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The term "resin," as used in this page, refers to an organic, polymer-based, solid plastic material. Resins do not contain a significant amount of a solvent phase (as do gels), and resins are placed downhole in a liquid monomeric (or oligomeric) state and polymerized in situ to the mature solid state. Oilfield resins are exceptionally strong materials for use in blocking and plugging fluid flow in the wellbore and/or the very near-wellbore region. The three classical oilfield resins discussed here have exceptionally good compressive strengths. Also, these three resins usually have good bonding strength to oil-free rock surfaces.
Fluid-Loss-Control Additives (FLAs) are used to maintain a consistent fluid volume within a cement slurry to ensure that the slurry performance properties remain within an acceptable range. The variability of each of these parameters (slurry performance properties) is dependent upon the water content of the slurry. If the water content is less than intended, the opposite will normally occur. The magnitude of change is directly related to the amount of fluid lost from the slurry. Because predictability of performance is typically the most important parameter in a cementing operation, considerable attention has been paid to mechanical control of slurry density during the mixing of the slurry to assure reproducibility.
Abstract The drilling industry faces several challenges related to downhole vibration; amongst the solutions introduced to alleviate those challenges, a unique Axial Agitation System is often considered. This paper qualitatively analyses the effect of the Axial Agitation System in directional drilling and quantifies how it addresses the above challenges observed in Rotary Steerable System (RSS) Bottom Hole Assembly (BHA) used in the 8.5 in. section in different wells of the ADNOC Offshore mature field. The Axial Agitation System consists of Axial Oscillation Tool which generates a pressure pulse from a valve driven by mud flow converted to axial motion by The Shock Tool. The system complements the rotational movement of the string by introducing gentle and consistent axial oscillating motion. The drill string moves around its rotational axis, oscillating along its axial axis reducing kinetic frictional losses from interaction with the wellbore, especially in directional and long lateral sections. The analysis consisted in comparing drilling dynamics metrics between wells with AAS in the drill string and offset wells without it, in the 8.5in hole section. As a pilot project, the system was introduced into Well A. Based on the successful tests in the pilot well; the system was also utilized in Wells B & C. The metrics include, but are not limited to, drilling activities, surface mechanical indicators, downhole data from the RSS as well as mathematical modelled algorithms. The results of the analysis of wells clearly indicate an enhancement into the drilling dynamics in terms of overall reduction in kinetic friction, improved weight transfer, less hanging and levels of torsional dynamics, shocks and vibration. The collateral benefits also included performance improvement, reduced non-productive time (NPT) and lower mechanical specific energy (MSE) to drill the section. The Axial Agitation System complemented very well with the rotary steerable system as well as other BHA components and delivered consistent performance in all three wells. High amplitude fine-tuned Axial Agitation System paired with RSS BHA creates a combination of a highly efficient directional system. The results are consistently performance with reduction in the shock and vibration levels in the environment. This also benefits in improving tool reliability, directional control while also optimizing the repair and maintenance costs for the downhole tools.
Abstract The Walloons coal measures located in Surat Basin (eastern Australia) is a well-known coal seam gas play that has been under production for several years. The well completion in this play is primarily driven by coal permeability which varies from 1 Darcy or more in regions with significant natural fractures to less than 1md in areas with underdeveloped cleat networks. For an economic development of the latter, fracturing treatment designs that effectively stimulate numerous and often thin coals seams, and enhance inter-seam connectivity, are a clear choice. Fracture stimulation of Surat basin coals however has its own challenges given their unique geologic and geomechanical features that include (a) low net to gross ratio of ~0.1 in nearly 300 m (984.3 ft) of gross interval, (b) on average 60 seams per well ranging from 0.4 m to 3 m in thickness, (c) non-gas bearing and reactive interburden, and (d) stress regimes that vary as a function of depth. To address these challenges, low rate, low viscosity, and high proppant concentration coiled tubing (CT) conveyed pinpoint stimulation methods were introduced basin-wide after successful technology pilots in 2015 (Pandey and Flottmann 2015). This novel stimulation technique led to noticeable improvements in the well performance, but also highlighted the areas that could be improved – especially stage spacing and standoff, perforation strategy, and number of stages, all aimed at maximizing coal coverage during well stimulation. This paper summarizes the findings from a 6-well multi-stage stimulation pilot aimed at studying fracture geometries to improve standoff efficiency and maximizing coal connectivity amongst various coal seams of Walloons coal package. In the design matrix that targeted shallow (300 to 600 m) gas-bearing coal seams, the stimulation treatments varied in volume, injection rate, proppant concentration, fluid type, perforation spacing, and standoff between adjacent stages. Treatment designs were simulated using a field-data calibrated, log-based stress model. After necessary adjustments in the field, the treatments were pumped down the CT at injection rates ranging from 12 to 16 bbl/min (0.032 to 0.042 m/s). Post-stimulation modeling and history-matching using numerical simulators showed the dependence of fracture growth not only on pumping parameters, but also on depth. Shallower stages showed a strong propensity of limited growth which was corroborated by additional field measurements and previous work in the field (Kirk-Burnnand et al. 2015). These and other such observations led to revision of early guidelines on standoff and was considered a major step that now enabled a cost-effective inclusion of additional coal seams in the stimulation program. The learnings from the pilot study were implemented on development wells and can potentially also serve as a template for similar pinpoint completions worldwide.
