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Directional Drilling
Sustained Annular Pressure Prevention in the Vaca Muerta Wells Optimizing Well Construction Through the Utilization of Metal Expandable Packers Technology
Torres, Jorge (YPF SA) | Calegari, Ricardo (YPF SA) | Arias, Fernando (YPF SA) | Arribillaga, Lucas (YPF SA) | López, Emiliano (Welltec) | Esquitin, Yosafat (Welltec) | López, José (Welltec) | Guilarte, Mariano (Welltec)
Abstract Drilling and completing oil and gas Wells into the unconventional Vaca Muerta Formation (Fm.) has proven to be a challenging task since the beginning of the development. The unique characteristics of the several formations oil operators must drill through in order to reach Vaca Muerta Fm along with the extended reach horizontal sections, make the complexity of the drilling operation to become a constant challenge for an optimized well architecture. To add up the extensive and demanding completions program, currently being executed with an average of 60 frac stages per well with a work pressure up to 13500 psi, make the construction of wells to be an even more challenging task. One of the main factors that make the previously describe scenario into an even more complex is the presence of Sustained Annular Pressure (SAP), this phenomenon affects around 35% of worldwide oil and gas wells (Farag, Mahmoud - 2015). This challenge represents several risks such as contamination of water formations, emission of greenhouse gasses, potential well blow outs. This situation it's been witnessed in some of the recently drilled well in the Vaca Muerta Fm, turning SAP into one of the challenges oil operators face today. Said phenomenon has been evidenced by the presence of pressure in the annular spaces at surface once the hydraulic fracturing programs have been completed. To mitigate SAP several alternatives to enhance or replaced the traditional cement seal are being evaluated; mechanical integrity of the cemented seal can be affected by the stresses generated in the casing as the frac operations gets developed, suffering multiple compression and expansion cycles. An effective and proven solution, that can be integrated into the well's completion program helping to achieve the prevention of SAP, is the Metal Expandable Packer (MEP) technology. This new technology can help mitigate SAP eliminating the need for complex remedial operations that usually increases the costs and operational risks. The following paper shows the process of technology selection, qualification, job planning, field deployment of MEP and results.
- North America (0.94)
- South America > Argentina > Neuquén Province > Neuquén (0.49)
- South America > Argentina > Patagonia > Neuquén > Neuquen Basin > Vaca Muerta Shale Formation (0.99)
- South America > Argentina > Patagonia > Neuquén > Neuquen Basin > Vaca Muerta Field > Vaca Muerta Shale Formation (0.98)
Abstract The development of Vaca Muerta has presented significant challenges in the unconventional oil industry. These challenges extend beyond the complexity of drilling and completing several-kilometer-long horizontal branches, as they also include the issue of well-to-well interference due to fractures, known as "frac hits". The primary objective of this case study is to document the series of frac hit events occurring between 2018 and 2023 in a Vaca Muerta field (oil window with multilanding development), analyzing the consequences such as pressure increases or sand production in offset wells, and presenting strategies to mitigate these issues. Additionally, the methods used to forecast these events and estimate potential production losses or well damages will be described. To study frac hits, wellhead flowing pressure (WHFP) obtained through telemetry was analyzed, and a machine learning model was employed to transform WHFP into bottomhole flowing pressure (BHFP) to correlate with production controls and water tracers. A statistical study was conducted, highlighting changes in production (oil and water) and pressure in the offset wells during these events. Furthermore, cases of sand production, effects on water production in the source wells, potential damages to the offset wells, and the influence on well decline after a frac hit were evaluated. Using these statistics, it is possible to predict which wells are susceptible to experiencing frac hits and estimate their intensity. The obtained results revealed that in the mentioned Vaca Muerta field, frac hits represent one of the most significant challenges for its development. Adverse effects were observed, including sand production, casing deformations, considerable oil production losses, and an increase in the production decline of offset wells. Additionally, difficulties in managing large volumes of produced water due to the frac hit were identified. It was observed that second-line receivers present considerably smaller effects compared to first-line receivers, that frac hits can occur between landings only in certain cases, and it was found that clustering numerous fractures using diversion technology amplifies the effects of frac hits, potentially impacting wells located over 1400m away. Through this study, it is possible to estimate frac hit events, considering various factors such as proximity to the source well, BHFP of the offset well, degree of overlap between both wells, among others. Based on this information, quantitative estimations of the duration of the frac hit, oil losses, water production, time required for the bottomhole pressure to return to its pre-frac hit state, and other relevant aspects were made. Measures were implemented to mitigate the consequences of frac hits, such as pressure barriers between the fractured wells and offset wells, securing neighboring wells, opening the size of choke to facilitate water drainage, and reducing the size of choke in case of sand production.
