bluuebunny/crossref_metadata_2025 huggingface dataset:
Utilizing Low-Density Mud Systems to Improve Operational Efficiency for Post Frac Cleanout of Unconventional Wells in Depleted Areas
Authors: Peurifoy David , McGraw Mike , Martinez Stephen , Morales Adrian , Farish Maddie , Perkins Reece , Merrill Allan
Published: September 2022

Background

Due to advancements in horizontal drilling and completions technology, wells in some basins are now being completed in areas where conventional production has existed for 50+ years. This paper will focus on the Midland Basin, where wells in the Spraberry, Dean, and Wolfcamp formations have been produced since the 1960s and earlier in some cases. As a result, current unconventional wells in these formations will invariably deal with depletion. In the past, freshwater consisting of friction reducer and a foaming agent, along with nitrogen, was used to lighten clean-out fluids to a fluid density that allows circulation of these wells. The use of nitrogen, while necessary, can lead to variable fluid quality, increase clean-out times, add expense, and ultimately reduce time-to-market for these wells. Lightweight mud systems (LMS) are not new to the oilfield but relatively new to post-frac clean-out operations applications. The system consists of a proprietary water-based mud additive that reduces mud density by creating microbubbles encapsulating air in a multi-layer shell. This technology can reduce fluid weights by up to 1.9 ppg from the original base weight. The base fluid for the LMS may be freshwater, produced water, or brine. The fluids possess a low shear rate viscosity that allows good hole cleaning without risking formation invasion. The system may be used with nitrogen if needed for extreme cases. No degradation of mud motor performance has been observed when using the LMS. This paper will offer 3 case studies where the LMS provided operational and economic benefits in post-frac clean-out operations.
Gas Chemical and Carbon Isotope Composition as a Diagnostic Tool for Energy
Authors: Almubarak Zainab , Alrowaie Mohammad , Lu Feng , Algeer Ranya
Published: September 2022

As the world is moving toward a low-carbon energy structure, natural gas has become critical in the supply of global energy. The genetic identification of different types of natural gas is important for the assessment of their source and exploration potential. Chemical and carbon isotopic compositions of produced gas are useful tools to assess their origin, thermal maturity, migration and to monitor gas production. In this study, we present different geochemical approaches to assess the origin of the gases and thermal maturity as well as to evaluate the effect of adsorption on shale gas during production. Thirteen gas samples from different conventional reservoirs were analyzed for their isotopic compositions to assess gas origin and thermal maturity. To assess gas production, seven gas samples were collected periodically from the same unconventional shale interval and were analyzed for their isotopic signatures. The results demonstrate that carbon isotopic composition of methane to pentane can be used as fingerprinting tool to identify different sources of gas. The studied gases are all of a thermogenic origin and were generated from Type-II marine source rocks. Mixing of gases generated from different source rocks were observed. The mixed gases are characterized by similar isotopic profiles in methane and ethane and they differ in C3+ hydrocarbons. Thermal maturity trends were identified on the studied samples using the relationship between methane, ethane, and propane isotopes versus the wetness index (total HC/methane concentration). To study the effect of gas adsorption during production, samples produced from the same hydrocarbon source rock were assessed at different time intervals (one-year period of production). The results show small variations between isotope compositions; thus, the impact of adsorption is still uncertain and a longer-term monitoring plan is designed. The results of this study shed insight into using isotope geochemistry as an important diagnostic tool for natural gas exploration and production.
Separation of Oil and Water Emulsions: Is Heating Good Enough?
Authors: Gavrielatos Ilias , Mohan Ram S. , Shoham Ovadia
Published: September 2022

Surfactants and nanoparticles (NP) frequently act as stabilizers for oil and water emulsions. There is a need to investigate whether such NP stabilized emulsions (also known as Pickering emulsions) require different treatment for break-up, as compared to the well-known method to separate surfactant stabilized emulsions, i.e., heating. Thus, the main objectives of this work were to identify emulsions resistant to heating and develop a process able to accelerate the separation kinetics of such ultra-tight emulsions.

