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packer
Successful Customized Thru-Tubing Plug & Abandonment from a Light Well Intervention Vessel as an Alternative to Heavy Workover Operations to Reduce Time and Cost - A Case Study from Brazil
Boldrin, Rodrigo (Halliburton, Macaé, Rio de Janeiro, Brazil) | Martinez, Raul (Halliburton, Macaé, Rio de Janeiro, Brazil) | Nunes, Mauro (Halliburton, Macaé, Rio de Janeiro, Brazil) | Ayusso, André (Halliburton, Macaé, Rio de Janeiro, Brazil) | Vivas, Victor (Halliburton, Macaé, Rio de Janeiro, Brazil)
Abstract Since Brazil produced first oil from the Campos Basin (offshore) in 1977, several companies have tried to reduce costs and speed up their offshore interventions. This requirement is even more necessary as the fields mature with limited oil production. The operator's objective has always been to avoid interventions or increase the time between them for the duration of the wells’ life. When required, the normal way to perform these interventions has been by using heavy workover rigs, but during the last five years, this process has changed since Brazil started to perform these activities using Light Well Intervention Vessels (LWIV). These vessels allow a different approach to traditional methods of thru-tubing interventions while still meeting the requirements of local regulations. This paper describes recent thru-tubing techniques used in a mature field during a large P&A campaign. It shows the high potential synergy integrating a LWIV with Coiled Tubing (CT), Slickline (SL), Wireline (WL), and cementing technologies for use in Brazilian activities. CT equipment rigged up as the primary and selective intervention on a LWIV offers more flexibility between service lines, reducing time with safety and quality. This integrated solution applies since the most recent Electric (e-CT) technologies added to conventional tools, such as inflatable packers, slickline plugs, tubing punches, logging devices, and others, creates new procedures and capabilities to speed up the well intervention operation. Some jobs previously performed in over 45 days, can now be carried out in less than 13 days. Comparing this new offshore P&A thru-tubing technique with traditional heavy well workover interventions results in a significant reduction in Abandonment Expenditure (ABEX) when operations are performed through the production tubing, allowing the completion tubing to be left in the well. The method described in this paper, backed up with a detailed case study, illustrates the significant parts of the process, from cement placement preparation and slurry specifications to pumping through the CT into the wellbore and the cost reduction gained. Conclusions and recommendations offer more technical references for further similar applications.
Successful Pipe Recovery Solutions in Unique Stuck Scenarios for Coiled Tubing and Downhole Completions
AlMarzooqi, A. (ADNOC Offshore) | Faqir, A. M. (ADNOC Offshore) | Nasr, K. K. (ADNOC Offshore) | Bana, S. (Weatherford) | Baca Espinoza, I. (Weatherford) | Garzon, C. (Weatherford) | Abushamat, A. (Weatherford)
Abstract Considering the advancement of smart completions getting stuck downhole is a high risk in today's working environment. To avoid incurred costs in a rig and rig spread rates, it is eminent to have reliable and quick pipe recovery tools (PRT) and methods for special cases. To complete this challenge the nonexplosive plasma punchers and cutters play an important role. Convectional PRT utilizes HAZMAT materials and involves both HSE and logistical challenges increasing the delivery times to the wellsite for direct execution. This step is bypassed for non-explosive plasma PRT. The slim coiled tubing (CT) recovery puncher and cutter range from ¾″ to 1″ in size; applicable on 1 ¾″ - 2″ CT produces a clean cut for further fishing intervention. For unconventional cases where the standard tools cannot pass the slimmer PRT is required. Finally, a serious challenge is packer mandrels with cut/release windows < 1-2ft could be addressed by plasma PRT. The Adnoc Offshore real results include 4 successful CT recovery operations mobilized in under 24 hours and successfully executed as low as 10 hours of operating time. The plasma PRT also helped to recover the stuck dual completions with small restrictions and managed to cut at points with deviation >80 degrees. Moreover, the PRT can cut in any pipe condition such as in neutral, compression, or under tension allowing to perform the job prior to the rig move. Having the ability to cut in restrictive conditions with high accuracy, more than 100's successful nonexplosive PRT punchers and plasma cutter run with very high success rates. The non-explosive PRT can be air shipped by chopper to offshore locations minimizing downtime on logistics such as vessel availability, and weather challenges. It is fulfilling the governmental security requirements for HAZMAT logistics, storage, and handling that are restrictive to the explosives or chemicals PRTs.
