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Coring is essential to offshore exploration programs—but sometimes cores are taken from the wrong formation or return to surface in poor condition. One firm thinks it can solve these costly issues with a first-of-a-kind coring device that uses logging instruments that add accuracy and integrity. Pulled directly from the reservoir rock, core samples provide critical data used to determine how exploration should proceed. Until recently, core analysis remained old school, however, there is an ongoing transition to bring the process of core description into the digital age.
This paper outlines the capabilities and advantages of a 3 1/8-in. instrumented wireline tool designed for fishing or shifting in casedhole wells with up to 90,000 lbf with high precision and minimized tubular deformation.
Some fishing necks have ratings higher than maximum capacity for linear actuators of similar size. To maximize the pull force applied to the fish, it was necessary to intervene with a linear actuator with a capacity at least as high as the fishing neck, but without increasing diameter to the point that it did not fit in the tubing or through restrictions above the fish. It is additionally necessary to accomplish this high pull without damage to the tubular where the linear actuator reacts the force applied to the fish. This imposes a requirement on the anchor module to avoid applying excessive radial forces to the inside of the tubular.
A linear actuator was designed that has proven a pull capacity of up to 90,000 lbf to fish stuck tools without exceeding a 3 1/8-in. tool diameter. This module can achieve this feat with precision measurements on the force applied to the fish, the displacement of the fish relative to the tubular, the radial force applied to the tubular by the anchors, and the exact opening position of the anchors. It also carries onboard temperature and pressure measurements to detect changes in wellbore parameters when used for exercising stuck ball valves or sliding sleeves. Extensive simulations have been completed to aid in operational planning and ensure anchor pads do not damage the wall of the tubulars. Multiple anchor modules can be run in series to further distribute radial and axial loads if needed for thin-walled tubing.
The use of high-precision instrumentation and high-strength mechanical design enabled a linear actuator to accurately pull twice as much as similar linear actuators with the same physical dimensions. This allows wireline to complete fishing operations in casedhole wells that were previously inaccessible either because of force requirements or diameter constraints, surpassing coiled tubing capacity.
Well was spudded on Sept. 8th, 1991 as a horizontal oil producer offshore Europe. The lower horizontal completion had multi stage proppant fracs and the well was handed over to Production on Dec. 14th 1991. The well was worked over in November 2011 when the upper completion was changed and subsequently was shut in in February 2015 when it failed Subsurface Safety Valve (SSSV) inflow tests. As a result of the SSSV inflow test failures, it was treated with acid but without success and it was concluded that the flow tube was stuck in the open position possibly due to the presence of scale - as a result the decision was made to look into the possibility of reactivating the SSSV using wireline techniques. In October 2015 several gauge cutters, broaches and brushes were run in the well to clean scale down to the SSSV at 1560ft. A task Launcher was run into the well to treat the flow tube and reinstate the well into service, upon treatmeant with task launcher scale from above and dropped ontop of the task launcher and slickline was unable to move, and since it proved impossible to retrieve the tool string, a wire cutter was dropped and the slickline was retrieved - the fishing neck remaining was gauged and determined to be clean. Subsequently when the fishing tool string and HD pulling tool were run the fish was latched and some 50-60 jars applied without movement of the fish being seen. Acid was dumped on top of the fish and an additional 60 jars applied without success. By this time some 26 days of operations had been completed without any progress being made operations were suspended and Bridge Plug was set to secure the well.
Coring is a considerably costly drilling operation, but vital to retrieve valuable sources of ground-truth data in the oil and gas industry. To justify the high cost of this operation, essentially, cores should not undergo jamming and mechanical damage. Core jamming not only indicates an unprecedented termination of the operation, but also causes severe damage to the core column already taken in the barrel. This means that the cores cannot be retrieved with sufficient key performance indicators (KPIs); thus, it would not reliably represent reservoir properties. Reaching this significant target can be ensured not only by proper design, but also by online monitoring and investigation of the drilling parameters. This investigation predicated on several case studies in the Middle East to identify the effect of imperfect decisions made by the driller. Based on the experience and observations, the paper provides practical recommendations to alleviate the impact of such negative actions.
