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Pragma is bringing the industry’s first 3D metal printed, ultrahigh expansion bridge plug to market, the Aberdeen-based company said in a press release. Its patented M-Bubble bridge plug has successfully completed final lab testing and is due to begin field trials by the end of 2020. Initially targeted at both the plug-and-abandonment (P&A) sector and water shutoff applications, the first M-Bubble addresses a gap in the market for a lower-cost, fast-turnaround, permanent plugging solution, with a high pressure differential (3,000 psi) capability, the company said. The plug can be set without additional cement to save rig time and “waiting-on-cement” time, which can accumulate significant savings for the operator, especially in deeper, extended-reach wells. It also provides barrier-integrity reassurance when there is the possibility of a poor cement bond or cement channeling occurring on the high side of deviated wells, the company added.
Sakurai, Shunsuke (University of Western Australia) | Norris, Bruce (University of Western Australia) | Hoskin, Ben (Oilfield Technologies Pty. Ltd.) | Choi, Joel (Oilfield Technologies Pty. Ltd.) | Nonoue, Tomoya (Japan Oil, Gas and Metals National Corporation, currently, JGC Corporation) | Eric, May (University of Western Australia) | Aman, Zachary (University of Western Australia)
Natural gas hydrate has attracted interest as an energy resource capable of meeting the expected growth in global energy demand. Several key issues remain to be tackled to enable commercial production, one of which is gas hydrate re-association in production lines, where significant volumes of water are co-produced with free gas. To predict this behavior, we introduce a model and simulation tool tailored towards hydrate growth in water-dominant turbulent flow.
We have produced a model to predict the growth rate of hydrate in water dominant systems, integrated into an in-house pseudo-steady-state multiphase flow simulator, named HyFAST. This is a mass transfer limited model where the growth rate is limited by the dissolution of guest gas molecules into the water-continuous phase. It considers the effect of interfacial gas-water bubble surface area, the degree of turbulence on mixing, and changes in bulk viscosity caused by hydrate particle formation. The tool is deployed to estimate the hydrate volume formed in production lines during the second offshore methane hydrate production test in Japan.
Initially, the model was validated in an experimental study against flowloop data, where, at worst, model predictions showed order of magnitude agreement with experimental growth rates; following this the model was integrated into an overall flow simulation tool used for larger scale predictions. The offshore production test was designed to use two separate lines to produce gas and water, however, some gas was entrained into the water production line, posing a risk of re-association. As such, our primary focus was on this water production line, approximately 1 km in length, rather than the gas production line, which generally remained outside the hydrate stability region. Our simulation predictions showed that the hydrate volume in the water production line was less than 5 vol%. Coupled with flowloop data which showed that blockages did not occur in similar systems up to 20 vol% hydrate, this suggests there was not a significant hydrate blockage likelihood in the offshore production test. These initial results suggest that the model may scale well from lab to field, and that such simulation tools can prove useful in discussing the consequences of hydrate re-association.
A new model and simulation tool were developed to predict the rate and extent of hydrate growth in water-dominant flow. These were used to predict hydrate formation in both flowloop experiments and actual production lines. The validation results showed that the approach may prove useful in evaluating hydrate blockage propensity in future gas hydrate production.
Traditionally, rigs are positioned over a well from the moment the surface casing is drilled till the installation of the wellhead Christmas Tree. This resulted in the loss of precious rig time as the rig is idling during online cementing. However, in Field A, offshore of Terengganu, Malaysia, a new approach has managed to eliminate such inefficiency drastically. This paper discusses the employment of offline cementing techniques made possible with distinctive wellhead technology, that enabled a fast, efficient, and safe drilling and completion.
