Most production wells currently drilled in the North Sea are in complex geological settings. In order to place the wells safely and effectively, drilling a successful production well requires an advanced technology and integrated proactive reservoir navigation approach, in addition to multiple data driven answer products from downhole tools. Extra deep azimuthal resistivity logging while drilling (LWD) tools can detect boundaries up to 30 m away from the wellbore given optimal resistivity conditions. Combined with multicomponent inversion modelling (MCWD), the data acquired are used to map multiple boundaries, individual sand bodies, reservoir thicknesses, and lateral reservoir changes. Borehole images aid in geosteering and are used to steer up or down based on structural boundaries identified on the image. Using wired pipe technology that provides telemetry rates good enough for memoryresolution data, the full resolution electrical image is available while drilling. Despite complex reservoir geometry in both external boundaries and internal sedimentary structure, it was possible to succesfully geosteer by using an integrated geosteering approach. Through MCWD inversion, it was possible to track a thin, highly resistive layer at the roof for much of the reservoir, which allowed for proactive geosteering, optimizing wellbore placement and mapping of reservoir volumes.
Ventura, Darryl (Baker Hughes Inc) | Murugesan, Sankaran (Baker Hughes Inc) | Kuznetsov, Oleksandr (Baker Hughes Inc) | Mazyar, Oleg (Baker Hughes Inc) | Khabashesku, Valery (Baker Hughes Inc) | Darugar, Qusai (Baker Hughes Inc)
AbstractThis paper discusses the synthesis of hybrid carbon nanotube (CNT) and carbon nitride (CNx) membranes for applications in flowback water filtration processes. Due to their intriguing properties, these nanocomposites may be a suitable replacement for conventional membranes found in spiral-wound filter cartridges. The membranes presented here offer a dual-filtration mechanism because nano-sized particulates are filtered out by the porous, high-surface area CNT membrane while charged ions are removed via the CNx particles. This membrane has also demonstrated a unique ability to bind to, and subsequently filter out, divalent ions such as zinc—a common component of completion fluid. In addition, the inherent physical properties of CNTs, such nanocomposites, offer enhanced chemical corrosion resistance and anti-fouling properties.
AbstractThe use of elastomers in oil industry extends over a broad range of applications including seals, packing elements, reactive rubber elements, stators, and pads. These applications require a variety of property requirements that may differ for dynamic and static applications or include a need for stimuli-responsive capabilities in certain tools.This research details the effect of nanofillers on elastomer properties for oil and gas components. The effects include enhancement of mechanical properties, wear resistance, thermal conductivity and heat expansion properties. In addition, effects of nanofillers on rapid gas decompression (RGD) resistance, chemical resistance to downhole fluids, and resistance to chemical aging at downhole temperatures were investigated.Advanced rubber nanocomposites formulations, based on Hydrogenated Nitrile Butadiene Rubber (HNBR) elastomers, were designed internally. Their properties were assessed using methods and techniques to qualify elastomers for downhole applications. Mechanical properties of elastomers were evaluated at room temperature and at 325° F, which is a maximum application temperature for HNBR elastomers. RGD testing was conducted according to ISO standards.Results indicated that it is possible to control mechanical properties of elastomers with nanotechnology, including improving the abrasion resistance of the elastomers by more than 100% in dynamic, wear-intensive applications, when compared to commercial compounds typically used in the oil industry. Thermal conductivity was improved by up to 40%, while heat expansion decreased by 30%, providing more versatility for seal design in dynamic applications which are prone to localized heating. In addition, RGD resistance in nanocomposites was examined and compared it to control samples. The industrial scale feasibility for nano-enhanced elastomers was demonstrated by a scale-up study.
AbstractThe extreme downhole environments of high-pressure high-temperature (HPHT) often lead to failures of the conventional rubber seals due to degradation and loss of elasticity. The application of metal-to-metal seal is also limited due to its small elasticity and demanding requirements of the harsh well environments. A novel Lattice seal technology, which is designed for sealing at 500°F, is presented in this paper. The Lattice seal material which is composed of a porous metallic structure with large elasticity (up to 30%) and a thermoplastic matrix was invented. Many advanced properties of the Lattice seal material, such as high elasticity, great extrusion resistance, excellent chemical stability, large expansion and incompressibility, were proven at 500°F. Prototype packers made of Lattice seal materials were designed, fabricated and tested. Finite Element Analysis (FEA) was used during the development for saving cost and shortening lead time, as well as for comprehensive investigations of the impacts of filler ring, setting forces, and differential pressures. The Lattice packer with a filler ring successfully passed the test at 450°F with 6,000 PSI differential pressure across the packer.
Coiled Tubing deployed Electrical Submersible Pumps (ESPs) have had a very short history in the oil and gas industry. The idea of installing a pump using coiled tubing was developed more than a decade ago which would allow the possibility of rigless operations and reduce the time for deployment/retrieval of the completion under “live-well” conditions. However, the initial attempts to define their economics were limited to comparing operational costs based on equipment and services, without considering the long term performance and gains over the life of the installation.
A new concept of power cable consisting of 3 mono-conductors has been developed in the past 2 years for deploying ESPs that eliminates the need for spooling and banding at the wellhead. The project has been a strategic development for ESP alternative deployment methods that would eliminate the need to move a work over rig on location to replace/service an ESP, making it more cost effective. A customer in Saudi Arabia has chosen the path of performing an initial recompletion of the well with this system with the benefits of the alternate deployment method during the periodic ESP replacements for resizing and wear out.
This paper outlines the details of the new cable deployed ESP system and the extensive considerations given to the deployment process to ensure safe and successful installation of the ESPs.