- South America > Argentina > Patagonia Region (1.00)
- South America > Argentina > Neuquén Province > Neuquén (1.00)
- South America > Argentina > Patagonia > Neuquén > Neuquen Basin > Vaca Muerta Shale Formation (0.99)
- South America > Argentina > Patagonia > Neuquén > Neuquen Basin > Vaca Muerta Field > Vaca Muerta Shale Formation (0.99)
- South America > Argentina > Patagonia > Neuquén > Neuquen Basin > Tordillo Formation (0.99)
- South America > Argentina > Patagonia > Neuquén > Neuquen Basin > Quintuco Formation (0.99)
Abstract This paper introduces how GIS software and mathematical algorithms can be combined with the goal of efficiently placing well laterals in order to maximize drainage area of shale reservoirs. Integer Linear Programming (ILP) and Geographic Information Systems (GIS) combined to solve the optimization problem of efficiently placing pads and laterals in order to maximize coverage of acreage positions while avoiding subsurface and surface constraints using multiple predefined drilling templates. This methodology has been used to plan future infill development of Tecpetrol's Fortín de Piedra area in Vaca Muerta formation (Neuquén/Argentina). Results showed up to 84% coverage of drainage formation using 59 PADs with 230 new laterals of length 2.700 meters. Real cases studies results show that this approach may provide an optimization opportunity in shale plays with many surface and subsurface constraints. Introduction Fortín de Piedra area is in the center of the Neuquén basin, in Neuquén province, near the town of Añelo as shown in Figure 1. With an area of 248 km2, Tecpetrol operates this block with 100% of ownership. In 2017 Tecpetrol started an unconventional development plan targeted to fluid extraction in Vaca Muerta formation, one of the main sources of shale gas in the country (Biscayart et al, 2020). Up to date, Fortín de Piedra has become one of the key players for gas supply in the country, providing 14% of what is consumed in Argentina. The problem Tecpetrol's GIS Data Management Team is involved in the planning and representation of the drilling plan of the horizontal wells within the reservoir, also called unconventional development plan. Based on geoscientists’ well Pad designs, they locate Pads throughout the exploitation area while avoiding restrictions due to faults, drilled wells, or reservoir geometry. This process was performed manually using a GIS software. Different developments plans are evaluated for a single area consuming up to two weeks of workday per analyzed scenario and with little chance to rapidly targeting the optimal distribution of Pads. In 2019, Tecpetrol implemented a novel optimization algorithm based on Integer Linear Programming (ILP) that helped the company to optimize massive horizontal well developments while cutting processing times down to one day and targeting the optimal development plan in a couple of iterations.
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.46)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play (0.36)
- South America > Argentina > Patagonia > Neuquén > Neuquen Basin > Vaca Muerta Shale Formation (0.99)
- Asia > Kazakhstan > Aktobe Oblast > Precaspian Basin > North Block (0.99)
- South America > Argentina > Patagonia > Neuquén > Neuquen Basin > Vaca Muerta Field > Vaca Muerta Shale Formation (0.98)
Analysis of Casing Deformation in Different Unconventional Areas with a Comprehensive Approach in the Study
Espindola, Brian (YPF.S.A.) | Romero, Antonio N. (YPF.S.A.) | Rodríguez, Maria J. (YPF.S.A.) | Luna, Romina D. Sosa (YPF.S.A.) | Weimann, Mauro I. (YPF.S.A.) | Velo, Rosario D. (YPF.S.A.) | Escobar, Rodrigo A. (YPF.S.A.) | Suarez, Fernando (YPF.S.A.) | Pucho, Miguel S. (YPF.S.A.) | Gonzalez, Nicolas (YPF.S.A.) | Ferrara, Andrea V. (YPF.S.A.) | Roth, Rocío L. (YPF.S.A.)