Extensive experimental investigations on the stability of different types of oil and water emulsions under various temperature and brine salinity conditions were carried out using a state-of-the-art Portable Dispersion Characterization Rig (P-DCR). The batch separator was equipped with a high-resolution, surveillance camera to monitor emulsion separation kinetics. Commercial grade mineral oil and synthesized brines with various salinities were used as the test fluids. Silica nanoparticles of different wettability and surfactants with different HLB values were deployed as the stabilizing agents for the produced emulsions.

It was found that the elevated temperature effects dominate the separation kinetics of the studied emulsions, as compared to any brine salinity effects, especially at higher temperatures, namely, 60°C and 80°C. Moreover, the effects of high temperatures and brine salinities on the separation kinetics were much more significant for the emulsions stabilized by surfactants than for NP stabilized emulsions. Perhaps more importantly, neither high temperature nor high brine salinity had any remarkable effects on the separation kinetics of the emulsions stabilized by hydrophobic NP. It was also shown that the hydrophobic NP dominate the stability mechanism for dual emulsifier fluid systems, such as emulsions stabilized by both hydrophobic NP (R974) and a surfactant of low HLB value (Span 80).

A novel oil-water emulsion break-up process was developed to enhance the kinetics of the separation, irrespective of the underlying emulsion stability mechanisms, namely, surfactant, NP or both. The performance of this separation process was superior to heating, which is the conventional method applied to separate oil-field emulsions. Finally, it is envisioned that the newly developed process may be applied in the field as an in-line separation system for tight oil-field emulsions.
High-Resolution Acoustic Imaging for Submillimetric Casing Thickness Quantification and Advanced Effective-Area-Based Burst Pressure Analyses
Authors: Simpson Greer , Littleford Tom , Battistel Anthony
Published: September 2022

For downhole casing integrity applications, high-resolution acoustic imaging is a novel approach for quantifying casing thickness, corrosion, and mechanical damage defects by measuring both inner diameter and outer diameter wall losses. The technology deploys high-density solid-state arrays with up to 512 transducers to achieve sub-degree azimuthal and sub-millimetric axial resolutions with casing thickness measurements down to a minimum thickness of 0.07 in with an error of ±0.005-in. In this study, we discuss the technological advancements, details of laboratory validation results, exploration of burst pressure calculation methodologies, and a field case study based on the novel technology.

The high-density solid-state transducer array uses acoustic signals to measure the casing thickness and radial measurements in a single pass. The resulting 3D point cloud of data is analyzed using image-processing-based machine learning algorithms. The validation data are collected from multiple machined and field samples. The machined defect dimensions are varied to test the detection, sizing, and accuracy of the platform. A field-based case study is presented to compare high-resolution acoustic imaging data with computed tomography scan data. To demonstrate the advantages and sensitivities of using high-resolution datasets and high-accuracy burst pressure methodologies, examples of RSTRENG software burst pressure analyses are provided.

The high-resolution acoustic imaging platform offers fundamental improvements over legacy magnetic flux leakage (MFL) and single-element ultrasound-based tools. Acoustic technology relies on direct measurement principles and results are not inferred through calibration. The time-of-flight-based approach enables the inspection a single casing string comprising different diameters, wall thicknesses, and materials in a single log run. The technology is pipe material agnostic and directly measures the casing thickness of ferrous and nonferrous metals. The electronic platform enables the capture and storage of submillimetric axial resolution, which provides details of the penetration profiles of all defects. High-resolution and spatially registered datasets are leveraged to conduct effective area, RSTRENG, and modified B31G burst pressure calculations with significantly improved defect identification, penetration quantification, interaction rule application, and shape characterization. The advancements presented in this paper are highly pertinent to gas storage and carbon sequestration operators, seeking integrity management advancements. The real-world benefits of the presented technology are the ability to extend well life, optimize workover schedules, and manage gas storage pressure ratings more efficiently.
Solving the Engagement Enigma
Authors: Smith Andrew L
Published: September 2022

