Analysis of Shunted Screen Gravel Pack Process and Calculation of Friction in Deepwater Horizontal Wells

Shunted screen gravel packing is a kind of technology which is difficult to complete gravel packing with the conventional method in low fracture pressure formation and long wellbore length condition. According to the characteristics of LS 17-2 deepwater gas field, the shunted screen packing tool was designed and the gravel packing process and packing mechanism were analyzed. The variation law of the flow friction, flow rate distribution in multichannel, and other parameters of the shunted screen gravel packing were analyzed and calculated. The friction calculation model of different stages of gravel packing was established. A gravel packing simulation software was developed to simulate the friction in different stages of shunted screen gravel packing. The parameters such as sand-dune ratio, pumping sand amount, packing length, and packing time in the process of packing were also calculated. In deepwater horizontal well gravel packing, the results show that the friction ratio of the string is the largest in the stage of injection and α-wave packing. While the friction increases rapidly in the stage of β-wave packing because the carrier fluid needs to flow through the long and narrow washpipe/screen annulus. Particularly when the β-wave packing is near the beginning of the open hole, the packing pressure reaches the maximum. The calculated results are in good agreement with the measured results of the downhole pressure gauge. The model and software can provide technical support for the prediction and optimization of gravel packing parameters in the future.

Evaluation of Latest Technological Advances in Sand Control Completions: A Case Study

Sand control poses huge financial loses during production operations particularly in mature fields. It hinders economic oil production rates as well as damages downhole and surface equipment due to its abrasive action. Excessive sand production rates can plug the wellhead, flow lines, and separators which can result in detrimental well control situations. This paper will provide a comparative study on various sand control mechanisms by reviewing the latest advancements in sand management techniques. This study evaluates the performance of through-tubing sand screens, internal gravel pack, cased hole expandable sand screen, modular gravel pack system, openhole standalone screen, multi-zone single trip gravel pack, slim gravel pack, and chemical sand consolidation mechanisms. Various field examples from Niger-Delta, Mahakam oil and gas block, and offshore Malaysia are examined to gain an insight about the application of aforementioned sand control methods for different type of reservoirs. This study enables the operator to tackle the sand production problem according to the well construction changes during the life cycle of a well. The internal gravel pack completion system delivers a prolonged plateau production regime in shallow depths. In high drawdown conditions, chemical sand consolidation completion incurs early water breakthrough and elevated sand production. Chemical sand consolidation technique yields better results in deeper formations and its placement can be improvised by implementing coiled tubing and diversion techniques for multi-stage treatments. Depending on the well inclination, gas-water contact, producing zone type and thickness, well age, and economy, the completion types out of modular gravel pack, openhole standalone screen, slim gravel pack, and through tubing sand screen is recommended accordingly. Acquiring offset data, well log analysis, particle size distribution and performing pressure tests will improve the data quality of the obtained reservoir properties. This will further help in the selection of the most suitable sand control method for the target reservoir.

An Industry First: Concept Selection, Material Testing, and Modelling Process for a Successful Managed Pressure Open Hole Gravel Pack Project

One of the major technical challenges to this project was placing horizontal open hole gravel packs (HzOHGP) within the narrow pore pressure to frac-gradient (PPFG) margin in the target reservoirs. This paper addresses the steps taken to overcome this challenge. To maximize the use of the narrow PPFG margin, the project combined a managed pressure drilling (MPD) system with low gravel placement pump rates made possible by an ultra-light-weight proppant (ULWP). Of the MPD systems available, the Controlled Mud Level (CML) system was selected over the Surface Back Pressure (SBP) system for several reasons. It enabled conventional gravel pack pumping operations and equipment and it accommodated the brine weight needed to inhibit the shales. A series of lab tests showed that the completion fluid density required to inhibit the reservoir shale reactivity was only possible using CML. An overall evaluation of CML showed that it was most suitable and offered the greatest flexibility for the gravel pack job design. The special ceramic ULWP had to be qualified and tested. The qualification testing ranged from standard API and compatibility tests to full scale flow loop testing. The flow loop tests were needed to measure the ULWP transport velocity for the target wellbore geometry. Understanding the transport velocity is critical for gravel pack design and job execution planning. Once MPD and ceramic ULWP were selected, the gravel pack placement operations were simulated to demonstrate that their features increased the likelihood of successfully gravel packing in the target reservoirs. Small PPFG margins decrease the probability of success of placing a HzOHGP. In the target formations, the pressure margin is insufficient to safely execute HzOHGP conventionally; instead, the project combined MPD and the low pump rates facilitated by using ULWP to control circulating pressures to stay inside the narrow margin and place the gravel packs. The integration of CML and ULWP into in a gravel pack operation to control circulating pressures has never been done. The concept and its successful field implementation are industry firsts.