Abstract In Neuquén, Argentina; the Vaca Muerta formation is the main target for unconventional resources and casing deformation is a recurrent problem observed among most of the main operators in this basin. In our case the first deformations were observed at the beginning of 2011 and as the development of the unconventional fields advanced, they continued to appear and increased in frequency when the horizontal well manufacturing process began. The knowledge of the subsurface mechanisms that cause these deformations motivated numerous internal and external studies that focused on geology, geomechanics, seismic, and reservoir engineering, and led to the application of mitigation measures and risk analysis matrices. One of the ways to validate casing collapse is through the MIT (Multifinger Image Tool) registry which measures the internal diameter with multiple flanges. Based on the opposite measurement, it calculates the minimum passage in a restriction event, data that is used to make immediate decisions and thus be able to continue with the completion operations. With the exhaustive analysis of this profile and incorporating the geological domain, geosteering, mechanical contrast analysis and the type of stimulation design executed, the casing deformation mechanism can be identified, and, in this study, we will be showing different examples of deformed wells, understanding the mechanism and the proposed mitigation with positive results in the operation. The objective of this work, beside proposing good practices for obtaining the record (recording mode, configuration of tools and resolution) to follow the workflow of restriction analysis, also intends to show the preliminary conclusions reached regarding the mechanisms involved in generating deformations studied in YPF blocks where the MIT tool, well imaging and additional well information were readily available. The pre-classification of the deformations into two categories used to facilitate the study and the understanding of the mechanisms involved in their formation as it is understood today. The use of the MIT tool is very valuable, but it is necessary to have another complementary tool with low availability such as the tractor to run it on the horizontal section. In addition, this protocol gives us information about the condition of the pipe at the time the tool is used, not during the stages along the well-bore. Reason why we have added to the analysis the CCL (Casing Collar Locator) measurements took during each of the fracturing stages of the Plug & Perf operations and obtained a good correlation with what was measured in the MIT with no additional costs.
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Structural Geology (0.93)
- South America > Argentina > Patagonia > Neuquén > Neuquen Basin > Vaca Muerta Shale Formation (0.99)
- Asia > China > Sichuan > Sichuan Basin (0.99)
- South America > Argentina > Patagonia > Neuquén > Neuquen Basin > Vaca Muerta Field > Vaca Muerta Shale Formation (0.98)
Abstract Addressing the challenges of drilling the Cretaceous formations of the Middle Magdalena Valley Basin in Colombia which present a difficult geologic environment characterized by high structural complexity, faulting, and uncertainties regarding operational windows, required the consideration of controlled pressure conditions and the use of two-phase fluid on continuous nitrogen injection. Also, to achieve wellbore displacement enhancing recovery, required a high-angle directional trajectory that involved close directional control and the identification and analysis of operational risks. Therefore, careful planning during the design phase was crucial. This involved identifying a set of engineering practices, mapping operational risks, and offering integrated solutions. Additionally, a thorough analysis of available options and selection of technologies that align with project requirements and challenges was necessary. Furthermore, the incorporation of bottomhole pressure sensors (PWD) was necessary to provide a reliable source of information for personnel in charge of monitoring bottomhole conditions and overseeing nitrogen injection, so that the information collected could be reviewed in real time to determine the effectiveness of the operational parameters implemented and to evaluate unexpected conditions. The results indicated a smooth trajectory with minimal deviations, meeting the directional requirements as modeled by the directional BHA. A limited percentage of detection and data transmission through pulse signals to the surface was deemed acceptable. Additionally, the implementation of automation using service provider proprietary software became feasible. Introduction The main challenges encountered when drilling a naturally fractured limestone reservoirs involves minimizing formation damage resulting from circulation losses. To address this issue, a solution was implemented utilizing Managed Pressure Drilling (MPD) and the injection of Nitrogen as a bi-phasic fluid. The objective of this approach was to generate a controlled Equivalent Circulating Density (ECD) in order to minimize fluid invasion and effectively manage fluid losses. The main difficulty lied in drilling a high angle well in a complex geological environment with significant structural complexities. The operational window was uncertain, necessitating consideration of two-phase fluid conditions and continuous nitrogen injection. Additionally, it was crucial to maintain directional control and meet specific requirements for capturing logging information. To address these challenges, a comprehensive operational risk analysis was conducted, and the appropriate selection of tools and techniques was made to efficiently gather information in harsh conditions. This enabled the reduction of decision-making times and the achievement of operational efficiencies based on real-time data collection.