The adoption of green credentials requires cultural change within our organisations and the need to attract, train, develop and retain a new breed of talent demanding a net zero future. This is fine in theory but one of the first objectives our industry must solve is the Engagement Enigma, otherwise none of these aspects will be achieved. This paper now provides a solution to solving the Engagement Enigma as it may be clearly demonstrated by the 4C's which show that the key process to ensure Engagement, is the underlying synergy created by starting a Career, acquiring Competence, demonstrating Care and a transparent feedback Culture created throughout an organisation by encouraging Continual Professional Development or CPD. We are therefore in the unique position to ensure that the oil & gas industry can also synergistically implement the IPIECA SDG's as an integral component of CPD to provide genuine engagement. The solution to the Engagement Enigma is a new paradigm which now clearly shows that to those skilled in the art it is self-evident that all the above UN SDG topics may be synergistically combined to provide us with a unique and novel solution to the Engagement Enigma.
Effects of Fluid Over Pump Intake on Rod Pumping System Performance
Authors: Ahmed Mohamed G. M. , Ahmed Ahmed Mohamed G.
Published: September 2022

The application of the reciprocating sucker rod pumping system has been growing steadily with the improvement in the system technology, which allows to open the application envelop of this system. Therefore, the need for a better understanding of the system performance is heavily required. Predicting the dynamic responses and loads is critically important to determine the operating situation, total system performance, and system output. Usually there is a perception of reducing the fluid level over the pump intake (intake pressure) will maximizing well production and system overall efficiency. This is not always true. In some cases, increasing fluid over the pump lead to more production, improving subsurface pump volumetric efficiency and improving system efficiency.

The main purpose of this study is to investigate the effect of fluid level over pump on the overall system and production performance.

In order to achieve that goal, the Sucker Rod Pump design simulator with actual field data has been used‥ The study analyzes the effect of well inflow, fluid PVT, pump size, setting depth, and running parameters. Actual field data are used.

This study concluded that for wells producing with pump intake pressure below bubble point, especially low productivity wells, reducing pump intake pressure does not always increase well production. It also concluded that negative effect on the net production and equipment running live, which is in additional to increasing power consumption and reducing overall system efficiency.

This study summarizes the results and lessons learned from successful use of system design and operation. The study provides practical recommendations supported by a series of case studies and multiple field examples where applying such approach increases the well production and net profit.
Automated Forensic PDC Dull Analysis Enables Digital Feedback Loop
Authors: Devers Cameron , Dyer Warren , Lyles Dustin
Published: September 2022

A digital feedback loop is designed to facilitate collection and analysis of cutter wear on a large scale, propelling improved engineering decisions. An increase in data-oriented bit engineering design strategies produce more predictable performance differentials as designs are iterated. The results of implementing the feedback loop are compared to previous methods across several metrics. The digital feedback loop implemented is based on the idea that all aspects of PDC bit design should be centered around the collection and understanding of analytic data, and not subjective data. This is made possible by utilization of automated data collection techniques taking measurements of dull bits for all repaired dulls. The data collected is then compiled for analysis while simultaneously made available to all relevant parties. This process is continuously repeated for every dull bit. The integration of the digital feedback loop is built into the bit product development process and application specific cutter and design selection workflows. This integration minimizes forensic dull evaluation time investment to the point where data is collected, processed, and uploaded to analytics tools within minutes of a dull being received via automated metrology technology integrated into the repair process. The trend analysis, additional models and insight gathered from enhanced data collection and recording has additionally reduced the time it takes for bit design to reach the design proposal stage by 60%, while simultaneously increasing the number of metrics that are considered during the product development design process. The reduced time spent in bit design has led to reduction in time between bit order received, bit manufacturing and subsequent bit delivery. The overall improvements generated by the integration of this digital feedback loop have also resulted in insights not previously considered or reviewed due to lack of access to the information. These improved, data driven insights have increased the accuracy of the design process to improve probability of performance objectives of the new design being met on the first iteration rather than a continuous trial and error-based approach. The process discussed in this work describes the utilization of an automated forensic dull bit evaluation methodology that allows for a data driven method of improving PDC Bit design and application specific cutter and bit design selection while working to minimize the necessity of the subjective, visual based analysis of the common industry methods.
Assisting Production Decision Technology in Gas Storage Operation Based on Digital Twin Technologies
Authors: Wang Peixian , Li Zunzhao , Wang Xiaolin , Wang Gang , Li Mingyi , Yao Shizhe
Published: September 2022

Underground gas storage (UGS) is a method to ensure safe and stable supply of natural gas in China. The digital twin technologies, also known as Industry 4.0 technologies, play a more and more important role in digital and intelligent development of UGS.