Extending Gravel Pack Carrier Fluid Performance in Highly Deviated Well for 7-Inch Gravel Pack Completion without Shunt Tube by Using High Grade Suspension Gravel Pack Fluid in Mahakam Offshore

In unconsolidated sand reservoirs, proper sand control completion methods are necessary to help prevent reservoir sand production. Failure due to sand production from surface equipment damage to downhole equipment failures which can ultimately result in loss of well integrity and worst-case catastrophic failure. Gravel Packing is currently the most widely used sand control method for controlling sand production in the oil and gas industry to deliver a proppant filter in the annular space between an unconsolidated formation and a centralized integrated screen in front of target zones. Additional mechanical skin and proper proppant packing downhole are the most critical objective when implementing gravel packs as part of a completion operation. This paper presents a case history of Well SX that was designed as single-trip multi-zone completion 7-inch casing, S-shape well type, having 86 deg inclination along 1300 meters, 4 to 5-meter perforation range interval and 54 deg inclination in front of the reservoir with total depth of 3800 mMD. The well consists of 4 zones of interest which had previously been treated with a two-trip gravel pack system. While Well NX was designed as single-trip multi-zone completion in 7-inch casing, J-shape well type, 8-meter perforation interval and 84 deg inclination in front of the reservoir with total depth of 3300 mMD. The well consists of two zones of interest which had previously been treated with a single-trip gravel pack system. Both wells are in the Sisi-Nubi field offshore Mahakam on East Kalimantan Province of Borneo, Indonesia. This paper discusses the downhole completion design and operation as well as the changes to the gravel pack carrier which overcame challenges such as high friction in the 7" lower completion and the potential for an improper annular gravel pack due to the lack of shunt tubes in a highly deviated wellbore. In vertical wellbores, obtaining a complete annular pack is relatively easy to accomplish but in highly deviated wellbores, the annular gravel pack is more difficult to achieve and can contribute additional skin. Tibbles at al (2007) noted that installing a conventional gravel pack could result in skin values of 40 to 50, mostly due to poor proppant packing in perforation tunnels. Therefore, operator required to find a reliable gravel pack carrier fluid optimization for typical highly deviated wells to overcome the potential sand production issues by applying a single-trip multi-zone sand control system across both zones (without shunt tubes) along with the utilization of a high-grade xanthan biopolymer gravel pack carrier fluid. Laboratory testing was conducted to ensure that the gravel pack fluid could transport the sand to the sand control completion, large enough to allow for a complete annular pack and still allow the excess slurry to be circulated out of the hole. Electronic gravel pack simulations were performed to ensure that rate/pressure/sand concentration would allow for a complete gravel pack. All four zones in Both of Well SX and NX were successfully gravel packed with a high rate, relatively high sand concentration slurry. The well has not exhibited any sand production issues to date. The current production from both wells is above expectation and are comingled from the two primary zones. Multiple factors were considered during the design and operation of the sand control treatment. Those factors will be described in this paper, starting with candidate selection, completion strategy, operational challenges and treatment execution along with production monitoring of the well.

Non Selective Shallow Unconsolidated Well Re-Entry: Case Study in Mahakam Delta

Declining of shallow reservoir reserve urges efficiency effort to switching well architecture from zone-selective gravel pack completion to non-selective tubingless completion. However, zone management in tubingless completion is not as simple as sliding sleeve manipulation in gravel pack well. It requires proper zone isolation of closed zone such as setting plug, tubing patch, or squeezed cement. Therefore, optimum zone management need to be identified to be consistent with cost efficiency effort. Study in determining optimum zone management captured two nearly identic case of 3 zones of selective well and non-selective well. The well cost, production, and its net present value was compared to evaluate how the reservoir production is managed. Although selective well has higher initial well cost, but operation cost during the production is significantly low. On the other hand, even non-selective well has lower initial well cost, due to complication on zone management, non-selective well has higher operation cost. The total cost of problematic non-selective well could nearly reach the selective well cost. The complication is identified as downward movement, i.e. re-accessing previously isolated lower zone and isolating upper zone at once. However, this study suggests that strictly following bottom-up production strategy could potentially avoid the complication by 23% more efficient in production and cost index. Well cost efficiency is not only determined by lower initial well cost. All operating cost during production must be also considered. Optimum well management for both type of completion is a key parameter in order to control the cost efficiency effort. Therefore, well completion design selection must consider not only the cost and production, but also the operation excellence and capability during managing well production in its lifetime.