Tortrakul, Nichnita (Chevron Thailand Exploration & Production, LTD) | Pochan, Chatwit (Chevron Thailand Exploration & Production, LTD) | Kananithikorn, Nardthida (Chevron Thailand Exploration & Production, LTD) | Siripan, Thanapong (NOV) | Ching, Basil (NOV) | Jordnork, Duangkamon (NOV) | Zbaraskiy, Vasiliy (NOV) | Botton, Benoit (NOV)
Abstract This paper presents a method of reducing equivalent circulating density (ECD) while drilling using eccentric string reamers (ESR) with adjustable gage stabilizer (AGS) in Gulf of Thailand (GoT). Reduced ECD in slimhole is desirable when drilling depleted reservoirs as reduced borehole pressure can reduce or delay drilling fluid loss events. Delaying losses can allow well depth to be increased with the prospect of penetrating otherwise unrealized pay horizons and increasing reserves capture. Several methods of reducing ECD were considered but most solutions included changing drill string and/or casing design specifications with prohibitive cost. A low-cost, low operational-impact solution was needed. Hole-opening is a method of increasing annular clearance, but well delivery requirements of ~4.5 days per well necessitates a one-trip solution without introducing significant ROP reduction or negatively impact bottomhole assembly (BHA) walking tendencies. Further, the preferred solution must be compatible with a high temperature reservoir drilling environment and must not undermine drilling system operational reliability. A simple but controversial tool for hole opening is ESR. ESR’s are simple in that there are no moving parts or cutter blocks to shift, and operating cost is low. They are controversial due to uncertainty that the tool eccentricity and drilling dynamics will successfully open hole to the desired diameter. Given that the intent of this hole-opening application is limited to creating annular clearance for fluid, not mechanical clearance, the eccentric reamer solution was chosen for field trial and potential development. A tool design challenge was to create a reamer geometry with the desired enlargement ratio (6⅛-in. to 6⅞-in.) while drilling, and reliably drift surface equipment and casing without complications. The ESR design must efficiently drill-out cement and float equipment as well as heterogeneous shale/sand/mudstone interbedded formation layers without significant vibration. If successful, the enlarged hole diameter will increase annular clearance, reduce ECD, improve hole cleaning, and allow drilling depth to be increased to capture additional reserves The plug and play functionality of the ESR required no changes to the existing rig site procedures in handling and making up the tool. The ESR drifts the casing and drills cement and shoe track with normal parameters. The ESR is run with standard measurements-while-drilling (MWD)/logging-while-drilling (LWD) AGS BHA and is able to reduce ECD providing the opportunity to drill deeper and increase barrel of oil equivalent (BOE) per each wellbore. Performance analysis has shown no negative effect on drilling performance and BHA walking tendency. The novelty of this ESR application is its proven ability to assist in increasing reserves capture in highly depleted reservoirs. The ESR is performing very efficiently (high ROP) and reliability is outstanding. In this application, the ESR is a very cost-effective and viable solution for slimhole design.
