Results
LITHOCODIUM MOUND IDENTIFICATION USING LWD IMAGE LOG AND QUANTIFIED CUTTING ANALYSIS VALIDATION WITH ANALOGUES
Perrin, Christian (North Oil Company) | Pointer, Chay (North Oil Company) | Al-Mohannadi, Ghada (North Oil Company) | Sen, Shantanu (North Oil Company) | Buraimoh, Muse Ajadi (QatarEnergy)
Lithocodium mounds are early Cretaceous sedimentary structures described in the literature from outcrops, however, never described in the subsurface. The objective of this work is to identify and characterize Lithocodium mounds in the subsurface along a 25,000ft horizontal well. Drill cuttings sampled at a 100ft interval are observed in thin sections to define and quantify key sedimentary indicators (bioclasts, facies, and texture). Logging-while-drilling (LWD) GR, density, neutron, and resistivity logs are acquired along with the LWD high-resolution borehole image (BHI) log. Bedding dips from BHI data, interpreted along the horizontal well, enabled the reconstruction of the reservoir paleotopography. In particular, the alternation of dip azimuth combined with the facies interpretation from the thin sections supported the interpretation of eight distinct mound structures. An assessment of their overall geometry confirmed the mound shape to be subcircular, consistent with the subcircular geometries observed in Oman at the outcrop. The inferred dimensions of the mounds are comparable with the Aptian Lithocodium mounds in Oman (3040m), and their intermound organization resembles that of the Albian mounds in Texas. This work demonstrates the value of analyzing cuttings to complement image log interpretation and the value of outcrop analogs for interpreting sedimentary structures. For the first time, the subsurface identification and characterization of Lithocodium mounds and intermounds are achieved.
- North America > United States > Texas (0.48)
- Asia > Middle East > Oman (0.45)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (1.00)
- Geology > Sedimentary Geology > Depositional Environment (0.93)
- Geology > Geological Subdiscipline > Stratigraphy (0.66)
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Seismic Surveying > Borehole Seismic Surveying (0.48)
- Well Drilling > Drilling Operations (1.00)
- Well Drilling > Drilling Measurement, Data Acquisition and Automation > Logging while drilling (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
Summary A survey program is designed for every well drilled to meet the well objective of penetrating the target reservoir and avoiding a collision with nearby offset wells. The selection of the wellbore survey tools within the survey program is limited in number and accuracy by the current surveying technologies available in the industry. This article demonstrates how a higher level of accuracy can be achieved to meet challenging well objectives when the accuracy of the most accurate wellbore surveying tools and technologies taken individually is insufficient. This high level of wellbore positioning accuracy is achieved by combining two independent wellbore positions of the same wellbore trajectory. The first wellbore position is calculated using the latest technology of magnetic measurement-while-drilling (MWD) definitive dynamic surveys (DDS). The accuracy of the MWD DDS can be further improved by minimizing error sources such as misalignment of the survey package from the borehole, drillstring magnetic interference, the use of localized geomagnetic reference, using high-accuracy accelerometer sensors, and a high-accuracy gravity reference. Furthermore, the MWD DDS inclination accuracy is improved using an independent inclination measurement from the rotary steerable system. A first wellbore position is calculated from the magnetic MWD DDS after applying in-field referencing (IFR), multistation analysis (MSA), bottomhole assembly (BHA), sag correction (SAG), and dual-inclination (DI) corrections to improve both azimuth and inclination accuracy. A second wellbore position is calculated using gyro-MWD (GWD) technology. The results and comparisons of multiple combined survey runs are presented. The highest accuracy of wellbore positioning had been proved in this successful case study by penetrating a very small reservoir target on an extended-reach well that was unfeasible using either the most accurate enhanced MWD DDS or GWD technology individually. The presented case study shows how the wellbore objectives of penetrating a very small reservoir target had been confirmed by logging-while-drilling images and the reservoir mapping interpretation of the client subsurface team. This gave a high-accuracy wellbore position during drilling and provided higher confidence in wellbore placement to maximize reservoir production without colliding with nearby offset wells. Wellbore survey accuracy limits a borehole’s lateral and true vertical depth (TVD) spacing, constraining reservoir production in those sections. In the top and intermediate sections, wellbore survey accuracy limits how close the wellbore can be drilled to other offset wells due to collision concerns. This directly impacts the complexity of the directional work and the cost per section. Combining independent wellbore surveys unlocks the potential to improve the wellbore positioning accuracy significantly. It demonstrates the highest wellbore positioning accuracy that can be achieved to date compared with the latest magnetic MWD surveys after correcting all known errors or compared with GWD.