Based on digital twin technologies, the assisting production decision technology which contains data layer, model layer, logic layer, interaction layer, is constructed. The data layer covers data from SCADA, equipment detection, GIS, etc. Using laser point cloud scanning, oblique photography, and 3d design software, the 3D model in the model layer achieves one-to-one reduction of the ground process of UGS. The simulation model in the model layer integrates reservoir or reservoir boundary, wellbore, pipeline, ground process simulation model, which can realize the whole process simulation of UGS. The logic layer takes the data information stored in the data layer as input, and adopts programming language or algorithm model to analyze and evaluate the process and equipment of UGS. The interaction layer is the visual window of the system, which can realize the visualization and scenario-based interaction of data.

The assisting production decision technology fuses historical data, real-time data, and predicted data to track the past, monitor the present, and predict the future. Firstly, it integrates all the needed data with 3D models visually. Secondly, the total elements information perception technology, augmented reality technology, three-dimensional visualization monitoring technology, etc. are integrated to observe and study gas storage. Last but not least, the high fidelity model of gas storage digital twin also helps understand situation, monitor equipment energy consumption, and make optimization decision.

Integrating digital twin technologies into intelligent and digital management of gas storage, so as to facilitate the personalized management of gas storage.
Improved Well Spacing Decision Using RTA: Workflow to Translate RTA Half-Length to Actual Depletion
Authors: Muralidharan Vivek , Esmaili Soodabeh
Published: September 2022

Rate Transient Analysis (RTA) is widely used in the industry to understand the Stimulated Reservoir Volume (SRV) of horizontal wells for forecasting and for comparing well performance. However, significant well interferences are observed while using SRV dimensions obtained from analytical models in making well spacing decisions. The reason for that is the assumption of rectangular shape for SRV representation, which is not a realistic case. Upon drilling several pressure monitoring wells in the Permian Basin and comparing them with multiple diagnostic tools, we found that the actual SRV vertical drainage is not uniform. Inaccurate characterizations of fracture height and half lengths would result in either overcapitalizing the project or not draining the reservoir efficiently.

The objective of this study is to provide guidance for improving stacked development in the Permian Basin with the understanding of depletion patterns around individual wells both vertically and laterally. Pressure depletion profiles from several vertical monitoring wells in the Permian Basin are used to define the depletion patterns. Downhole microseismic data are also utilized to bridge any gaps. Several fully developed sections are used as case studies to validate the frac geometries and assumptions. The learnings from this study will be tremendously useful in applying RTA to optimize vertical and lateral spacing of unconventional wells across the Permian Basin.
Demonstration Numerical Simulation of Field-Scale CO2 Sequestration Project with Complex Faulting System in San Juan Basin, USA
Authors: Tu Jiawei , Ampomah William , Moodie Nathan , Ulmer-Scholle Dana , Martin Luke , Wells Elizabeth , Parwar Rajesh
Published: September 2022

San Juan Basin (SJB) is a geologic structural basin located in northwest New Mexico. Comprehensive field-scale reservoir simulation work was performed in finely constructed basin-wide geologic models, targeting sequestering over 120 million metric tons of CO2 for a period of 20 years. Petrophysical properties were populated through well logs and measurements on core samples obtained from nearby wells within the study area. Various critical storage trapping mechanisms were considered. The threshold pressure in delineating AoR is formulated based on guidance provided by the Environmental Protection Agency (EPA) to ensure the safety of underground drinking water sources (USDW). Besides, a complex faulting system identified on the west side of the basin was modeled to preclude risks of CO2 migration. The faulting system at the northwestern SJB was identified through well log stratigraphy. A near-vertical faulting system was mapped that may pose uncertainties to the sealing capacities of the caprock layer. The preliminary structural map shows a relatively flat topography that deepens to the east; and a high area in the west-northwest that is produced by faulting within a Hogback Monocline. The relief on the fault/monocline averages around 4,000 to 4,500 feet. Our simulation results indicate that SJB has the potential to safely contain the proposed amount of CO2 and avoid the impact of faulting systems. Further, pressure build-up in the injection zone is the most influential factor that may endanger the drinking water aquifer through the active injection and post-injection site care phases compared to CO2 plume migration. Controlling the size of AoR will increase the overall storage capacity within the area of interest while cutting down the overhead for corrective action planning and site monitoring.