- South America > Colombia > Tolima Department (0.35)
- South America > Colombia > Santander Department (0.35)
- South America > Colombia > Cesar Department (0.35)
- (4 more...)
- South America > Colombia > Tolima Department > Middle Magdalena Basin > La Luna Shale Formation (0.99)
- South America > Colombia > Tolima Department > Middle Magdalena Basin > Casabe Field (0.99)
- South America > Colombia > Santander Department > Middle Magdalena Basin > La Luna Shale Formation (0.99)
- (11 more...)
- Well Drilling > Well Planning > Trajectory design (1.00)
- Well Drilling > Pressure Management > Well control (1.00)
- Well Drilling > Pressure Management > Managed pressure drilling (1.00)
- (8 more...)
Abstract This work describes a Shell process for quantifying production scaling factors using best practices in data analytics that has been employed in numerous shale basins including Permian, SCOOP-STACK, Eagle Ford, Haynesville, and the Montney. Shell formed a collaboration with NOVI Labs leveraging their experience with machine learning platforms. This work is a more detailed extension of an earlier work discussing the application for scaling factors to Vaca Muerta wells (McEntyre et al., 2022). We highlight best practices in developing and quality checking data analytics-based models. Using NOVI Labs’ data analytics platform, Shell developed over 250 machine learning models based on close to 600 wells to scale oil production for a wide range of conditions. Datasets were filtered based on operator, target zone, normalized production, porosity, and completion vintage year. Around 120 distinct input features were examined, such as average porosity, water saturation, total organic content, bulk density, gamma ray, compressional sonic, true vertical depth of lateral, various completion intensity metrics, and various spacing parameter combinations. Results were validated via multiple blind testing in various blocks and landing zones. We document a workflow used to assign log and petrophysical properties when no basin-wide static model is present. Key insights from our modeling process include: • A methodology to establish production scaling factors • Impacts of operating strategy on model results • Impacts of removing static input, or other key features on prediction capabilities • How stimulation intensities matter more in lower quality rock The final model simplifies a non-linear complex solution into a five variable linear equation that allows Shell to confidently build type curves and perform development planning optimization exercises with little to no pilot data. We highlight the applicability of our methodology beyond scaling production to other applications in the oil and gas industry. Introduction The Vaca Muerta play in the Nequeun Basin is undergoing active development, including testing up to five stacked landing zones within a single development unit (Figure 1). Although the well inventory has expanded in recent years, the number of black oil horizontal wells with a year or more of production is still relatively low at fewer than 600 wells. In comparison, a prolific play like the Permian boasts over 32,000 producing horizontal wells. To overcome the limited well data, Shell Argentina has employed software developed by Novi Labs. This software utilizes machine learning (ML) models trained on Vaca Muerta data sets to accurately predict well performance and identify the magnitude of impact of different subsurface, completion, and other well design features. Shell then applies proprietary post-processing on the ML model results to derive production scaling factors. These scaling factors empowered Shell to standardize well performance across various conditions, confidently build type curves, and optimize development planning.
- Geology > Geological Subdiscipline > Geomechanics (0.68)
- Geology > Petroleum Play Type > Unconventional Play (0.68)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.34)
- South America > Argentina > Patagonia > Neuquén > Neuquen Basin > Vaca Muerta Shale Formation (0.99)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.99)
- (31 more...)