- Europe (1.00)
- North America > United States (0.68)
- Asia > Middle East > UAE > Abu Dhabi Emirate > Abu Dhabi (0.15)
- Geophysics > Seismic Surveying > Borehole Seismic Surveying (1.00)
- Geophysics > Magnetic Surveying (1.00)
- Geophysics > Borehole Geophysics (1.00)
- Well Drilling > Wellbore Positioning (1.00)
- Well Drilling > Well Planning > Trajectory design (1.00)
- Well Drilling > Drilling Operations > Directional drilling (1.00)
- Well Drilling > Drilling Measurement, Data Acquisition and Automation > Measurement while drilling (1.00)
- Information Technology > Sensing and Signal Processing (1.00)
- Information Technology > Architecture > Real Time Systems (1.00)
Pipe Viscometer for Continuous Viscosity and Density Measurement of Oil Well Barrier Materials
Lima, V. N. (NORCE Norwegian Research Centre AS) | Randeberg, E. (Pontificia Universidade Catolica do Rio de Janeiro (PUC-Rio)) | Taheri, A. (NORCE Norwegian Research Centre AS (Corresponding author)) | Skadsem, H. J. (NORCE Norwegian Research Centre AS)
University of Stavanger Summary The barrier material is a crucial component for wells, as it provides mechanical support to the casing and prevents the uncontrolled flow of formation fluids, ensuring zonal isolation. One of the essential prerequisites for the success of cementing an oil and gas well is the efficient removal of in-situ fluids and their adequate replacement by the barrier material. The quality of the mud displacement is affected by both the density and the viscosity hierarchy among subsequent fluids. Consequently, accurate and reliable measurement of fluid properties can help ensure consistent large-scale mixing of cementing fluids and verification that the properties of the mixed fluid are according to plan. In this paper, we investigate the implementation of a pipe viscometer for future automated measurements of density and viscosity of materials for zonal isolation and perform a sequential validation of the viscometer that starts with small-scale batch mixing and characterization of particle-free calibration liquids, followed by conventional Class G cement and selected new barrier materials. Finally, a larger-scale validation of the pipe viscometer was performed by integrating it into a yard-scale batch mixer for inline characterization of expanding Class G oilwell cement mixing. In all cases, flow curves derived from pipe viscosity measurements were compared with offline measurements using a rheometer and a conventional oilfield viscometer. After a series of measurements and comparisons, the investigated inline measurement system proved adequate for viscosity estimation. The flow curve of the barrier materials showed results similar to measurements using a conventional viscometer, validating the proposed test configuration to continuously measure the rheological behavior of the barrier material. The pipe viscometer flow curves are generally found to be in good quantitative agreement with independent viscometer characterization of the fluids, although some of the pipe viscometer measurements likely exhibited entrance length effects. Future improvements to the pipe viscometer design involve the assessment of even longer pipe sections to allow full flow development at the highest shear rate range and possibly different pipe diameters to improve the measurement resolution of low-shear rate viscosity. Introduction The oil well cementing process involves placing cement slurries in the annular space between the casing and the rock formation. After placement, the cement hardens to form a hydraulic seal in the wellbore, preventing the migration of formation fluids into the annulus. In the placement process, the cement paste flows through the interior of the casing into the annular space that is to be cemented, displacing in-situ fluids as it is pumped toward the surface.
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (22 more...)
- Well Drilling > Drilling Operations (1.00)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid management & disposal (1.00)
- (7 more...)
- Information Technology > Sensing and Signal Processing (0.94)
- Information Technology > Architecture > Real Time Systems (0.67)
Summary Understanding gas dynamics in mud is essential for planning well control operations, improving the reliability of riser gas handling procedures, and optimizing drilling techniques, such as the pressurized mud cap drilling (PMCD) method. However, gas rise behavior in mud is not fully understood due to the inability to create an experimental setup that approximates gas migration at full-scale annular conditions. As a result, there is a discrepancy between the gas migration velocities observed in the field as compared to analytical estimates. This study bridges this gap by using distributed fiber-optic sensors (DFOS) for in-situ monitoring and analysis of gas dynamics in mud at the well scale. DFOS offers a paradigm shift for monitoring applications by providing real-time measurements along the entire length of the installed fiber at high spatial and temporal resolution. Thus, it can enable in-situ monitoring of the dynamic events in the entire wellbore, which may not be fully captured using discrete gauges. This study is the first well-scale investigation of gas migration dynamics in oil-based mud with solids, using optical fiber-based distributed acoustic sensing (DAS) and distributed temperature sensing (DTS). Four multiphase flow experiments conducted in a 5,163-ft-deep wellbore with oil-based mud and nitrogen at different gas injection rates and bottomhole pressure conditions are analyzed. The presence of solids in the mud increased the background noise in the acquired DFOS measurements, thereby necessitating the development and deployment of novel time- and frequency-domain signal processing techniques to clearly visualize the gas signature and minimize the background noise. Gas rise velocities estimated independently using DAS and DTS showed good agreement with the gas velocity estimated using downhole pressure gauges.