This work employed realistic reservoir characterization data from San Juan Basin CarbonSAFE Phase III project to construct the reservoir simulation model, including 3D seismic, well logs, core analysis, and fluid sampling. As the worldwide commercial CO2 geologic storage projects aiming for soaring storage capacity goals, the processes in this work demonstrated the workflow to manage a large-scale CO2sequestration project in complex geological structured reservoirs.
Unlocking Stimulation Solution for Heavy Oil Production in Bentayan Structure Pertamina Hulu Rokan
Authors: Alfajri Reza , Sipahutar Herbert , Parsaulian Sakti , Herusakti S Adhi
Published: September 2022

Producing heavy oil requires more efforts than usual. Low degree of API, High viscosity, and high pour point make producing wells with this oil type quite challenging. B Structure in Pertamina faces this challenge. Its oil has 15-200 API, 10-300 cp viscosity, and 1150 F pour point. Producing the wells results in either low production rate or water coning. Seeking optimal stimulation solution was the main activities in this structure for the last eleven years.

The search of suitable stimulation method for Bentayan structure has been started in 2010. There were four types of stimulation methods attempted during 2010 – 2020 before successfully unlocking the most suitable method in aromatic solvent stimulation. The previous methods were surfactant, microbial, mutual solvent (musol), and thermochemical stimulation. Surfactant stimulation can reduce IFT and change rock wettability by injecting surfactant chemical into reservoir. Microbial stimulation injects microbial bacteria into reservoir and let it produces enzymes that have the same effect as surfactant as well as shortens the length of hydrocarbon chain to make the oil lighter. Musol stimulation removes heavy hydrocarbon deposits, controls rock wettability and IFT, and prevents emulsion from happening. Thermochemical stimulation mixes two types of chemicals generate heat into the reservoir preventing heavy oil reaches its pour point. The last and most successful method is aromatic solvent stimulation that can dilute asphaltene and wax content of heavy oil.

Surfactant method was performed on total 12 wells in two separate occasions in 2010-2012 and 2019. This method was a success from 8 wells and generated production gain from 1 to 50 bopd. Microbial stimulation method was performed in 2017-2018 on 2 wells. Only one well contributed oil production gain. Musol stimulation was performed in 2016 on 3 wells, and 2 of them were successful with oil production gain of 10 and 77 bbls/d. Thermochemical was then performed in 2020 on 1 well, however the result was not satisfactory. No oil production gain generated from this stimulation method. The most successful stimulation that has been tried in this structure is aromatic solvent. It has been performed on 10 wells so far and 8 of them were successful and oil production gain ranges from 20 to 300 bbls/d. Not only generating high production gain, this method also opened the door for optimization because there is increase in pump submergence.

The results from these stimulation jobs shows provide a solution for heavy oil production in Bentayan Structure in Pertamina Hulu Rokan. As aromatic solvent stimulation method in this structure produces the most significant results, it is considered the unlocked solution and has been selected as the standard treatment in producing heavy oil in Bentayan
A Flexible Design Approach to Improve Economics of Shale Well Pads: A Case Study from the Appalachian Basin
Authors: Kumar Hemant , Bhinde Tej , Popa Andrei , Hopkinson David , De Neufville Richard
Published: September 2022

Unconventional oil and gas projects are long-term, capital-intensive investments with significant risks due to various unknowns. The main uncertainties include reserves, reservoir quality, expected production, and commodity prices. Operating companies need to make decisions at the start of the project to design wells/facilities that impact production and economics throughout the project life. The system may be severely constrained at the start of production and have excess capacity in late field life based on design decisions often taken at the beginning with limited information. A novel approach to improve economic returns from shale pads is presented here using a flexible design concept. A physics-based integrated model is coupled with an economics model to demonstrate the system via a field example from the Appalachian Basin.