Technology Focus: Sand Management (October 2021)

Our industry is under pressure to produce cleaner energy. That is the mantra, more so than a few years ago. A recent report from the International Energy Agency suggested that all greenfield developments in the oil and gas sector should be stopped forthwith if we are to achieve the net-zero target by 2050. That essentially means that we squeeze what we can from the not-so-easy and mature reservoirs, many of which have sand-control problems. Perhaps that is the reason most operators are working ever harder to manage and produce such assets, a trend reflected in the number of papers written. More importantly, a large proportion of papers this year were on sand consolidation and through-tubing exclusion methods, which primarily target mature producing reservoirs. A few technology trends are becoming apparent. There is a move to gravel pack longer and longer horizontal sections. It is now possible to pack more than 7,000 ft with zonal isolation. Through-tubing sand-control remediation continues to evolve. Sand consolidation is moving toward nanoparticles, with a promise of better regained permeability. Further strides have been made in developing filters to achieve behind-screen compliance for better sand retention. Industry has been enchanted by what data analytics and machine learning can potentially offer, and perhaps rightly so. Several papers this year apply these tools to sand management. For those interested, I would recommend paper SPE 200949 and OTC 31234 as further reading. Unfortunately, from a sand-control perspective, I do not yet see a compelling narrative. One interesting statistic that I stole from a LinkedIn post is that the rising 3-year trend of papers in OnePetro on this subject has fallen dramatically between 2020 and 2021. I have not independently verified these figures, but it does tell a story. Is the excitement waning? Recommended additional reading at OnePetro: www.onepetro.org. SPE 203238 - Sanding Propensity Prediction Technology and Methodology Comparison by Surej Kumar Subbiah, Universiti Teknologi Malaysia and Schlumberger, et al. SPE 201768 - Using Artificial Intelligence for Determining Threshold Sand Rates From Acoustic Monitors by Srinivas Swaroop Kolla, The University of Tulsa, et al. OTC 30386 - Pioneering Slickline Deployed Through Tubing Gravel Pack in Malaysia: Successful Case Study and Lessons Learned by Ertiawati Mappanyompa, Petronas, et al.

Autonomous Inflow-Control Devices Boost Production While Managing Sand

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 30403, “Sand Production Management While Increasing Oil Production of a Gravel-Packed Well Equipped With Rate-Controlled-Production Autonomous Inflow-Control Devices in a Thin Heavy-Oil Reservoir Offshore China,” by Shuquan Xiong, Fan Li, and Congda Wei, CNOOC, et al., prepared for the 2020 Offshore Technology Conference Asia, originally scheduled to be held in Kuala Lumpur, 2–6 November. The paper has not been peer reviewed. Copyright 2020 Offshore Technology Conference. Reproduced by permission. A 2018 infill development campaign for a horizontal well offshore China targeted improved production through the installation of autonomous inflow-control devices (AICDs). However, because the well requires gravel packing to manage the sand, the integration of AICDs and the gravel pack was an issue. An integrated work flow was followed to deliver the AICD application successfully in an offshore heavy-oil reservoir with major uncertainties in remaining oil thickness and water/oil contacts. AICD completions ensured balanced contribution from all reservoir sections and limited water production significantly while the gravel pack kept the valves safe from the effects of sand. Field Description The field is a low-amplitude fault anticline oil field developed on the basement uplift. The structure is relatively gentle (Fig. 1). The reservoir lithology is mainly feldspathic quartz sandstone, with an average porosity of 22%, an average permeability of 397 md, a reservoir pressure coefficient of 1, an oil density of 0.92 g/cm3, and crude oil viscosity of 150 cp. The current methodology for gravel packing with ICDs/AICDs in the well uses a multiple alpha-wave technique whereby at least one conventional standalone screen joint is deployed at the toe of the well to provide a return path during the buildup of the alpha wave. The flow rate is reduced progressively to maximize the dune weight until screenout is observed. Once the gravel-packing operation is complete, the standalone-screen section at the toe is isolated before the well is placed on production. This technique does not allow a complete pack to be achieved and will allow more gravel to build up around the zonal isolation packers. This methodology is most applicable in unconsolidated sands with high net-to-gross reservoirs where borehole collapse will occur early in well life. One technique to provide sufficient flow path through the screen assembly is to integrate sliding sleeves into each screen joint. However, in long lateral wellbores, this may be prohibitively expensive and requires multiple manual manipulations as the wash pipe is retrieved. The use of a temporary bypass valve is recommended to enable standard gravel-packing operations to be performed with ICDs without significant additional cost, complexity, or compromise. The dissolvable material is used with a valve located within the ICD/AICD housing to provide a high-flow-area path from the annulus to the tubing during completion operations.