- North America > United States > Texas (0.68)
- Europe (0.68)
- Research Report > New Finding (1.00)
- Research Report > Experimental Study (0.93)
- Geophysics > Seismic Surveying > Seismic Modeling > Velocity Modeling (0.51)
- Geophysics > Seismic Surveying > Passive Seismic Surveying (0.35)
- Well Drilling > Pressure Management > Well control (1.00)
- Well Drilling > Drilling Operations (1.00)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- (2 more...)
- Information Technology > Sensing and Signal Processing (1.00)
- Information Technology > Architecture > Real Time Systems (1.00)
- Information Technology > Communications > Networks > Sensor Networks (0.86)
Abstract Driven by increased production rewards, multiple operators in the United States have been improving their unconventional wells by increasing the lateral length. Several "superlaterals" with lengths above 23,000 ft (7 km) have been drilled successfully in several U.S. basins. This paper describes the technical challenges to drill and run casing in superlaterals and the difficulties to make them possible in the Vaca Muerta unconventional play. Several mechanical and hydrodynamics models within the geomechanics constraints are combined with real-time data to illustrate the limitations observed in shorter wells and the steps needed to successfully deliver superlaterals. Drilling and running casing successful operational practices as well as "superlateral related" failures are also discussed. As the lateral length increases, torsional and tensional loads increase. Buckling also becomes a much larger problem to overcome. Geomechanical constraints are a major challenge, especially at higher mud weights. The stability margin becomes narrower when transitioning from a shorter lateral to a superlateral because hydraulic friction increases with the lateral length and the risk of losses is increased. Furthermore, wellbore stability is paramount to keep drag in acceptable values for a successful casing run. Conventional drill strings and casing configurations may not reach bottom and design changes are likely to be required. Better attention to the drilling and casing running practices is key to prevent catastrophic events. In Vaca Muerta, the geomechanical constraints are particularly important. Changes in the wellbore geometry and/or drill pipe size can be required to maintain an acceptable mud weight window. When Quintuco and Vaca Muerta are drilled in the same section, the use of Managed Pressure Drilling (MPD) has reduced the effect of the uncertainties on the pore pressure and allowed successful drilling of shorter laterals, but as the lateral length increases, MPD alone is insufficient to mitigate this risk.
- North America > United States > Pennsylvania (0.93)
- South America > Argentina > Neuquén Province > Neuquén (0.28)
- North America > United States > West Virginia > Appalachian Basin > Utica Shale Formation (0.99)
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- (24 more...)