In this offshore drilling program, five wells were successfully batched drilled and cemented offline by ingenious planning and skidding of the rig. As the first well has reached its depth, offline adapters with pressure compatible cementing heads and accessories are installed on the wellhead. This allowed the rig to skid to the adjacent wells to continue drilling while the previous well was being cemented with the use of full bore offline cementing adapters. Full bore offline cementing adapters helped maintained familiarity by allowing the use of simple conventional wiper plugs. These offline adapters are compatible with both mandrel and slip hangers and have pressure bleed off and monitoring capabilities. These steps were then repeated in all of the wells, from the surface casing till the tubing of these mono bore completions. Besides that, production and casing hangers come with barrier plug profiles allowing plugs to be pre-made up and tested. This reduced installation time on the rig floor and ensure that there was a positively tested barrier, before nippling down the riser. Hangers with seals also allowed for a single trip installation, further reducing rig time.
The five wells were drilled and completed in record-breaking time at an average of 7 days per well and below budget, resulting in a time saving of 31 hours and 18.5% of cumulative savings. In conclusion, this wellhead technology introduced a new approach to drilling and completion allowing vast improvement to the field economics and profitability to the development of marginal fields.
Multiple attempts to commercially produce from a horizontal well in a challenging sandstone formation completed with the plug-and-perf method were rendered unsuccessful. An innovative stimulation strategy was proposed for the next candidate in an attempt to improve post-fracturing productivity. Three different types of proppant fracturing treatments were performed as a first-time application, including hybrid slickwater treatment, low-guar crosslinked treatment, and CO2 foam fracturing.
A hybrid design combining high-rate slickwater at the beginning and low-guar-loading crosslinked gel at the end of the treatment was pumped in two stages. This allowed minimizing the crosslinked fluid pumped while enhancing fracture half-length. Second, conventional low-guar fracturing was implemented in four stages. Crosslinked gel loading was reduced by 25% compared to gel that was utilized in offset wells. Finally, a CO2 foam fracturing design with a novel biopolymer linear fracturing fluid was implemented in the last stage. This reduced water consumption and improved the chance of increased gas production by yielding a higher-conductivity fracture network.
Friction pressure for CO2 foam was calibrated using bottomhole gauge data that was obtained with downhole gauges run prior to the calibration testing. The new calibrated friction numbers were then used for the bottomhole treating pressure calculation during the treatment. CO2 foam fracturing was found to be a significant success for this well based on multiple evaluation criteria. First, the use of foam helped conserve 1,000 bbl of freshwater compared to conventional stages. Second, the foam treatment allowed two times faster cleanup compared to other stages, based on cleanup time normalized over fluid volumes. Finally, production logging results showed that the foamed treatment achieved better production compared to other treatments in the well, considering productivity index (PI) normalized by the proppant mass, porosity, and zone mobility. The CO2 stage normalized PI was significantly higher than the other stages in the well. After the well was cleaned up, a production log was conducted, and it was analyzed to corroborate the higher production: 70% of the production contribution was seen from the CO2 treatment interval.
In most of the literature, estimates of the friction correlations for foams are based on empirical data. This paper gives the calculations of friction pressure based on field data. The combination of measured bottomhole data and post-cleanup production logging demonstrates the potential productivity improvements that can be achieved through novel design approaches. This type of data is rare in the industry and can help to improve the design of foamed fracturing treatments.
The Gorgon Foundation Project (GFP) development comprises of the Gorgon and Jansz-Io gas fields located in offshore Western Australia. To maintain gas supply, the Gorgon Stage 2 (GS2) project will expand the existing infrastructure with additional subsea production wells. The Gorgon Stage 2 (GS2) well architecture is designed to deliver a 7 5/8 in. tubing × 7 in. production liner Cased Hole Orientated Perforation completion (CHOP).
An unsuccessful production liner primary cement job resulted in an area of uncemented wellbore -casing annulus and a sand containing mobile water exposed. This led to the unresolvable uncertainty of water crossflow into adjacent produced sands. Under the current flow assurance restrictions, the risk of produced water could reduce production rates or require the well to be shut-in. To mitigate water flow potential, cement plug annulus impediments (baffles) were installed. The objective of these plugs are for reservoir management, not abandonment barrier plugs. This allowed an optimized scope for verification and contingency operations planned and executed.