Abstract Traditional evaluation of behind-casing cement bond quality prior to cement plug placement involves removal, storage, transportation, and disposal of the tubing completion string. This paper presents an innovative approach to verifying cement bond and subsequent cement plug placement. This method involves cutting and retrieving part of the completion string and deploying acoustic logging tools into the casing, followed by using the tubing as a cement stinger. The procedure described in this paper first involves plugging and cutting the tubing, followed by partial retrieval of the completion to expose the abandonment horizon, which may be an impermeable shale or salt layer. A radial cement bond log tool is conveyed on wireline out of the tubing cut in order to evaluate the cement bond behind the exposed casing section. The existing cement sheath is assessed in accordance to a cement evaluation criteria to determine suitability as a barrier. A balanced cement plug is pumped utilising the existing completion string rather than a dedicated stinger. The permanent barrier is then verified appropriately based on satisfying key metrics in the pumping operation before hanging off the completion tubing in-hole and progressing with the rest of the abandonment programme. In the case study presented here, the tool string design considered the need to pass completion restrictions, convey through production tubing, and remain centralised with up to 50-degree deviation. Analysis of cement bond log data indicated that bond quality was good and suitable to place an internal cement plug across the abandonment horizon. This satisfied a minimum of 200-ft coverage across the zone of interest. The existing deep-set mechanical plug placed in the tubing prior to tubing cut was utilised as a base for the cement barrier. A 2,000-ft balanced cement plug was successfully set across the zone of interest. The completion tubing was used as a conduit for cement slurry placement, eliminating the usage of a dedicated work string. At the end of displacement, the tubing string was pulled out of hole safely to approximately 500-ft above the top of the cement with the help of controlled-gel progression properties incorporated in the slurry design. Due to existing completion accessories, setting a through-tubing cement plug and tubing rotation is not an option. Expandable cement was pumped to mitigate natural shrinkage and enhance post-set cement expansion to ensure a competent barrier. The cement job objectives were achieved by meeting the cementation execution criteria with no requirement to wait on cement. This provides additional time saving to the well abandonment. The discussed approach has successfully realised a significant rig-time saving of approximately two days on each well. Going forward, the methodology has effectively been applied to multiple wells across the Southern North Sea (SNS).
Pytko, Mykhailo (UkrGasVydobuvannya) | Kuchkovskyi, Pavlo (UkrGasVydobuvannya) | Abdellaitif, Ibrahim (UkrGasVydobuvannya) | Franco Delgado, Ernesto (Schlumberger) | Vyslobitsky, Andriy (Schlumberger) | Balabatyr, Yerik (Schlumberger) | Rachid Haro, Raul German (Schlumberger) | Ahmim, Nacer Ridha (Schlumberger) | Garcia Cardona, Walther (Schlumberger)
Abstract This paper describes three coiled tubing (CT) applications in depleted reservoir wells, where full circulation and precise fluid placement were achievable only by using a novel solids-free loss-control system, such as abrasive perforating applications. It also describes the preparation work, such as laboratory results and mixing procedure performed to ensure successful implementation. The analysis of Ukrainian reservoir conditions by local and global engineering teams showed that in a highly depleted well, abrasive jetting through CT was the best option to efficiently perforate the wellbore. However, this approach could lead to later impairment of the gas production if the abrasive material (sand) could not be entirely recovered. Such a risk was even higher as wells were depleted and significant losses to the formation occurred. The use of solids-free fluid-loss material that was easy to mix, pump, and remove after the operation, was, therefore, critical to the success of that approach. In Ukraine, most of the brownfields have a reservoir pressure that varies between 50% and 20% of the original reservoir pressure. This is a challenge for CT operations in general and especially for abrasive jetting, which requires full circulation to remove solids. It also complicates intervention when precise fluid placement control is required, such as spotting cement to avoid its being lost into the formation. The perforation solids-free loss-control system is a highly crosslinked Hydroxy-Ethyl Cellulose (HEC) system designed for use after perforating when high-loss situations require a low-viscosity, nondamaging, bridging agent as is normally required in sand control applications. It is supplied as gel particles that are readily dispersed in most completion brines. The particles form a low-permeability filter cake that is pliable, conforms to the formation surface, and limits fluid loss. The system produces low friction pressures, which enable its placement using CT. Introduction of that system in Ukraine allowed the full circulation of sand or cuttings to surface without inducing significant damage to the formation for first time; it was also used for balanced cement plug placements. This project was the first application of the solids-free loss-control system in combination with CT operations. It previously was used only for loss control material during the well completion phase in sand formations with the use of drilling rigs.