Well Integrity Compliant, Innovative Dual Cut-To-Release Packer System Addresses Well Challenges in high profile wells for ADNOC
Mefleh, Issam Rezk (ADNOC Group, Abu Dhabi, United Arab Emirates) | Abdulla, Mohammed Fawzi (ADNOC Group, Abu Dhabi, United Arab Emirates) | Al Marzouqe, Muna (ADNOC Group, Abu Dhabi, United Arab Emirates) | MacKenzie, Alan (Praxis Completion Technology, Dubai, United Arab Emirates) | McMillan, Gordon (Praxis Completion Technology, Dubai, United Arab Emirates) | Sood, Atul B. (Praxis Completion Technology, Dubai, United Arab Emirates) | Hajiji, Fateh (Praxis Completion Technology, Dubai, United Arab Emirates) | El Sayed, Laith (Praxis Completion Technology, Dubai, United Arab Emirates)
Abstract This paper introduces a groundbreaking development in well completion technology - the Dual Packer Cut-to-Release (CTR) system. This innovative solution offers a superior replacement for the conventional pull-to-release dual packer, CUT-TO-RELEASE (CTR) technology. The key feature of the Dual Packer CTR lies in the integration of a defined cut window within the challenging geometry of a 9-5/8" × 3-1/2" × 3-1/2" production packer design. This integration provides unparalleled risk mitigation, ensuring optimal well integrity throughout the high-profile well completion process and its entire operating life. With recent advancements in the reliability of well intervention tools, the confidence level among operators in production and injection applications has significantly increased. The Dual Packer CTR technology leverages these improvements to offer a higher level of reliability and precision during the releasing (cut) process. Additionally, this technology enables precise zonal isolation, enhancing well performance and providing versatility for deployment in supported and unsupported wellbores. The paper discusses the development process, including the selection of field-proven technology and the rigorous testing and validation procedures carried out to ensure the packer's robustness and functionality. The successful implementation of the Dual Packer CTR in field installation further solidifies its position as a dependable and efficient solution for challenging well completion operations. Ultimately, this advanced technology provides operators with enhanced confidence and assurance for achieving successful production and injection applications.
- Overview (0.34)
- Research Report (0.34)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > Asia Government > Middle East Government > UAE Government (0.51)
Abstract High resolution micro-resistivity imaging has been available in the logging while drilling (LWD) industry for the last 15 years in water-based mud (WBM) systems. However, the recent introduction of LWD ultrasonic technologies means that high-resolution images and associated analysis are now available for both WBM and oil-based mud (OBM) applications. This paper details the deployment of a 4¾-in. LWD ultrasonic imaging service in a mature offshore carbonate field, in Abu Dhabi, and the assessment of images in WBM with micro-resistivity image comparisons. The 4¾-in. ultrasonic service combines borehole size and shape measurements with high-resolution radius and reflection amplitude images. The LWD tool takes advantage of drill string rotation to make a 360-degree scan of the borehole with each transducer. The ultrasonic sensor uses four transducers that operate in a pulse-echo mode. By firing simultaneously, the transducers provide a total of 2,000 traveltime and reflection amplitude measurements each second, enabling the creation of high-resolution images, even at high-logging speeds. The images were used to evaluate the suitability of the LWD ultrasonic measurements to enhance reservoir understanding, along with azimuthal high-resolution resistivity image measurements in WBM applications. The ultrasonic tool was run in tandem with the resistivity imaging tool on a recent well where an inflow control device (ICD) had to be installed. The ultrasonic images showed excellent agreement with the high-resolution resistivity measurements, illustrating bedding, natural fractures, and sedimentological features. The resolution of the reflection amplitude images enables identification of drilling-induced features on the surface of the borehole, highlighting the measurement's value in understanding the impact of bottom hole assembly (BHA) design on the quality of the wellbore in fine detail. The travel-time measurements provide detailed evaluation of the borehole size and shape, with a three-dimensional (3D) visualization of the wellbore illustrating the ability of the tool to identify borehole enlargement and breakout. These findings demonstrate the suitability of the ultrasonic imager to address wellbore stability issues, identify principal stress orientations, and aid completion design in real time by confirming swell packer positions. Comparisons between ultrasonic images and established LWD technologies highlight the suitability of the radius and reflection amplitude images to provide enhanced reservoir characterization in both WBM and OBM applications. Log examples show that high-resolution images can identify bedding features, confirm natural fracture types and provide assessment of borehole size and shape for wellbore stability assessment for better ICD completion design.