This paper provides an insight into the collaborative efforts made by the Subsurface, Drilling and Completions (Wells) teams and Service Partners to plan and successfully execute two (2) Perforate, Wash and Cement plug jobs. Operations include the use of Tubing Conveyed Perforations (TCP) and Closed Loop Cup Type Wash and Cement tool, a first for Chevron in Australia. The cement plugs were deployed from a semi-submersible in ~220 m of water and placed at depths of ~5,700 mMD and ~5,500 mMD respectively, at inclinations of 60° and in high static bottom hole temperatures up to ~157°C.
The key challenges and lesson are discussed including planning to optimize swab cup integrity in high temperature operations.
In 2014 ConocoPhillips (CoP) decided to focus on the Jet-type perforate, wash and cement (P/W/C) technique as its primary permanent well abandonment method for setting a full cross-sectional cement/steel barrier. Following this decision, a quality improvement project was launched to prepare for a transition from Cup-type to Jet-type P/W/C to improve barrier plug quality. The initiative was presented during the Stavanger P&A Forum (PAF) conference October 2014 for information and to indicate for specific vendors that there were opportunities for participation.
The perforate, wash and cement method is complex and as with any cementing operation there is operational risk involved. This paper is written to share ConocoPhillips experience and learning from the improvement project which is still ongoing. It is specifically written for drilling engineers planning Jet-type P/W/C operation to help identifying key parameters to achieve a top-quality operation as well as managing the operational risk inherent to the operation.
Quality requirement in P&A operations? It can be a hard sell to argue for costly fluids, BHAs (bottom hole assembly) and TCP (tubing conveyed perforation) guns to plug off a depleted reservoir where the test of time is hundreds of years from now as the reservoir gets pressurized again. The latter is not the case in the Greater Ekofisk Area (GEA) where active water injection increases the average reservoir pressure quickly and the established production strategy is dependent on good isolation of abandoned wellbores.
To get a ‘’good’’ P&A plug you need to understand how to prioritize and control the variables such as cement properties, drilling fluid properties, drill pipe and BHA design, hole cleaning, ECD, displacement, TCP performance, operational sequence and many more. ConocoPhillips have made a structured approach to build a process which captures the basics of getting a high quality well abandonment plug. The displacement process itself has been modelled with computational fluids dynamics (CFD) software to understand key drivers for the placement of a cross-sectional P&A plug.
This understanding has been mated with the practical limitations from a standard drilling unit to get a robust operational plan. To ensure the quality is maintained from operation to operation, the process have been accurately described in a Best Practice document. The operation itself is checked against a QA form to verify that execution was performed according to plan. The QA form is then filed as part of the P&A documentation, similar as a casing test during well construction.
In the GEA experience a good P/W/C P&A plug is one set as per the Best Practice document where the operation is quality assured with an "all green" QA (quality assurance) sheet. A more tangible description is offered: After the operation the offshore cement sample which is contaminated with 10% mud will set up in the UCA (ultrasonic cement analyser) cell per programmed setting time plus no more than 3 hrs. The cement plug itself will be tagged at planned TOC (top of cement) +/- 20 ft. It will hold the positive pressure test to fracture gradient + 1000 psi. From time to time the plug will be drilled out. If that is the case, we expect to see an average weight on bit larger than 15,000 lbs for a 9 5/8’’ casing plug. The external well barrier element may be logged using a CBL/USIT (cement bond log) string or similar. In that event we expect to see "bond quality", which is a weighted interpretation of CBL, VDL (variable density log), flexural attenuation and pulse echo measurements as "good" to "very good" throughout the perforated section.
This paper is one of many discussing the P/W/C technique
Lost circulation is a major contributor to non-productive time (NPT). Any efforts to better understand the factors that lead to it and subsequently identify a suitable cure will translate to tremendous savings of time and money for operators.