The drilling parameters observed in the mud logging data of six coring case studies (of several runs from three wells in carbonate reservoirs) were investigated at the depth interval just prior to jamming occurrence. These parameters consist of rate of penetration (ROP), torque, weight on the bit (WOB), rotary speed (revolutions per minute, RPM), circulation rate, and standpipe pressure (SPP). In this work, a main cause of the core jamming occurrences is discussed; that is, the improper drilling parameters application, as mismanaged by the driller. Finally, as indications of jamming, sudden variations of the drilling parameters at the specified depth were investigated. Such study can contributeto the better monitoring for future coring operations.
Based on the observations in six case studies
The case studies in this paper provide several observations and indications of core jamming occurrences in a limestone reservoir which can be attributed to non-optimized drilling parameters. The paper also provides several practical recommendations and measures to prevent core jamming and core damage.
Kumar, Amrendra (Schlumberger) | Gadiyar, Balkrishna (Schlumberger) | Parlar, Mehmet (Schlumberger) | Anikanov, Evgeny (Schlumberger) | Dikshit, Ashutosh (Schlumberger) | Rudic, Aleksandar (Schlumberger) | Woiceshyn, Glenn (Schlumberger) | Jurgensen, Camilo (Schlumberger) | Petukhov, Pavel (Schlumberger)
Sand control screens are typically installed with an internal string (washpipe) which, among other functions, provides a circulation path. In long horizontal wells, running a washpipe consumes considerable rig time and may limit ability to reach target depth. In cases where fluid losses are experienced after screen installation, isolating the open hole with a fluid loss control valve can take a long time. This paper describes a washpipe-free solution for screen installation using a check valve ICD.
ICD screens are commonly used to delay/restrict influx of unwanted fluids such as gas or water. The washpipe-free solution integrates a check valve with the ICD to prevent outflow through the screen during circulation and allow inflow through the screen when placed on production. This solution uses a check ball that seals against the ICD during circulation but falls back on a porous retainer plate during production. The check ball and retainer plate can be dissolved by spotting a reactive fluid inside the screen or made to erode over time with production.
Laboratory testing yielded the following results: 1) ICD with the check ball was shown to seal up to 5,000 psi, 2) Check ball and retainer plate can be dissolved by a reactive fluid which can be tailored to bottom hole temperature and required time of dissolution, 3) Pressure activation test demonstrated maximum differential pressure to seat the ball is less than 5 psi.
This check valve ICD solution has been applied worldwide in more than 35 wells, most of which were targeted to avoid running a washpipe. However, in two wells the technology was successfully used to set open hole packers with 5,000 psi setting pressure. Washpipe-free ICD screen installation with a dissolvable check valve and capability of setting hydraulic packer without washpipe or intervention in open hole are novel solutions presented in this paper.
AlJallad, Osama (Ingrain A Halliburton Service) | Dernaika, Moustafa (Former Ingrain A Halliburton Service) | Koronfol, Safouh (Ingrain A Halliburton Service) | Naseer Uddin, Yasir (Ingrain A Halliburton Service) | Mishra, Prasanta (Kuwait Oil Company)
The evaluation of carbonate cores is a complex task because of the inherent heterogeneities that occur at all length scales. Rock properties may be defined differently at different scales and this introduces a challenge in capturing the heterogeneity in a single rock volume. This research work studied whole core samples using multi-resolution imaging and advanced computations. The samples could not be directly measured by conventional techniques due to their fractured state and complex nature. The cores are Mid Cretaceous in age, derived from a giant oil field in the Middle East and are predominately composed of limestone with complex paragenetic history.
The core samples were first imaged by X-ray dual-energy CT in 3D at a resolution of 0.5mm/voxel. The whole core CT images revealed extreme heterogeneity along the sample lengths and showed varying distribution patterns of high and low-density textures. The selected plugs from those density textures were acquired to accurately represent the different flow phases in the whole core samples. The plugs were fully characterized by high-resolution X-ray CT images at 40 μm/voxel, thin-section photomicrographs, poroperm measurements and Mercury Injection Capillary Pressure (MICP). These analyses provided a detailed understanding of the geological and petrophysical variations within the different density textures in the whole core samples. Simultaneously, smaller-scale subsamples were obtained from the different porosity regions in the plugs and scanned at higher resolutions down to Nanoscale at 0.064 gm/voxel.