- Reservoir Description and Dynamics (1.00)
- Management > Asset and Portfolio Management > Field development optimization and planning (1.00)
- Data Science & Engineering Analytics > Information Management and Systems > Data mining (1.00)
- Data Science & Engineering Analytics > Information Management and Systems > Artificial intelligence (1.00)
- Information Technology > Data Science (1.00)
- Information Technology > Artificial Intelligence > Machine Learning (1.00)
- Information Technology > Artificial Intelligence > Representation & Reasoning > Search (0.46)
- Information Technology > Artificial Intelligence > Natural Language > Information Retrieval (0.46)
Abstract The main objective of this paper is to present a thermo-hydrodynamic 3D modeling approach for interpreting temperature surveys in horizontal wells with multiple fractures. The scope of the study includes predicting detailed homogeneous flow patterns in the porous matrix, fractures, and flow geometry inside smart completions. The model aims to provide 3D distributions of pressure and temperature along the horizontal wellbore, enabling quantitative flow analysis in liner, annulus, sandface, and each fracture. The 3D thermo-hydrodynamic modeling approach utilizes a grid covering the wellbore and the reservoir domain, considering the entire production/injection history. Advanced thermal and hydrodynamic equations are employed to describe physical processes in the reservoir, wellbore, and fractures. The scientific approach enables the model to quantify flow in various configurations, such as radial flow around the wellbore, semi-spherical flow at the toe and heel, and linear flow towards fractures, leading to improved accuracy and capabilities for reservoir production control. The 3D thermo-hydrodynamic modeling approach has been successfully applied in horizontal injectors and producers. A "blind" comparison to industry-standard PLT measurements and other temperature modeling products evaluated accuracy, thresholds, advantages, and limitations. The model matched PLT well in wellbore flow rates. In challenging cases, it depicted reliable reservoir flow profiles with complex flow paths, including annular flows, flows behind the casing, and swell packer failures. The model's quantitative assessment capability presents new opportunities for predicting diverse flow patterns in horizontal wells, advancing reservoir and fracture performance understanding. The 3D thermo-hydrodynamic modeling approach is of paramount importance in the oil and gas industry. By predicting flow patterns in horizontal wells with multiple fractures, the model offers valuable reservoir management insights. It surpasses conventional logging techniques, addressing limitations in detecting crossflow, high thresholds, and challenges with high viscosity fluids. The model's novelty lies in its comprehensive methodology, simulating 3D pressure and temperature distributions along the wellbore. Quantitative flow analysis in liner, annulus, sandface, and each fracture revolutionizes the industry. Successfully applied in horizontal wells with multi-stage hydraulic fractures, it enhances reservoir performance control and production efficiency.
Open Hole Sidetracks Performed in Lateral Sections in Unconventional Wells
Lara, Ines Leon (Drilling Engineering, YPF, Neuquen, Argentina) | Valero, Maria Angelica (Drilling Engineering, YPF, Neuquen, Argentina) | Chirinos, Robert (Drilling Engineering, YPF, Neuquen, Argentina) | Viramonte, Jose (NOC, YPF S.A. Buenos Aires, Argentina) | Somaruga, Agustin Jose (NOC, YPF S.A. Buenos Aires, Argentina) | Palladino, Celeste (Drilling Engineering, YPF, Neuquen, Argentina) | Rivera, Lucas Maximiliano (Drilling Engineering, YPF, Neuquen, Argentina)
Abstract The objective of this work was to develop a workflow to execute open hole sidetracks in the lateral section of horizontal wells, as an alternative to sidetracking against a mechanical barrier such as cement plugs or whipstock systems. The methodology implemented for sidetracking in open hole without mechanical deflection consists in three phases: (1) Well planning to kick-off and deviate from the original wellbore against a suitable lithology and achieve a trajectory with manageable tortuosity. (2) Designing specific bottom hole assemblies (BHA) to execute the sidetrack and return to the target geosteering window. It was necessary to refine the geomechanical and structural models of the reservoir to predict and anticipate BHA response to the target lithology. (3) Executing specific drilling practices including time-drilling, surveying, torque & drag and wellbore cleaning monitoring. All of this until the sidetrack BHA was confirmed to be in the new trajectory. To date, four wells have been successfully sidetracked without mechanical deflection in unconventional fields operated by YPF. A reference procedure was developed, following the success of operations in which the sidetrack was performed in a single run, lateral sections were then drilled to TD with a different BHA optimizing ROP and geosteering demands as usual, casing was run through the KOP and reached final depth without issues. This procedure incorporates specific parameters and conditions derived from the accumulated knowledge and experiences of previous experiences. Its implementation in future lost in hole scenarios is expected to mitigate the adverse impact of these events, contributing to overall operational efficiency and cost effectiveness of each project. Introduction When drilling horizontal wells in unconventional reservoirs, it might become necessary to sidetrack from the original wellbore within the lateral section, in the event of a lost in hole incident, in which BHA or casing components cannot be retrieved. This is known to be a more convenient solution in terms of surface facilities and overall project costs compared to drilling an entire new well.