Conventional materials such as calcium carbonate, nut shells, graphites and fibers are successful in curing many cases of seepage and partial lost circulation. However, there is a practical limit to the concentration of these materials used to combat the most severe losses due to the limitation of pumps and drilling assembly. In porous formations, high fluid loss squeeze pills have seen some success in reducing losses by forming a high compressive strength plug, but these pills do not have a good success rate in large fractures or vugular formations. Such challenges are better addressed by cross-linking pills, but even this solution does not always have a high success rate due to the low compressive strength of the formed plug.
The new phase-transforming loss circulation material (PTLCM) was designed to be pumped easily and achieve thixotropic behaviour under downhole conditions, resisting losses in the thief zone prior to setting as a rigid plug with high compressive strength. A setting-control additive ensures the LCM does not prematurely set. The additive is used at a concentration calculated by considering the time required for pumping and the bottom hole temperature (BHT) in the thief zone. After the LCM sets, a high compressive strength solid plug is formed that can resist fluid loss to the formation. The LCM has a high acid solubility of ~95%, making this system a viable option for deploying in reservoir sections, depending on the client requirement and well conditions.
This paper describes two recent successful applications deploying this novel technology.
Shan, Youngbin (EverGreen Energy Service, LLC.) | Gao, Wenxiang (CNPC Tarim Oilfield) | Wang, Xuelong (BHDC Korla branch) | Xu, Minglei (BHDC Institute of Engineering and Technology) | Cao, Cong (BHDC Korla branch) | Zhang, Chao (CNPC Tarim Oilfield) | Du, Hai (CNPC Tarim Oilfield) | Jin, Xiaohu (EverGreen Energy Service, LLC.) | Su, Xiaodan (CCDC Changqing DownHole Technology Company) | Wang, Wenxiong (New Technology Development Center, Shaanxi)
It is a great challenge for well integrity when a high volume gas production well is found with the production casing broken near the wellhead hanger resulting in high pressure communication between Annulus A and B.
The objective of the paper is to propose a new solution to establish a strong pressure barrier between annulus via a sealant system and to show that such a barrier has been proven to be durable for long time.
A proprietary resin sealant is the key technology and precise job planning and execution are also viewed as being vital to the success of treatments.
Because tubing flow pressure may reach up to 10,000 psi during production after recompletion, operator decided to pressure test the sealant barrier to 10,000 psi for a minimum of 30 minutes duration. If pressure drop during the pressure test is less than 100psi, then the well is allowed to be recompleted.
Several spots and squeezes of sealant eventually setup a strong pressure barrier and were pressure tested up to 10,000 psi in both A and B Annuli. There was no pressure communication at the other annulus in the 30 minute test period.
In the past six (6) years, the operator has tried several jobs to repair casing leaks but none were successful. It was the first time that a sealant system provided a solution to repair a casing leak and hold a high pressure differential.
During recompletion, the production packer failed to set but the operator decided to initiate production. A annulus pressure increased quickly and finally stabilized at 8700 psi. It is now a year since the job was completed in October, 2019, and B annulus pressure in has consistently remained at zero pressure. This has proved that the sealant technology can securely setup and provide a high pressure barrier which is valid for long term V0 sealing.
Sato, Ken (Waseda University) | Shinohara, Kenji (Waseda University) | Furui, Kenji (Waseda University) | Mandai, Shusaku (Mitsubishi Chemical Corporation) | Ishihara, Chizuko (Mitsubishi Chemical Corporation) | Hirano, Yasuhiro (Mitsubishi Chemical Corporation) | Taniguchi, Ryosuke (Mitsubishi Chemical Corporation, Now with Soarus L.L.C.)
It has been reported that hydraulic fracturing treatments with smaller cluster spacing and larger fracturing fluids volumes yield better production performance in Permian Basin, Bakken, and Eagle Ford. Degradable diverting agents can play an important role as temporary plugging materials for multiple, tightly-spaced fracturing operations. However, applications of degradable diverting agents are often limited to moderate to high reservoir temperatures. In this study, a new degradable diverting agent is developed for use in low temperature reservoir applications.