- Well Drilling > Wellbore Design > Wellbore integrity (1.00)
- Well Drilling > Drilling Operations > Running and setting casing (1.00)
- Well Drilling > Drilling Operations > Directional drilling (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs (1.00)
- Information Technology > Architecture > Real Time Systems (1.00)
- Information Technology > Sensing and Signal Processing (0.88)
When oil prices tumble, upstream research and development projects are among the first casualties. Many are put on the shelf. Few are ever taken off. Then there’s what happened at Apache Corp. More than a decade ago, the Houston-based independent oil and gas producer, which following a restructuring is now a subsidiary of APA Corp., was among a small cadre of operators working at the fore of automated drilling technology. As a first adopter, Apache had gone so far as to develop a newbuild automated rig design for its onshore shale fields in Texas. Then in mid-2014, crude prices plummeted nearly 60% over a 7-month period. The heady days of $100/bbl oil were replaced by the era of “lower for longer,” derailing Apache’s ambitious plan to build its pioneering prototype. That could have been the end of the story. But less than a year after the ambitious capital project was scrapped, something else emerged in its place. While AI-based automation was out, Apache’s drilling team was given a chance to develop the next best thing: an AI-based drilling advisory system. “We saw that there was at least a small opportunity to do something more with our rig data—that 1-Hz real-time data—by combining it and mashing it up with contextual data so that it could be something useful,” said Michael Behounek, a former director of drilling, completions, and workover performance and leader of the project for Apache where he spent the past 13 years before taking early retirement. Now a managing partner of an upstream digital consulting startup called Emerja, Behounek spoke at the recent SPE Annual Technical Conference and Exhibition while presenting SPE 215132. The paper outlines how after 8 years that small opportunity turned into a 10% year-over-year reduction in drilling costs. The system, a presumed multi-million dollar value creator, was adopted across all of Apache’s contracted rigs in 2018, playing an increasingly important role in the drilling of more than 1,700 wells across a wide spectrum of geologies. This track record spans nine onshore and offshore basins, with deployments of the system in the Permian Basin, Egypt, Canada, offshore Suriname, and the North Sea. Behounek said most of the reported cost savings stem from the models’ ability to trim rig time by predicting problems that would keep drillers from staying on bottom and turning to the right. That said, the paper, which is coauthored by Apache’s software partner Intellicess Inc., emphasizes that “the system only enables the opportunity—it is the field personnel and engineers taking the proper actions and decisions offered by the system that deliver the improvement.” Apache has shared several papers about the various components of the advisory program over the years but the most recent offers a holistic view of the strategy that led to companywide adoption. Of the dozens of takeaways it offers, some of the biggest follow.
- South America > Suriname (0.54)
- North America > United States > Texas (0.54)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (21 more...)
- Well Drilling > Drilling Operations (1.00)
- Well Drilling > Drilling Equipment (1.00)
- Data Science & Engineering Analytics > Information Management and Systems > Artificial intelligence (1.00)
- Information Technology > Sensing and Signal Processing (1.00)
- Information Technology > Artificial Intelligence (1.00)
- Information Technology > Architecture > Real Time Systems (1.00)
Integration of RCA and SCAL with Image Logs Leads to a Unique High Resolution Technique to Evaluate Laminated Clastic Reservoirs of Black Sea, Turkey
Isdiken, Batur (Türkiye Petrolleri Offshore Technology Center TP-OTC) | Dutta, Tanmoy (Türkiye Petrolleri Offshore Technology Center TP-OTC) | Yüce, Ugur (Türkiye Petrolleri) | Kiliç, Mert (Türkiye Petrolleri Offshore Technology Center TP-OTC)
Abstract Deep water gas reservoirs in the Western Black Sea consist of highly laminated heterogeneous and complex sand/shale sequences. A petrophysical volumetric model was created by combining the triaxial induction resistivity data with the Thomas-Stieber (1975) sand-shale volumetric model to better evaluate low-resistivity pay zones in highly laminated shaly sand sequences. Although the results from this method are volumetrically almost correct, they are quite insufficient to deal with the distinctions between finely laminated sand, silt and shale. In order to calculate volumetric petrophysical parameters, such as porosity and water saturation, which are linearly or non-linearly derived from the sand/shale fraction of the rock volume, accurate measurement of laminar shale volume in shaly sand sequences is an essential first step. Even though GIIP does not change much, the volumetric method presents a particular challenge in terms of continuity of gas bearing layers when there is water located in both above and below the gas-bearing sands. High-resolution wireline image tools with a vertical resolution of 0.5 cm can capture bed thicknesses and boundaries of these sand layers, enabling the determination of the net to gross sand ratio. However, imaging technologies by themselves are unable to determine precise porosity and water saturation. By statistically evaluating extensive volumes of core data (RCA and SCAL) and image logs, a new high-resolution methodology offers a simple and innovative method to compute porosity and saturation. A partially cored reservoir section example is used to demonstrate the entire technique. This approach does not require standard log deconvolution. The uncertainty has been understood after comparing the results between the volumetric model and high-resolution model. By using the methods described in this paper, it is possible to position the perforation interval more precisely and reduce uncertainty for volumetric petrophysical calculations in complex highly laminated clastic reservoirs. The results show that low resistive laminated clastic reservoirs can be extremely productive, showing reservoir quality comparable to that of productive thick sands.