A typical pad in Appalachia has fixed capacity gas processing units (GPUs) installed for each well. The current design does not allow for expansion or reduction of processing capacity if the reservoir quality or commodity prices are different from expectations. A flexible design allows operators to redeploy processing capacity to other pads under favorable technical and market conditions (reservoir conditions and product prices), thus, decreasing average costs and increasing profitability.

An integration platform was used to couple an economic model with a physics-based integrated production model consisting of a pad's reservoir, well and surface network. The coupled models were used to generate short-term forecasts (2-3 years). Scenarios were run on the integrated model based on defined uncertainties such as reservoir characteristics and economics.

We evaluated two flexible options, rental GPU and in-house GPU augmentation which were compared with the current fixed design. The results demonstrate that flexible designs result in higher (>5%) net present values (NPVs) for the project compared to fixed designs. Also, the flexible designs reduce the economic risk if the future market and operating conditions turn out to be unfavorable.
Optimizing Focused Reservoir Fluid Sampling Using a Deterministic Causation Artificial Intelligence Intuition Technology
Authors: Chakraborty Rabindra , Dong Chengli , Elshahawi Hani , Smith Jeroen , Ramaswami Shyam
Published: September 2022

Samples collected using Wireline Formation Testing (WFT) provide vital information throughout the lifetime of the reservoir. Contaminated samples can lead to erroneous fluid analysis results with potentially huge economic consequences. On the other hand, sampling operations need to be optimized to minimize the cost without compromising the quality of the collected fluid samples. Today the success of an operation depends on real time human interpretations of the fluid cleanup based on in-situ fluid properties as measured by insitu downhole sensors. There is a need for an application that can assist engineers to accurately infer the state of fluid contamination as well as recommend actions when an operation has gone astray.

We have developed and patented Intuition Technology, which is an advanced causation-based artificial intelligence framework designed to forewarn complex, hard to detect state changes in chemical, biological and geological systems. This paper describes the development of a WFT contamination forewarning application based on the Intuition Technology framework which de-risks the formation sampling process by advising real time decisions regarding the state of fluid contamination and recommending rate schedule or other changes that will help optimize the WFT operation. This application has potential to save millions of dollars per annum through operational optimization, value assurance, and risk mitigation.
History Matching and Forecasting Production Rate and Bottomhole Pressure Data Using an Enhanced Physics-Based Data-Driven Simulator
Authors: Li Ying , Alpak Faruk Omer , Jain Vivek , Lu Ranran , Onur Mustafa
Published: September 2022

For situations where performing reservoir management studies based on developing and running a full-scale reservoir simulation model is not plausible, physics-based and/or data-driven surrogate (or proxy) models may provide an attractive alternative. Recently, we developed a new physics-based data-driven model referred to as INSIM-BHP for reservoir flow and transport as a replacement for a reservoir simulator. INSIM-BHP provides rapid and accurate computation of well rates and BHPs for history matching, forecasting, and production optimization purposes. INSIM-BHP delivers precise BHP calculations under the influence of a limited aquifer drive mechanism. In this study, we present and investigate the application of INSIM-BHP to history match highly variable real-life (oscillatory) oil rate and BHP data acquired daily in multi-perforated wells. Previous versions of INSIM were never used to history match such data sets. INSIM-BHP represents the physics of two-phase oil-water flow more authentically by incorporating a harmonic-mean transmissibility computation protocol and including an arithmetic-mean gravity term in the pressure equation. As the specific data set considered in this study contains a sequence of highly variable oil rate and BHP data, the data density requires INSIM-BHP to take smaller than usual time steps and places a strain on the ensemble-smoother multiple data assimilation (ES-MDA) history-matching algorithm, which utilizes INSIM-BHP as the forward model. Another new development is the use of time-variant well indices and skin factors within INSIM-BHP's well model to account for the effects of well events on reservoir responses such as scaling, sand production, and matrix acidizing. A novel modification has been made to the well-head term calculation better mimic the physics of flow in the wellbore when the production rate is low, or the well(s) is(are) shut-in. We compare the history-matched oil rate and BHP data and forecasted results by INSIM-BHP with those from a commercial reservoir simulator. Results show that INSIM-BHP yields accurate forecasting of wells’ oil rates and BHPs on a daily level even under the influence of oscillatory rate schedules. Besides, INSIM-BHP can help diagnose abnormal BHP measurements within simulation runs. Computational costs incurred by INSIM-BHP and a commercial simulator are evaluated for the real data set investigated in this paper. It has been observed that INSIM-BHP simulations run more than ten-fold faster than a conventional reservoir simulator. Application results demonstrate that INSIM-BHP has great potential to be a rapid approximate capability for history matching and forecasting workflow in the investigated limited-volume aquifer-driven development.
Stampede Digital Twin: An Advanced Solution for Process Equipment Condition Monitoring
Authors: Rodriguez Dryonis , Clare Paul , Srikonda Rohit , Suvarna Monika
Published: September 2022