Abstract Emerging technologies, stringent permanent well abandonment regulations, and increasing well complexity affect the way we execute well intervention operations. One of the major operators in the Netherlands had an objective to set underbalanced cement plugs in brine across a deviated section using managed-pressure equipment to overcome high reservoir bottomhole pressure. The project involved several challenges: large-diameter production casing with a requirement to maintain high shut-in wellhead pressure, complex wellbore geometry, operations from a workover rig with zero discharge allowance, corrosive salt environment, and small cement slurry volume. These challenges had to be addressed to complete well abandonment to minimize safety risks, maximize efficiency, and achieve compliance with industry standards and regulatory requirements. This paper discusses two case studies involving underbalanced pump-and-pull and conventional balanced plug placement techniques. Thorough analysis and risk assessment, engineering design approach, comprehensive laboratory testing, and fit-for-purpose surface equipment and downhole tools enabled flawless job execution and placement and achievement of long-term zonal isolation. The first well-barrier elements were successfully verified by tagging and pressure testing in both cases. Results of this study include the following observations and conclusions: Managed-pressure cementing was proven to be an ideal solution for a well abandonment in a reservoir environment of high bottomhole pressure. Highly magnesium-resistant cement slurry design should be considered when setting cement plugs across an extremely corrosive salt environment. Successful verification of the first well-barrier element simplifies operations for subsequent cement plugs. Cost-effective solutions for permanent well abandonment under challenging downhole conditions attracts increasing interest from petroleum engineers due to increasing well complexity and low oil prices that challenge the economics of wells, leading to abandonment. The current paper describes the challenging conditions under which the wells had to be abandoned, thorough analysis of the risks involved, and an effective solution. The design strategy, execution, evaluation, and results for these two wells are discussed in detail and will help to guide success and solve problems related to permanent well abandonment under similar challenging conditions.
Maiorov, K. N. (Izhevsk Petroleum Research Center CJSC) | Chebkasov, D. S. (Izhevsk Petroleum Research Center CJSC) | Antipin, D. V. (Izhevsk Petroleum Research Center CJSC) | Vachrusheva, N. O. (Izhevsk Petroleum Research Center CJSC) | Karachurin, N. T. (Rosneft Oil Company) | Lozhkin, A. G. (Kalashnikov Izhevsk State Technical University)
The article discusses the problem of optimal well placement, it is proposed to solve it using the Alpha Zero reinforcement learning algorithm, which has proven itself as an artificial intelligence for games and for solving optimization problems in quantum optimal control theory. It is assumed that it can be no less effective in solving the problem of optimal well placement. The main components of the algorithm that influence decision making are the Monte Carlo tree search and the neural network. To select the location of the next well, a limited number of simulations are carried out along the tree, the root of which is the current sector from which the selection is made. During simulations, different tree branches are explored and new nodes are added for unexplored branches. The neural network gives an estimate of the NPV for the unexplored variant branches and the desirability of the following actions. As states in our approach, we will consider sectors of a fixed size, taken from a hydrodynamic model (hereinafter HDM), calculated for the entire field. Each sector is characterized by maps of properties of the HDM cut along the contour of the sector. Additionally, a vector of economic parameters is set. Note that a great advantage of the chosen approach is that there is no need for a complete enumeration of placement options - only branches with good estimates are revealed more deeply. The results of the system prototype operation according to the developed algorithm are presented and a brief comparison with the results of a hydrodynamic simulator is made. The developed prototype showed correct operation for synthetic models during the placement of production wells. The proposed well placement algorithm has shown its performance, comparable to the results of the hydrodynamic simulator.
Wellbore tortuosity is a term that has steadily increased in relevance to the oil and gas industry over the past decade, but its importance is especially clear in the current environment. The convergence of several major global events--the ongoing COVID-19 pandemic and persistent weakness in commodity pricing--combined with the industry's general attitude toward rate of penetration as the performance driver is leading to wells of inferior quality being drilled. The issue of wellbore quality is exacerbated by the division among drilling, completions, and production as functional disciplines, leading to dramatically different objectives and methods of quantifying success in each project phase. In wells with high tortuosity, the drilling process and drilling efficiency are affected, as well as the effectiveness of the completions and production equipment in achieving reservoir return rates. Defining wellbore tortuosity in relevant areas, such as openhole wellbores, production tubing, or casing, is often a very difficult task; historically, it has been a technical area fraught with challenges and misunderstandings.