- North America > United States (1.00)
- Europe (1.00)
- Asia > Middle East > Turkey (0.50)
- Research Report > New Finding (0.48)
- Overview > Innovation (0.48)
- Research Report > Experimental Study (0.34)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Well Drilling > Drilling Operations > Coring, fishing (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Core analysis (1.00)
- Information Technology > Artificial Intelligence (1.00)
- Information Technology > Sensing and Signal Processing > Image Processing (0.46)
Abstract Directional drilling plays a pivotal role in the oil and gas industry, but its efficacy is frequently hampered by imprecise control. This paper introduces an autonomous directional drilling framework that capitalizes on intelligent execution techniques to enhance drilling performance. The proposed framework encompasses Autonomous Drilling Software (ADS), which operates as a fully independent system integrating sophisticated algorithms and real-time data analysis. This software aims to optimize drilling performance, ensuring more precise wellbore positioning, while simultaneously delivering tangible reductions in carbon emissions and substantial improvements in operational and health, safety, and environment (HSE) risk mitigation. The primary objective of this paper is to provide a comprehensive performance assessment of ADS by comparing the results of similar wellbore sections drilled conventionally under comparable conditions. A baseline will be established for performance by analyzing a range of key drilling metrics, including rate of penetration (ROP), actual drilling trajectory's accuracy, trip for failures (TFF), and a smoothness of hole profiles that helps to minimize the time and effort required for subsequent casing running operations, which can be a major source of downtime and operational inefficiency. The case study will provide a detailed analysis of the performance of ADS in a real-world drilling environment, highlighting the effectiveness of automation technologies in overcoming technical challenges and improving drilling efficiency and safety. According to the data collected over the last three years in fields drilled on the Norwegian continental shelf (NCS), the resulting ROP, well placement and borehole quality have been considerably improved by implementation of drilling automation. 23.4% increased ROP is achieved on sections being drilled by autonomous steering versus conventional drilling method. Additionally, the implementation of a drilling automation solution resulted in a notable 42% increase in the average length between downlinks for the curve sections when compared to manually drilled curve sections. The analysis has omitted the tangent section due to the practice of utilizing downhole navigation systems for drilling the tangent sections. In such cases, the rotary steerable system automatically adjusts steering force and toolface without requiring downlink communication. Wells drilled with the drilling automation platform tracked the distance to the planned trajectory with lower standard deviation in comparison with manually drilled wellbores. ADS guided push and point the bit RSS technologies during drilling 25 curves on the particular fields in the Norwegian sea. The curves have been drilled with sample standard deviation 2 meters of the spread of distance to the plan data distribution. Results observed were compared with nearby offset curves drilled on the same field in manual mode, where the standard deviation of distance to plan achieved was 5.3 meters. The ensuing examination demonstrates a case history of directional drilling automation system deployment on injector well's 8.5-inch hole section, inclusive of wired drill pipe on the NCS. The rotary-steerable system's (RSS) drilling commands were automatically generated, optimized, and transmitted via a drilling automation platform, which leveraged real-time data to ensure accurate well placement. Since one of the objectives of the well was to detect an oil-water contact (OWC), the maximum allowable deviation from the principal plan was 5 meters to hit the Target #1 at the total depth (TD) of the section. The well section in question was a highly complex open hole sidetrack that was drilled from the cement, in close proximity to a nearby offset well, which served as the parent wellbore for a 7-inch liner stump. The liner stump was a source of magnetic interference, which posed a challenge in the drilling process. The drilling automation platform utilized the high-precision downhole measurements to compute and optimize the drilling trajectory in real-time, ensuring that the wellbore remained on track and avoided any potential sources of interference. Despite the complex and challenging nature of the well section, the automated system was able to complete the drilling operation with high accuracy and efficiency, demonstrating the effectiveness of advanced automation technologies in overcoming technical challenges in directional drilling.
