Urribarri Romero, Orlando José (Schlumberger, SLB) | Jimenez Rangel, Hector Hugo (Petróleos Mexicanos, PEMEX) | Gonzalez Mendoza, Luis Daniel (Schlumberger, SLB) | Ramírez Fuentes, Erik Alberto (Petróleos Mexicanos, PEMEX) | Rodriguez, Efrain Jose (Schlumberger, SLB) | Zarate Vergara, Marco Antonio (Petróleos Mexicanos, PEMEX)
Abstract Today drilling wells is one of the biggest capital expenditures and is employed starting from exploration, delineation, initial wells for production, and fresh production incorporation when existing wells production have declined. The estimated cost for drilling new wells in Ayatsil field is around 20 to 25 MM $, which requires a high level of decision to achieve production goals without exceeding the budget assigned to the Ayatsil field. Therefore, to make the right decision requires an integration of multidisciplinary group of specialists (geologists, geomechanics, reservoir engineers, production engineers and drilling engineers) from well design to execution phases. This paper will illustrate the methodology and process applied by the operator to optimize the drilling stages and accelerate field production, as a result the operator developed the operational excellence project, that consist of five phases and being executed by a multidisciplinary project team. The drilling team has been successful in reducing the depth versus days curves from an average of 130 days in 2017 to an average of less than 58 days in 2022. The best performance achieved till now in terms of total meterage is 4,200 meters drilled in 51 days from the surface. The continuous improvement of the Ayatsil project has resulted in world class drilling performance. The success factors include standardized well design, performance improvement processes that was made possible by the multidisciplinary well decision team like, flat times efficiency. In addition, the outcome of this approach has resulted that 30 to 33 million dollars have been saved from the original budget in reduction of well costs and impulse the productivity of Ayatsil field.
- North America > Mexico > Gulf of Mexico > Bay of Campeche (1.00)
- North America > United States > Texas (0.68)
- Geology > Geological Subdiscipline > Geomechanics (0.68)
- Geology > Rock Type (0.47)
- North America > Mexico > Gulf of Mexico > Bay of Campeche > Sureste Basin > Campeche Basin > Ayatsil Field (0.99)
- North America > Mexico > Gulf of Mexico > Bay of Campeche > Sureste Basin > Campeche Basin > Ku-Maloob-Zaap Field (0.98)
- Well Drilling > Well Planning (1.00)
- Well Drilling > Drilling Operations (1.00)
- Well Drilling > Drilling Fluids and Materials (1.00)
- (6 more...)
Abstract The electric submersible pump (ESP) is one of the most reliable artificial lift methods for delivering high flow rates in oil wells. If well designed for reservoir properties, ESPs may run for several years before failing. Despite many ESP design advancements, electrical connections remain within the most prominent points of failure in high H2S environments. This paper presents an innovative approach to mitigate electrical connection failures by encapsulating the ESP system for extended ESP run life in high H2S environments. Following an ESP design review to explore current practices in mitigating ESP electrical-connection failures in sour wells, an innovative ESP system was designed to eliminate electrical-connections’ contact with well fluid. The ESP is connected from the top to a production tubing, encapsulated within a pressure-retaining pod, and located above a deeply set production packer. The motor head is designed to partially set outside the pod to accommodate electrical-cable connection, while partially encapsulated within the pod to deliver the necessary electrical supply to the ESP motor. The tubing-casing annulus (TCA) is then filled with inhibited-brine to protect the electrical connections. Experts in the field typically select special ESP metallurgy and electrical connections (i.e., metal to metal) in high H2S wells to extend the run life of ESP systems. Although the development of multiple versions of electrical connections can mitigate H2S attacks, field experience has shown progress in sour environments where ESP run life is not yet matching mild environments. Most efforts were made to minimize H2S attacks on ESP electrical-connections by developing robust ESP systems, but little to no effort was made to eliminate the risk. This challenge can be undertaken by encapsulating the ESP system to avert electrical connection contact with well fluid. Thus, it provided a radical solution to one of the most common ESP failure points in sour environments. The encapsulated ESP system is a new concept, for which a patent is pending, designed to address electrical connection failures for an extended run life in high H2S environments. This paper will discuss the background and design of the system and its potential to eliminate electrical connection integrity issues.
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (1.00)
- Production and Well Operations > Artificial Lift Systems > Electric submersible pumps (1.00)
- Health, Safety, Environment & Sustainability > Health > Noise, chemicals, and other workplace hazards (1.00)
Case History: Alternative Application of Casedhole Gravel Pack with Openhole Standalone Screen and Water Contact Isolation Using Swell Packers
Ghallab, Ahmed (Petronas) | Noordin, Farriz Ijaz (Petronas) | Mohd Zain, Siti Nur Mahirah (Petronas) | Abdul Shukor, Mohd Syaza (Petronas) | Mohd, Shamsulbahri (Petronas) | Thuzar, Myat (Petronas) | Ak James Berok, Sylvia Mavis (Petronas) | Tan, Agnes (SLB) | Chin, Jennie (SLB) | Mosar, Nur Faizah (SLB) | Barretto, Gladson Joe (SLB)
Abstract The original lower completion strategy for the 13 oil producer wells in X Field was open hole standalone screens (OHSAS). The lower completion string comprised 6⅝-in. premium mesh screens inside the 8½-in. open hole. On the basis of updated predrill well data, stakeholders decided to change the well design to a cased hole gravel pack (CHGP). This paper discusses the feasibility study that was conducted to switch the design, the justification used to maintain the original strategy but with an increased use of swell packers for better compartmentalization in the OHSAS design, and the production results of the completed wells. Based on the most-recent data, maintaining the original design would increase the risk of water breakthrough and subsequently lead to a loss of production. Furthermore, all past campaigns in X Field were completions with CHGPs. To address these concerns, additional studies were performed to evaluate the potential of using the existing inventory combined with the concept of mounting shunt tubes onto the 6⅝-in. mesh screens for CHGP and to evaluate increasing the quantity of swell packers using different swelling materials for OHSAS completions. The assumption was that with a sufficient number of swell packers placed in the open hole with the sand screens, which would create a higher differential pressure, zonal isolation could be achieved in an open hole similar to the effect of having a bypass barrier in a cemented cased hole completion. Studies have showed that installing shunt tubes for 6⅝-in. screens for CHGP poses additional risks because of the tight clearance inside 9⅝-in. casing, and they can only be mounted with two shunt tubes. Isolation between zones is achieved by means of multizone shunted cup packers. However, as a result of the long lead procurement time for the multizone shunted cup packers, this option requires expediting to meet the project timeline. However, simulations performed on the enhanced OHSAS design using an increased number of swell packers became a promising solution to overcome the water breakthrough problem. The challenges were to determine the optimal quantity of swell packers required and the precise placement along the open hole. Other challenges are increasing drag effect on high dogleg well to accommodate the large quantity of swell packers. Sensitivity analysis of swell packer quantity had been run and compare with existing successful track record to further optimize the completion design. To meet the budget and schedule for the campaign, OHSASs with swell packers were successfully installed in Q4 2021 to isolate the water contact zone in the first three wells. Additional swell packers and short screens were used to mitigate the water-production risk and enable the completion and isolation of thin zones. Well unloading was performed immediately following the completions, with positive results in terms of water production in two of the three wells. The production performance of these three wells will be evaluated to determine the sand-control design strategy for the remaining wells on the next platform in Q3 2023.
- North America > United States (0.68)
- Asia (0.68)
- Well Completion > Well Integrity > Zonal isolation (1.00)
- Well Completion > Sand Control > Screen selection (1.00)