- Geophysics > Seismic Surveying > Borehole Seismic Surveying (1.00)
- Geophysics > Borehole Geophysics (1.00)
World Longest 7 in Single Trip for Multizones High Rate Water Pack Enhances Completion Strategy in Offshore Indonesia
Tokoh, K. W. (PT. Pertamina Hulu Mahakam, Balikpapan, East Kalimantan, Indonesia) | Jatikusuma, R. (PT. Pertamina Hulu Mahakam, Balikpapan, East Kalimantan, Indonesia) | Manalu, D. N. (PT. Pertamina Hulu Mahakam, Balikpapan, East Kalimantan, Indonesia) | Yudis, P. (PT. Halliburton Indonesia, Balikpapan, East Kalimantan, Indonesia) | Li, C. (PT. Superior Energy Indonesia, Jakarta, Indonesia)
Abstract Multizones Single Trip Gravel Pack (MZ-STGP) completion has been mainly utilized in Mahakam field in Indonesia since 2012 to present. The system has been used as a sand control solution for its cost efficiency, the ability to complete multiple pay zones in a single trip and to provide zonal isolation for production selectivity for typical unconsolidated sands, poor sorting, and uniformity coefficient as well as very high fine content. The cost escalates when this requirement happens for multiple zones that may require multi run which needs longer rig time. As of now, few of completions used to utilize the 9 5/8" system that normally require large bore and pumping more volume of fluid injected to deliver gravel pack slurry into wellbore. Meanwhile as part of drilling and completion cost efficiency, slimmer well architecture and completion system installation has driven by the needs for of a smaller borehole under various scenarios such as cases where 9 5/8" casing cannot reach planned depth and unlock additional reserves deeper below 9 5/8" casing shoe associated with well cost optimization for marginal gas wells at Mahakam. This paper reviews on successful execution of 7″ Multizones Single String Gravel Pack system deployment, high rate water pack design, lessons learnt and required mitigation on the system itself while ideal deliver gravel pack slurry have to be in place properly at downhole. Further optimization is the Multizones Single String Gravel Pack system developed to unlock more potential sandy reservoir drilled with multi zones gravel placement treatment in order to reduce the rig time and preserve smaller 7in multizones single trip system by extended top bottom assembly to 445 m and service pipe length up to 425 m as world longest 7" MZ-STGP system to achieve optimum well cost economically.
- Asia > Indonesia > East Kalimantan > Makassar Strait > Kutei Basin > Mahakam Block > Mahakam Field (0.99)
- Asia > Indonesia > East Kalimantan > Makassar Strait > Kutei Basin > Mahakam Block > Nubi Field (0.98)
Abstract The purpose of this paper is to share the lessons learned from a ballooning effect that occurred in a carbonate formation in the Middle East. Typically, ballooning is recognized as a gain/loss situation, but in this instance, the loss of mud was undetected, and a slight flow was observed and after that the well was shut-in. As the well was misinterpreted as a flowing well, the remedial operations took 15 days. The mud returns on the surface were only 0.3 barrels (bbls), and the well was immediately shut-in. The shut-in drill pipe and casing pressure increased simultaneously at the same rate. The kill mud weight was 80 pounds per square foot (pcf), and the circulation was performed using the wait and weight method. At the end of the circulation, the mud weight both in and out remained at 80 pcf, and no traces of oil and gas were observed during the killing operation. The well was circulated a total of 5 times, with a final mud weight of 109 pcf. Throughout the entire killing process, the same shut-in pressure behavior was observed. When the well was opened, slight returns were confirmed for a period of 5 hours. An ultrasonic bond log was taken to the 7" liner to rule out a possible communication with a formation with higher pore pressure than the 68 pcf mud weight, the ultrasonic cement bond log gave poor results due to eccentricity because of tough logging conditions (TLC) conveyance method where the tool lays down on the low side of the wellbore. To address the potential isolation problem, a balanced cement plug was squeezed, however the cement was not injected, fluid volume pumped and returned was the same. Finally, an inflow test was performed at different equivalent mud weights (EMW), confirming that a mud weight of 68 pcf is sufficient to effectively control the well. After determining the safe mud weight, the 6 1/8" section of the well was drilled to section total depth without any influx.