Recently, at the SPE Annual Technical Conference and Exhibition, I was asked a question about the ‘engineer of the future.’ As we take a pause to turn the page to next year, I believe now is a prescient time to contemplate what’s next for petroleum engineering. Throughout my career, I’ve been able to witness great change in our industry as the shale revolution took hold making horizontal drilling and hydraulic fracturing commonplace, diagnostic and modeling tools improved in access and cost, and data became more timely and readily available. This led to a tremendous period of US energy supply growth and decades-long productivity improvements. Looking forward, I believe there are three trends that engineers should consider: 1) applying “new” tools to solve “old” problems, 2) connecting the dots via hybrid engineering, and 3) organizing, directing, and inserting data predictions into their workflow. These are not only my views but also the views of Devon’s talented engineers. Old problems will meet new solutions. The past decade has been dominated by unconventional horizontal development that was first pioneered in the Barnett Shale for natural gas and shortly thereafter transitioned into oil-focused development in the Bakken and Eagle Ford. Today, the Permian Basin continues to grow in total supply as the stacked pay is developed. Engineers should take stock of the tool set we have acquired during this era with a mindset to deploy these methodologies to tier II unconventional extensions, previously developed or bypassed conventional formations, offshore and international opportunities, enhanced recovery projects such as EOR and refracturing, and new energy opportunities like geothermal. To make these future opportunities competitive and meet the global demand for energy, we will likely need a combination of price, technology, and cost improvements. Engineers are critical to the latter two. To better illustrate these points let’s utilize examples. Drilling rig specification improvements have been coupled with material science and design improvements in bottomhole assemblies. The outcome is improved topdrives and mud pressure systems to power more durable and efficient downhole motors and bits, thus reducing failures, enhancing the efficiency of a rig’s daily footage, and enabling longer laterals. If we pivot to the completion space, our diagnostics for frac geometry have gone from limited and costly to a menu of options that provide fit-for-purpose diagnostics and costs. Devon deployed its first permanent fiber diagnostics in unconventional shale in 2012. Today, the same system is readily available but for a much lower cost. However, more frequently Devon has supplemented this tool with dip-in fiber and a proprietary methodology called sealed wellbore pressure monitoring to gather more frequent data points for frac geometry and design. As our team conducted, in cooperation with the US Department of Energy (DOE), a novel Eagle Ford project capturing horizontal core and completion diagnostics, we recognized that our designs have tremendously improved in efficiency but still have potential to capture more of the resource via initial and secondary fracturing efforts.
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.55)
- 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)
- (28 more...)