Butane-diol vinyl alcohol co-polymer (BVOH) which has controllable water solubility is evaluated as diverting agents for hydraulic fracturing treatments. Using a high pressure-high temperature filtration apparatus, filtration properties of BVOH diverting agents are measured for various powder-to-pellet ratios under a range of temperature conditions. Filter media with 1 to 3 mm width slots, that simulate fracture openings, are used for the filtration test. The filtrate properties are evaluated based on spurt losses and filtration coefficients for quantitative evaluation. An analytical diverting agent model that considers swelling of the polymer in water is also developed for evaluating the filtration process of multimodal particles.
The experimental results presented in this work indicate that the degradable BVOH materials can be used as effective plugging agents for fracture-like narrow slits. Based on spurt losses and leakoff coefficients obtained under different powder-to-pellet ratios and temperature conditions, the performance of the diverting agents is quantitatively evaluated. The optimum powder-to-pellet ratio for BVOH materials are determined to be 80 to 20. The experimental results also reveal that the degree of BVOH crystallinity provides a dominant effect on the solubility of BVOH powder. The test results also indicate that the diverting agent plug properties started degrading under the temperature greater than 140°F as designed. The BVOH diverting agent developed in this work provides effective diversion effects under low to moderate temperature conditions (e.g., 80 to 100°F). The analytical plugging and bridging model developed in this work, which takes into account swelling properties of the polymer, show very good matches to the experimental results.
The degradable diverting agent developed for low temperature applications improve operational efficiency and economics of multistage hydraulic fracturing treatments in shallow reservoirs and operations where immediate fracturing fluid flowback is required. The plugging and bridging model with bimodal particle system developed in this study helps stimulation engineers select and optimize diverting agent material types, particle size distribution, and diverting agent concentration for various well, stimulation, and reservoir conditions.
Behrenbruch, Peter (Bear and Brook Consulting) | Quoc Doan, Truc (Bear and Brook Consulting) | Triet Do Huu, Minh (Bear and Brook Consulting) | Duy Bui, Khang (Bear and Brook Consulting) | Kennaird, Tony (Bear and Brook Consulting)
A detailed comparison is made of the more recently developed phenomenological 2-phase Modified Carman-Kozeny (2pMCK) relative permeability formulation with that of the industry standard, the Modified Brooks-Corey (MBC) formulation. The purpose is to show the strengths and weaknesses of the two formulations and to demonstrate how their combined use can yield the most consistent overall result, the optimum choice as input to reservoir simulation.
A brief overview of the two relative permeability formulations is given first. Several laboratory data sets are reviewed by deploying the two models, validating the data and pinpointing potential problems. In some cases, both methods are used to extrapolate lab results to determine a more realistic residual oil saturation value and corresponding water relative permeability endpoint, particularly for samples involving fines movement. The apparent increased degree of curvature of the oil relative permeability is also often problematic and is typically related to pore-fill, requiring modification to laboratory defined relationships. A clear workflow is outlined on how to derive overall optimal results. Both methods show that if additional information such as independent wettability measurements are available, there is more confidence in final relationships derived. As evident, problems are typically associated with the second data point and the final one, start and finish of multi-phase flow measurements, necessitating adjustment in oil relative permeability curvature and the final endpoint data, residual oil saturation and associated water relative permeability. If the curvature of the oil relative permeability is excessive, MBC extrapolation is prone to failure. While the 2pMCK model does not show such shortcoming, the model cannot currently handle very large exponents. However, for most realistic situations, such limitation is not a problem. Another advantage of the 2pMCK model is its ability to pinpoint laboratory artefacts.
The concurrent use of the two relative permeability formulations gives a new perspective of relative permeability modelling and is particularly suitable for quality checking and analysing more challenging laboratory results. The approach has been computerised, allowing for ease of data handling, model comparison and consistency.