The measured plug porosity and permeability data provided accurate results in the low and high-density regions in the whole core samples. This data was then upscaled to the whole core images by populating the individual data in the different textures and solving for the Stokes equation using the Lattice Boltzmann simulation. The upscaling process accounted for the varying fractions of the flow units in the sample, their interaction and their effects on the overall whole core properties.
The dual-energy CT scans along with core visual inspection, thin-section photo-micrographs and mercury injection pore throat size distributions (PTSD), demonstrated that each density region had similar geological and fluid flow characteristics throughout the core intervals. The upscaled poroperm data for all the core intervals gave a linear trend with a clear increment of porosity and permeability as a function of the low-density phase in the core. The permeability KV/KH anisotropy ratios were digitally computed for all the core intervals and were found to vary from 0.44 up to 0.94, which reflects the relative presence and distribution of the high and low-density regions in the reservoir core samples.
The digital analyses of the data together with the effects of heterogeneity distributions in the core provided an improved understanding of the geological and petrophysical properties in these complex reservoir rocks that would not be possible by conventional methodologies. The analyses were carried out at the pore scale and the core scale, which would lead to more robust reservoir engineering applications and petrophysical modeling of such complex reservoirs.
Nikitin, Anton (Shell International Exploration and Production) | Durand, Melanie (Shell Exploration and Production) | McMullen, Adam (Shell Exploration and Production) | Blount, Aidan (Shell Exploration and Production) | Driskill, Brian (Shell Exploration and Production) | Hows, Amie (Shell International Exploration and Production)
Sustained E&P activity levels and slim margins on highly valued Permian Basin acreage drive operators to leverage information as much as possible and in ways not seen in the recent past. Data accuracy, especially in this fast-paced, competitive environment, is strongly desired. Core analyses provide subsurface static calibration, but the thick stratigraphic section comprised largely of sublog scale facies, challenges a cost-effective approach to collect sufficient calibration data.
Saturation determination is a key petrophysical deliverable that has multiple uses, including landing zone assessment. Calibration of saturation models may originate in several ways: proprietary or joint venture core, industry consortia databases, data trades with other operators, government databases, or publications. Internal and external reviews of subsurface model inputs have repeatedly shown that Permian Basin saturations, in particular, have a wide distribution and large uncertainty. Accurately measuring core fluid saturations in tight rock continues to pose significant challenges originating from the currently accepted laboratory methods, assumptions used to interpret those data and more broadly, due to increased relative uncertainty associated with tight, low-porosity formations.
For example, crushing core samples, which enhances fluid extraction in tight rocks, causes systematic fluid losses in the case of core samples of liquid-rich mudstone formations, which are not typically quantified. Instead, as-received air-filled porosity is commonly assumed to represent hydrocarbons that were forced from core during acquisition/retrieval due to gas expansion. Additionally, fluid extraction from commercially available retorting systems have widely variable fluid collection efficiencies (<100%) resulting in significant inconsistencies between the weight of collected fluids and sample weight loss during retorting experiments. The Dean-Stark technique removes not only water and oil, but an unknown volume of solvent-extractable organic matter, and it only allows for direct quantification of the extracted water volume. Finally, fluid and solid losses during handling in the laboratory are unassessed in current commercial laboratory procedures. The reconciliation of fluid volumes with fluid and sample-weight data delivered by either of the two techniques, i.e., retort or Dean-Stark, requires numerous assumptions about pore fluid properties, which are typically not verified through direct measurements. We demonstrate that such assumptions can lead to extreme uncertainty in estimates of water saturation.
To address such critical uncertainties, a new retort-based core analysis workflow using improved core characterization and fluid-extraction techniques was developed. In one advancement, this workflow employs NMR measurements systematically performed on all as-received and crushed samples to quantify fluid losses during crushing. This approach also uses a specially developed fluid collection apparatus with close to 100% fluid collection efficiency. In addition to these advances in measurements, the workflow is optimized to avoid fluid losses during sample handling and includes repeated grain density and geochemical measurements at different stages for quality control (QC). As a result, the new workflow reduces the uncertainties in acquired data and better addresses the assumptions, i.e., parameter corrections for fluid losses, in interpreting measured data into core total porosity and core fluid saturations. The workflow is demonstrated for a set of Delaware Basin Wolfcamp A formation samples and the results suggest that previous crushed-rock core analysis protocols underestimate water saturation by at least 30% or ~15 saturation units (s.u.) for this liquid-rich mudstone formation.