The cross-industry development and application of technologies is the epitome of innovation and ingenuity. The more divergent the industries are, the more the unique ways of thinking strike us as remarkable. Technology transfer between the oil and gas industry and other sectors isn’t new. Many examples can be found in medical science, space exploration, and renewable and sustainable technologies. In this JPT issue, the technologies of Oceaneering Space Systems and Impossible Sensing Energy are featured. A case study presented at the 2023 SPE Annual Technical Conference and Exhibition took medical science to a new low—into the depths of the Permian Basin for downhole reservoir drainage diagnostics (RDD). The coauthors, a subsurface and wells manager and a chapter manager, surveillance, analysis, and optimization and pilots at Chevron Technology Ventures (CTV), described using genome sequencing for cancer detection and treatment in a successful proof-of-concept (POC) test conducted from 2017 to 2019. Nampetch Yamali and Daniel Emery explained in SPE 215052 how in 2017 CTV was given the task of identifying technology to assess vertical drainage dimensions to estimate drainage volumes from fractured wells. The goal was to minimize interference from offset wells and co-developments to optimize reservoir recovery in unconventional fields. At that time, the technologies and their capabilities were limited. Although subsurface microbial DNA sequencing for upstream assets has found applications in enhanced biocide and corrosion inhibition, reservoir sweet spot indicators, and tracer technology, use of the technique was thought also to have potential in horizontal well development planning via RDD. Learning of a genomic sequencing technique for cancer cell identification in humans at the biology and biochemistry department at the University of Houston, the wheels started turning at CTV with thoughts it could be developed and adopted for RDD. Similarities were seen because RDD uses in-situ subsurface microbial DNA to infer the depths from which fluids drain after fracturing a horizontal well and optimizes well spacing on a pad, especially in stacked reservoirs. The predictive analytics platform mapped the hydrocarbon footprints of geologic subzones by using noninvasive DNA testing tools. The unique DNA markers for RDD were extracted from mud and cuttings from the horizontal and vertical drilling sections. DNA from produced fluids was also collected. The authors wrote, “Produced fluids collected at two-to-four-week intervals at the wellhead are mapped to the RDD framework. They are ‘lineage traced’ back to shale and tight rock. Drainage heights and percentage of contribution from these locations is computed adapting DNA sequencing and data analytics pipelines which were developed for lineage tracing cancer cells, breaking off from the primary tumor and metastasizing to distant sites back to the tissue of origin.” After validating the DNA extractions, CTV conducted a blind test using only the DNA data to determine the landing zones for each of the four wells in the pad. Using clustering methods, the results of the blind test accurately identified all landing zones within an acceptable margin, according to Yamali and Emery. The next step in the trial analyzed the DNA of the produced fluids. “Preliminary results showed drainage height estimates for each horizontal well.” In 2021, the study continued with an additional four new field trials in the Permian Basin for application of the technique to zonal production identification. The authors wrote, “Although the results from the POC were positive, subsurface DNA RDD technology is a novel technique within the oil and gas industry, and advanced applications are still evolving. This combination naturally gives rise to more general skepticism and a need to thoroughly evaluate the technology from operational, economic, and accuracy perspectives.” The paper describes the ongoing cross-disciplinary work being done by petroleum engineers, geologists, microbiologists, and stratigraphers to fully evaluate this method of RDD. It further details CTV’s wider approach to “accelerate the innovation life cycle, from pilot stages to widespread adoption at scale,” emphasizing the need for leaders’ support for nonconventional thinking and approaches. As the close of 2023 approaches, I’d like to take this opportunity to wish you the best in 2024 on behalf of the JPT Editorial Review Board and the JPT staff. We’ll be kicking off the new year with the commemoration of JPT’s 75th anniversary. Each issue will include an article dedicated to the evolution of technology and industry practices over the seven and a half decades JPT has covered the upstream industry. In January, Trent Jacobs and Stephen Rassenfoss will revisit technological advancements since JPT’s 50th anniversary in 1999. Since then, over 25 million B/D have been added to the global supply thanks in very large part to advancements in drilling, completions, and reservoir technologies. Join us as we explore these along with some predictions made 25 years ago and the surprising realities of where the industry stands today.
- Asia (1.00)
- North America > United States > Texas (0.46)
- North America > United States > New Mexico (0.46)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > Asia Government > Middle East Government (0.31)
- 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...)
- Data Science & Engineering Analytics > Information Management and Systems (1.00)
- Well Drilling > Drilling Operations > Directional drilling (0.97)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale oil (0.87)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (0.87)