- Europe (1.00)
- North America > United States > Texas (0.28)
- Information Technology > Sensing and Signal Processing (1.00)
- Information Technology > Architecture > Real Time Systems (1.00)
Key Technologies and Solutions to Manage Risks and Overcome the Deepwater Challenges in an Integrated Services Project in the Gulf of Mexico
Davila, Andres Nunez (SLB, Houston, Texas, United States) | Lopez, Juan Ramon (SLB, Houston, Texas, United States) | Rossi, Lucas (SLB, Houston, Texas, United States) | Lin, Emily (SLB, Houston, Texas, United States) | Giam, David (SLB, Houston, Texas, United States) | Widhihabsari, Martha (SLB, Houston, Texas, United States) | Hill, Jesse (SLB, Houston, Texas, United States) | Jackson, Richard (SLB, Houston, Texas, United States) | Basso, Miguel (SLB, Houston, Texas, United States) | Jaimes, Juan Pablo (SLB, Houston, Texas, United States) | Bouguetta, Mario (SLB, Houston, Texas, United States)
Abstract The deepwater environment is traditionally characterized by high operating costs, making any operational savings extremely valuable when facilitating project development and execution. In a highly volatile oil price environment and while under a long-term commercial relationship, a new strategy was implemented to achieve performance optimization and time reduction. This strategy aimed to attain high efficiency and consistency through the application of an integrated services performance and reward model. The core objective of integrated services projects is to generate synergies for further project optimization, while the goal of a reward model is to promote the utilization of diverse technologies to manage risks and minimize the occurrence of undesirable events. In this paper we aim to describe how various technologies and digital solutions can be integrated to serve risk management endeavors, optimize performance, and meet project-specific needs. The integrated services performance and reward model was designed based on three components: project success criteria, historical nonproductive time (NPT), and key performance indicators (KPIs). Major technologies were evaluated and selected in accordance with the project requirements. Digital solutions were implemented to establish a performance baseline, assist in defining the planned time, and assess project-related risks. Critical tasks involved not only planning but also monitoring the results and comparing them to the KPIs, as well as identifying instances of invisible lost time. In the Gulf of Mexico, characterized by narrow operating windows and frequent lost circulation events, continuous monitoring and control of drilling fluid properties are mandatory, supported by the implementation of digital and automated solutions. In addition, key technologies were introduced for formation characterization and further area development.
- Well Drilling > Pressure Management (1.00)
- Well Drilling > Drilling Operations (1.00)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- (4 more...)
- Information Technology > Architecture > Real Time Systems (1.00)
- Information Technology > Communications (0.94)
- Information Technology > Sensing and Signal Processing (0.68)
Surveillance, Analysis, and Optimization (SA&O) During Active Drilling Campaign
Zhang, Yanfen (Chevron U.S.A. Inc., Covington, LA, U.S.A.) | Bovet, Paul (Chevron U.S.A. Inc., Covington, LA, U.S.A.) | Samano, Lorelea (Chevron U.S.A. Inc., Houston, TX, U.S.A.) | Isabu, Ozzy (Chevron U.S.A. Inc., Covington, LA, U.S.A.) | Chima, Andres (Chevron U.S.A. Inc., Covington, LA, U.S.A.) | Everson, Erik (Chevron U.S.A. Inc., Covington, LA, U.S.A.) | Sun, Kai (Chevron U.S.A. Inc., Houston, TX, U.S.A.)
Abstract Deepwater drilling is an expensive complex operation. Real-time surveillance data and analysis for drilling operations are very important for ensuring safety and cost control. Due to the high production rate and high expense of deepwater wells, there are usually not many wells planned for developing a deepwater field. Therefore, the results of each well hold particular significance as additional reservoir surveillance data and are crucial for optimizing field development and production forecasts. The subject field of this paper is WRB (pseudonym) which is a deepwater field located in the Gulf of Mexico. In the past few years, about one to two new wells per year came online at WRB field. Thus, there has been a constant stream of surveillance data from both drilling new wells and production/injection at existing wells. All the surveillance data were processed and utilized for updating the reservoir simulation model that ultimately serves as the engine for optimizing the future well locations. This paper is intended to review and share the key learnings and best practices of Surveillance, Analysis and Optimization (SA&O) during the active drilling campaign of WRB field. A comprehensive effort was undertaken to review the historic surveillance activities carried out during drilling and post-drill, and to review the consequent value-adding decisions from effective use of surveillance information.
- North America > United States > Texas (0.46)
- North America > Canada > Alberta (0.46)
- Asia > Middle East > Kuwait (0.28)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Geological Subdiscipline > Geochemistry (1.00)
- Asia > Middle East > Kuwait > Ahmadi Governorate > Arabian Basin > Widyan Basin > Greater Burgan Field > Wara Formation (0.99)
- Asia > Middle East > Kuwait > Ahmadi Governorate > Arabian Basin > Widyan Basin > Greater Burgan Field > Ratawi Formation (0.99)
- Asia > Middle East > Kuwait > Ahmadi Governorate > Arabian Basin > Widyan Basin > Greater Burgan Field > Mauddud Formation (0.99)
- (4 more...)
- Well Drilling > Wellbore Design > Wellbore integrity (1.00)
- Well Drilling > Drilling Operations (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- (8 more...)
- Information Technology > Communications > Networks > Sensor Networks (1.00)
- Information Technology > Modeling & Simulation (0.69)
- Information Technology > Sensing and Signal Processing (0.68)