Electrical Submersible Pumping Systems (ESPs) are becoming an increasingly important artificial lift method. As reservoir pressures deplete and water cuts increase, the need for high volumes of production remains, and this technology fills a critical need. One of the key challenges faced by operators is how to most efficiently deploy and maintain these systems. Deploying ESP's on conventional jointed pipe is adequate for low pressure onshore wells but higher pressure or even naturally flowing wells, especially offshore, can be problematic. In many cases, drilling rigs are being utilized for these ESP installations, which is both costly and an inefficient use of drilling systems.
This paper describes the full-scale testing conducted on a new, step-change subsea boosting system that pairs an in-well electrical submersible pump (ESP) with a mini-processing plant. A typical subsea boosting application is demanding for several reasons, perhaps most importantly being higher free-gas fractions, and the potential for variable or slugging flow that is often associated with aging wells. The new system as tested, demonstrates how a near-standard ESP can be operated in such high-gas environments within a mechanical embodiment that is compact, easy to deploy and to redeploy should the original ESP no longer meet the boost requirements. This paper lists the tests conducted and the results obtained regarding the operational, electrical and control performance, the vibration response and finally the ease of assembly.
Peng, Y. (PetroChina Southwest Oil & Gas Field Co.) | Liao, T. (Baker Hughes Inc) | Kang, Y. (Amerlink Energy Development Services Ltd.) | Zhu, Q. (PetroChina Southwest Oil & Gas Field Co.) | Li, C. (PetroChina Southwest Oil & Gas Field Co.)
The operator in China Sichuan gas field is often faced with challenges of efficiently removing water from aged gas production wells in which reservoir pressure depletes and liquid loading problem ensues. Applying the proper dewatering method is essential to keep the well flowing and avoid water accumulating in bottom hole. Among the many proven dewatering artificial lift methods, ESP (Electric Submersible Pump) technology has its advantage in wells which need a high volume of water produced with maximum pressure drawdown, which are beyond the capability of other artificial lift methods. First introduced in year of 1984, the operator and ESP provider have made considerable progress to develop an ESP application method in the field through theoretical studies, field trials and regular production. This paper concentrates on discussing the ESP sizing and optimization practice to tackle the corrosive, extremely gassy, fluctuating liquid inflow environment typically seen in gas wells - an area used to be perceived as infeasible for ESP technology. The methodology of well selection, completion string design and production management could be used for reference where there are similar challenges with Sichuan gas field.
Electric Submersible Pump technology dramatically evolved to encompass wider inflow ranges and conditions. Production and reservoir data uncertainty represent critical hurdles for ESP selection, often resulting in improper sizing of equipment. The improper sizing may result in the ESP operating out of range, or, in the worst case, constraining the well's production. A properly sized and fit-for-purpose ESP is important for reliable operations and to avoid costly intervention and deferred production which negatively impact project economics.
Recently discovered reservoirs often present challenges with data availability and certainty. It becomes even more challenging if the reservoir is unconventional or if the data quality is questionable. This study encompasses an unconventional reservoir (recently discovered and a mature field), a deepwater subsea application and a field with limited and questionable data.
There are various statistical options to manage uncertainty. This paper presents a methodology to apply the probabilistic production analysis to ESP design. The methodology comprises the use of nodal analysis, statistics and specialized ESP software. The resulting ESP options are simulated to model performance over time. Finally, all the options and conditions are scrutinized to select the configuration that best optimizes the ESP system from production and reliability perspectives.
This work presents a novel geological interpretation methodology that enables a significant improvement of the vertical resolution description of a formation, going from the vertical resolution of a pulsed neutron geochemical mineralogy tool (of about 1ft) to that of an image log (of about half an inch or less). The presented methodology addresses this challenge by combining the mineralogical and sedimentological information to generate a high resolution record of the formation mineralogy which can be applied to thin bedded environments. The keystone to the philosophy of the method is that the spectral information recorded by the mineralogy tool is a weighted average of the mineralogy of each lithological component in the analyzed volume. Therefore, by using high-resolution image log to determine the proportion of each lithological component, their composition can be determined from the mineralogy log data. This methodology proves to be especially valuable for thin-bedded formation and complicated rock environments.
Presentation Date: Monday, October 17, 2016
Start Time: 1:00:00 PM
Presentation Type: ORAL
Cementing sour wells can be very challenging; even when best practices are followed, the integrity of the cement, casing, and/or tubing can be jeopardized. In such cases, challenging and costly remedial work is necessary due to the complicated nature of the environment. A safe, cost effective way to prevent the need for remedial work is the use of self-sealing systems; however, until now, there was no data that validated self-sealing systems’ capability to tolerate exposure to H2S. This paper focuses on the newly discovered ability for the self-sealing systems to withstand exposure to H2S while maintaining self-sealing properties.
To confirm that the self-sealing material is uninhibited by H2S, a gas mixture of H2S in nitrogen was bubbled through a mixture of self-sealing material and water. The concentration and rates used were picked to mimic a standard sour well’s condition allowing the testing to recreate the challenging well environment. The self-sealing material was then added to the cement slurry and transferred to the crack/seal equipment for testing.
The results from the experiment were compared to a self-sealing slurry with the same components but in which the self-sealing material had not been exposed to H2S. Both systems were able to seal multiple times, validating the ability of the exposed material to withstand H2S exposure. The finding from this study opens the door for self-sealing cements to address several kinds of corrosive gases. Because the system was able to withstand exposure to such a strong gas, it will likely be able to tolerate weaker corrosive gases such as CO2.
The discovery from this experiment promotes a new use for self-sealing cements. No longer will their use be limited to cracks in the cement matrix but also as an extra precaution when working in sour wells and corrosive environments.