A dynamic digital twin solution has been implemented to enable process equipment condition monitoring on key topsides equipment such as gas compressors, compressor suction and discharge coolers, seawater lift pumps, cooling medium coolers, and various filters. Equipment condition monitoring is enabled by performing virtual measurements, equipment degradation assessment and detection of anomalous process conditions.

The existing Stampede Multi-Purpose Dynamic Simulation model was repurposed as a real-time performance monitoring model. This model was connected to a historian to read real-time data enabling virtual measurement and equipment performance analysis. Dynamic online clustering of the process variables measured from field and rolling regression on the performance monitoring model output is performed to estimate the remaining useful life and detect anomalous process conditions.

Virtual measurements from the real-time digital twin gives more insight into the performance of the production facility, which helps operators and engineers more efficiently troubleshoot equipment issues. The proposed data analytics methodology is implemented on a Boost Gas Compressor (BGC) installed on the Stampede facility. Two years of historic data from the Stampede facility has been used for this case study to estimate remaining useful life and detect anomalous operation conditions that result in damage to the system eventually requiring a replacement or causing a shutdown. For the BGC case study presented, we were able to detect the anomalous operating conditions for the BGC about 6 days prior to a defect being detected by the maintenance crew on the discharge cooler. It is possible to avoid damage to the gas compression system if we can detect when the BGC is being operated in an anomalous operating condition and prevent early replacement of expensive equipment.

The proposed dynamic digital twin provides better insights for condition monitoring of equipment in an oil and gas facility using both the field sensor data and the physics-based models. In addition to performance deviation measurements, integration of field sensor data with physics-based models provides virtual measurement at locations where actual field sensors are not available. Dynamic clustering helps tackle the lack of information about gas molecular weight in real-time.
Methodology to Estimate Low Grade Enhanced Geothermal System (EGS) Reserves Using Heat Extracted from Depleted Wells in High Temperature Shale Gas Formations
Authors: Ehlig-Economides Christine , Nikolaou Michael , Khan Murtaza Ahmed
Published: September 2022

Eventually there will be low-production gas wells in the Haynesville and Eagle Ford shale formations that are no longer monetized. The objective of this study is to assess the potential for repurposing multiple transverse fracture horizontal wells (MTFHWs) in these formations as low-grade enhanced /engineered geothermal systems.

We use DrillingInfo and other available data, including formation temperature, to categorize existing gas wells as active, depleted, and still on production or abandoned, and to estimate an abandonment time for those still on production. Once the categorization is done, further study applies machine learning to quantify the current and future EGS potential of these wells. Finally, the results from the preceding studies are used to evaluate how best to distribute power plants for effective use of these resources, and to estimate how much power generation is possible.

The result of this research is a methodology for forecast of EGS power generation potential of low-grade EGS reserves in the Eagle Ford and Haynesville shale gas formations. This forecast addresses both technical and economic aspects. In effect, this work also provides a methodology for assessing the economic potential of EGS from existing MTFHWs in other formations having sufficiently high temperature for low-grade geothermal heat extraction.