Paradigm Shift in Completion Limits: Open Hole Gravel Pack in Highly Depleted Reservoirs Drilled with Well Bore Strengthening Technology

Open Hole Gravel Pack (OHGP) completions have been the primary completion type for production wells in the Azeri-Chirag-Gunashli (ACG) field in Azerbaijan for 20 years. In recent years, it has been required to use well bore strengthening mud systems to allow drilling the more depleted parts of the field. This paper describes the major engineering effort that was undertaken to develop systems and techniques that would allow the successful installation of OHGP completions in this environment. OHGP completions have evolved over the last 3 decades, significantly increasing the window of suitable installation environments such that if a well could be drilled it could, in most cases, be completed as an OHGP if desired. Drilling fluids technology has also advanced to allow the drilling of highly depleted reservoirs with the development of well bore strengthening mud systems which use oversized solids in the mud system to prevent fracture propagation. This paper describes laboratory testing and development of well construction procedures to allow OHGPs to be successfully installed in wells drilled with well bore strengthening mud systems. Laboratory testing results showed that low levels of formation damage could be achieved in OHGPs using well bore strengthening mud systems that are comparable to those drilled with conventional mud systems. These drilling fluid formulations along with the rigorous mud conditioning and well clean-up practices that were developed were first implemented in mid-2019 and have now been used in 6 OHGP wells. All 6 wells showed that suitable levels of drilling mud cleanliness could be achieved with limited additional time added to the well construction process and operations and all of them have robust sand control reliability and technical limit skins. Historically it was thought that productive, reliable OHGP completions could not be delivered when using well bore strengthening mud systems due to the inability to effectively produce back filter cakes with large solids through the gravel pack and the ability to condition the mud system to allow sand screen deployment without plugging occurring. The engineering work and field results presented demonstrate that these hurdles can be overcome through appropriate fluid designs and well construction practices.

Industry First Openhole Alternate Path Gravel Pack Completion in HPHT Environment: Fluid Development and Case History

For offshore wells requiring sand control, Open Hole Gravel Packing (OHGP) with or without shunted screen technology is a common completion technique. Prior to this paper, there has been no application of shunted screen OHGP in High-Pressure High-Temperature (HPHT) environment due to lack of a viscous fluid availability in high-density divalent brines (> 14.6 lbm/U.S. gal). For the case study, the fluid requirements in terms of density and temperature were 15.4 lbm/U.S. gal and 265°F, respectively. The only brine option at this density was a blend of calcium chloride/bromide and zinc bromide. In this brine and density, none of the existing fluids work hence a novel polymer-based fluid had to be developed. The fluid had to pass the following tests a) rheology before and after subjecting to high shear of both uncontaminated and contaminated fluids at 3 different temperatures b) sand settling tests at 4 different temperatures c) Production Screen Tester to ensure the fluid does not plug the screens during the job. System Integration Tests (SIT) were performed to ensure the mixing equipment would be able to batch mix the fluid and actual pumping equipment would function properly with the fluid. The field trial planning included simulations, pre-job meetings, and fluid management plan. The job was executed as per the procedure outlined during pre-job meetings. This paper discusses laboratory development, yard test qualification, and successful shunted screen OHGP case history of a novel 15.4 lbm/U.S. gal viscous gravel pack carrier fluid.

Multizone Openhole Gravel Packing with Enhanced Shunt Screens and Zonal Isolation in High-Rate Gas Wells

A reliable single-trip openhole multizone completion can significantly lower capital expenditure (CAPEX) by reducing rig time and well count. Recent improvements in openhole packers and enhanced shunt screen technology have enabled multizone openhole gravel pack completions with complete zonal isolation. A multizone openhole gravel-pack completion was installed in the Julimar Field with an enhanced shunt screen system, shunted mechnaical packers (SMP) and shunt tube isolation valves (STIV), to provide improved operating pressure envelope and erosion tolerance. Well design was tailored to derisk the installation and optimize performance of the multizone completion. Extensive reliability testing was undertaken on all new technology for this project. Completions were installed as planned, and the main objectives of sand control integrity, production attainment, and complete zonal isolation with selective production were validated through post-job gravel-pack analysis and subsequent well unloading. The successful implementation of these technologies significantly reduced project CAPEX and enabled access to reserves that would otherwise have been uneconomical to recover. This paper discusses design, execution, and evaluation of the multizone openhole gravel pack (OHGP) completions installed in the Julimar Field. This includes methodology followed for multizone completion selection, development of a new high-temperature formate-based viscous gravel-pack carrier fluid, detailed completion equipment qualification tests, post-job gravel-pack evaluation, and initial well performance from well unload. It is the industry's first field case study of enhanced shunt screens with novel shunt tube isolation valves and high-temperature xanthan-based gravel-pack carrier fluid.