Design of Limited-Entry Completions Using Near-Wellbore Simulator for Effective Acid Stimulation of Heterogeneous Carbonates
Bedewi, M. (Halliburton) | Andreev, A. (Halliburton) | Khoriakov, V. (Halliburton) | Mogensen, K. (ADNOC Upstream, Abu Dhabi, United Arab Emirates) | Burke, R. (ADNOC Upstream, Abu Dhabi, United Arab Emirates)
Abstract Limited-entry liners (LEL) have predominantly been deployed in carbonate formations with only moderate variation in reservoir properties. In this work, a detailed numerical analysis was applied to investigate how the hole-spacing design can be tailored for effective stimulation of heterogeneous carbonate formations completed with long laterals. The base case is a well with a 10,000 ft reservoir section with a permeability of 1mD completed with a 4.5in LEL with 3mm and 4mm holes pre-drilled at variable hole spacing. A commercial near-wellbore simulator was used during this work, coupled with a new interface module, to study the flow distribution for a number of scenarios. The new interface module calculates a hole spacing which provides a desired acid coverage for each reservoir compartment, while honoring operational constraints such as not exceeding formation fracturing conditions, allowable surface pressure, maximum pump rate, as well as the number of joints with pre-drilled holes available onsite. Additionally, the module is designed to deliver a hole spacing promoting deeply penetrating wormholes from each hole in the liner. Finally, because stimulation takes place under transient conditions in the reservoir, a transient inflow model for horizontal wells was deployed to capture the reservoir response accurately. Skin reduction due to the acid-rock interaction is not considered at this point. The scenarios simulated demonstrate that swellable packers significantly dampen the impact of permeability variation by reducing annular flow. The initial hole spacing estimated for uniform reservoir properties in general does a good job of choking flow into high-perm zones, especially if the base line permeability is 10mD (higher reservoir quality). A high-perm zone at the toe has a larger effect than a high-perm zone at the heel because of the larger hole density. The 1mD base case design can accommodate reservoir pressure gradients of 500 psia without compromising the outflow profile, whereas a 10mD base case cannot. In the latter case, either the pump rate must be increased, or the stimulation must be postponed until the pressure gradient has reduced. The authors strongly believe that this work will help expand the operational envelope towards other reservoirs by providing physics-based guidance on how and when to modify the hole spacing for achieving an effective stimulation.
- Europe (0.94)
- Asia > Middle East > UAE > Abu Dhabi Emirate > Abu Dhabi (0.24)
Objective A case study of an application in Iraq is presented with the aim to show the versatility of a limited entry cluster port completion system to overcome specific well challenges with "off-the-shelf" equipment designs. To overcome a unique set of challenges, a fit-for-purpose lower completion was designed to stimulate a reservoir with an acid matrix treatment, cleanup the acid, and allow for future water shut-off with an electric submersible pump (ESP) and Y-Block in place. Following the case study, a discussion is presented of the application of the system in UAE to augment the already successful Smart Liner (SL) completion system. There are many similarities between the completion presented and the SL. Advantages of using the system discussed in this paper are discussed. These advantages include: Better acid placement – especially at the toe of the well Lower pumping pressure Higher pumping rates Re-closable nozzles allow for future shut-off of undesirable zones, water zones for example.
Metal Expandable Packer Secures the Integrity of a Cemented Casing Shoe and Protects the Caprock from Potential High Injection Pressures
Hazel, Paul (Welltec, Aberdeen, Uk) | Jacobsen, Brian (Aker Bp, Oslo, Norway) | Huse, Arve (Aker Bp, Oslo, Norway) | Rygh, Synnøve Lind (Aker Bp, Oslo, Norway) | Jørgensen, Paal Ludvik (Aker Bp, Oslo, Norway) | Lønning, Petter (Welltec, Stavanger, Norway) | Strømsvik, Frode (Welltec, Stavanger, Norway)
Abstract The Edvard Grieg platform and Solveig subsea field developments have four horizontal wells with a novel cap rock protection technology in place for water injection service. The 9 5/8" casing shoe is positioned within the cap rock providing the primary well barrier. However, the cap rock requires protection from potential out-of-zone fracturing during high pressure water injection. Options to protect and seal across the cap rock were cemented 7" liner, expandable cemented liner, or Metal Expandable Packers (MEP). With the MEP having the benefit of qualification to ISO 14310 and API 11D1. The 9 5/8" shoe was landed and cemented at the bottom of the cap rock, the mud weight lightened and the 8 ½" hole was drilled to Total Depth (TD). A single trip liner was deployed consisting of a liner hanger, a 7" casing with MEP and with contingency swell packers, positioned at the top of the injection reservoir, and 6 5/8" and/or 5 ½" sand screens with annulus flow prevention. The MEPs were expanded with 345 bar pressure after setting the liner hanger. On the Solveig wells, filter cake breaker fluid was reverse circulated across the reservoir and up the screen and landing string through an electric toe valve, before a ball valve was closed mechanically with an Radio Frequency Identification (RFID) tag operation as back-up. The MEP created a fracture propagation safety barrier between the top injection point and the casing shoe (bottom of the cap rock). This subsequently lowered the risk of out-of-zone cold water injection in a weaker zone between the cap rock and the injection reservoir. The solution also protected the formations behind the 9 5/8" casing up to the production packer location. Substituting the alternative cemented liner options with the MEP annulus barrier and anchoring system saved considerable rig time and cost with reduced operational risk. Maintaining the 8 ½" hole to TD avoided slim-hole related risk and maintained a standard casing program, while enabling 6 5/8" × 5 ½" screens for a considerably longer reach with respect to torque and drag. The overall injection capacity was increased due to the larger bore and lower pressure losses. The MEP can facilitate short "bursts" of water injection at pressures above the minimum horizontal stress of the reservoir rock, which can create new flow paths. This provides a contingency in the event of the Solveig "no flow back" filter cake breaker solution was not successful, or the Edvard Grieg production clean-up was not successful, or injection was not sustainable over time due to formation plugging. Many wells are challenged with depleted zones above, across or below the cap rock which often challenges the positioning of the production or injection casing shoe. The ability to achieve a competent well barrier and protect against out-of-zone injection and undesired fracture propagation is a valuable solution addition. This solution addressed the challenge, securing a more robust and long term well integrity situation at substantially reduced cost and risk. The operator is considering wireless pressure gauges above the MEP in future applications to consistently confirm the MEPs as working barriers against high injection pressures.
- Geology > Petroleum Play Type (1.00)
- Geology > Geological Subdiscipline > Geomechanics (0.75)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.96)
- Europe > Norway > North Sea > Central North Sea > Utsira High > PL 410 > Block 16/5 > Solveig Field > Skagerrak Formation (0.92)
- Europe > Norway > North Sea > Central North Sea > Utsira High > PL 410 > Block 16/5 > Solveig Field > Hegre Formation (0.92)
- Europe > Norway > North Sea > Central North Sea > Utsira High > PL 410 > Block 16/4 > Solveig Field > Skagerrak Formation (0.92)
- (10 more...)
Abstract Due to its complexity the Clair Field is a phased development. It consists of the Clair Phase 1 and Clair Ridge Platforms with prospects of Clair Phase 3 in future. The original development plan for the Clair Field was based on wells successfully targeting natural fracture networks to deliver enhanced production rates well above those the low-permeability matrix alone could deliver. Natural fractures drive productivity in Clair Field producers, so no hydraulic fracturing stimulation was envisaged. Therefore, it is unsurprising that initial stimulation efforts on the Clair Field targeted intervention-based hydraulic fracturing after the wells had been completed and put on production. However, several recent wells which did not encounter sufficient natural fractures have delivered production results below expectations. Consequently, this increased appetite for hydraulic fracturing to protect the base and provide additional production. Hydraulic fracturing has demonstrated its value in terms of production uplift for the Clair Field since the first well was hydraulically fractured in 2019. The first platform-based multistage fracturing on the Clair Phase 1 Platform was undertaken from the drill floor when no development well construction was taking place. It has highlighted that fracturing offshore as a wellwork campaign is an intensive and complex scope. On the Ridge platform the continuous drilling program is ongoing, driving requirements for simultaneous operations (SIMOPS). Increasing operational challenges to the next level, the next step was to perform hydraulic fracturing alongside an ongoing development drilling and completion campaign, driving the requirement to conduct all intervention operations simultaneously (SIMOPS) with minimal impact both to the rig and production operations. The first SIMOPS fracturing project was successfully delivered on the Clair Ridge Platform in 2022. It demonstrated the capability to perform a complex hydraulic fracturing intervention concurrently with an ongoing drilling campaign and production operations all while ensuring safe and reliable execution. Future intervention-based stimulations are planned on Clair Phase 1 and Clair Ridge and the lessons learned from the first two operations are key to delivering those efficiently. Striving for continuous improvement, the Clair team have developed plans to transfer stimulation operations from an intervention to an integral part of the well construction phase, immediately following lower completion installation. Changing to an ‘online’ fracturing execution approach greatly reduces both equipment and personnel on board (POB) required on the platform. New insights also include considerations on fracturing design and placement in naturally fractured reservoir as Ridge area of the Clair Field. This paper details lessons learned for dealing with pressure dependent leak-off for hydraulic fracturing in naturally fractured reservoir.
- North America > Canada > Alberta > Grande Prairie County No. 1 (1.00)
- Europe > United Kingdom > Atlantic Margin > West of Shetland (1.00)
- Europe > United Kingdom > Kimmeridge Formation (0.99)
- Europe > United Kingdom > Atlantic Margin > West of Shetland > Faroe-Shetland Basin > Rona Ridge > Block 206/9 > Clair Field (0.99)
- Europe > United Kingdom > Atlantic Margin > West of Shetland > Faroe-Shetland Basin > Rona Ridge > Block 206/8 > Clair Field (0.99)
- (3 more...)