This research provides input to support potential EGS development in Texas that could provide clean and affordable continuous (unfluctuating) power for small municipalities or industrial applications and/or as a contribution to the regional grid power supply.
Managing the High-Temperature Drilling Challenges of Deepwater HP/HT Wells: A Gulf of Mexico Case Study
Authors: Tchagop Alfred , Oyelami Opeyemi
Published: September 2022

High-pressure/high-temperature (HP/HT) drilling operations have unique challenges, which need to be carefully addressed. The need to address these challenges is because the search for additional hydrocarbon reserves is increasingly in the direction of frontier drilling.

Frontier drilling has more and more become an attractive option in the search for new hydrocarbon exploration and production. This drilling activity has been driven by the maturing of existing fields, the growing world demand for hydrocarbons, and technological advances. As proven fields are being depleted and because discoveries of giant fields have peaked, the greatest potential for new oil and gas discovery is in the frontier areas.

Frontier areas, defined as remote, hostile, and undrilled regions, are characterized by harsh climates or difficult environments. These environments include water depths greater than 2,000 ft, and downhole pressures and temperatures exceeding the equipment and tool ratings required to explore or develop those reservoirs.

The HP/HT environment limits the availability of equipment employed to operate safely and efficiently. The energy industry is constantly designing and developing equipment and operational workflows capable of operating in these HP/HT conditions.

This paper presents a systematic approach, which includes workflows and processes, to overcome the HT challenges in Gulf of Mexico (GOM) deepwater wells. The goal of these efforts is to enable safe and efficient drilling operations at temperatures greater than 302°F circulating bottomhole temperature.
Pioneering Oil-Degradable Nano-Composites for Deepwater Sand-Control Tools: To Preclude Annular-To-Tubular Communication During Deployment in Brine, and Degradation-To-Removal in Oil, Ensuing Production
Authors: Roy Ting , Ben Naceur Kamel , Singh Manjinder , Markel Daniel , Harp Leonard , Ardic Hifzi , Wilkinson Christian , Roy Indranil
Published: September 2022

In the energy industry many applications and embodiments are envisioned, for temporary sealing to dissolvables where deployed tools may remove themselves without any intervention, and on demand. Triggers for dissolution are often common downhole fluids of an aqueous nature. Metals designed to undergo accelerated corrosion via anodic dissolution or hydrolysable polymers triggered by brackish water, flowback or produced, facilitated by elevated downhole temperatures, are common. However, there is not a single formulation with tailored properties, engineered to degrade in presence of oil.

Here we present, industry's first oil degradable, nano-composite formulations, for HPHT temporary sealing. An application, as a one-way port plug or ball valve for deploying a sand screen using this novel technology will be ideal. The ball would seal against the flow-ports or nozzles when running in hole and circulating fluid through the screen to the toe and back up the annulus. Once the screens are set, and the well put on production, the oil will produce through the flow ports or nozzles, better known as inflow control devices or ICDs’ and drive the ball away. The ball is to be retained in a cage to allow unrestricted production. In reality, this solution however presents challenges. Production of solids, waxes and asphaltenes often gum up the ball in the cage and restrict production, often needing costly intervention. The ideal scenario will be if the ball seals can dissolve in produced hydrocarbons aka oil of varying API gravities. This will ensure unrestricted production, reduce possibility of intervention and rig time savings, all in all a step towards lowering our carbon footprint.

To augment the patented answer product, a step change in adding sensing and intelligence, nano-particulates and/or sensors as unique-identifiers are accommodated in the composite bulk, as tracers, control-released during degradation. As these nano-particulates, flow-back with production to the surface, these tracers with a unique fingerprint, are identified as they pass-through an in-line detector identifying the nano-crystal. The detector, comprising a remote computing system configured to store and relay information relating to these tracers is under development. This industry first is a paradigm shift in remote-monitoring, alerting any end user, anywhere in the world, of selected downhole event triggers, without running any device in the well.
Design Mud Weight and Control Breakout Width Based on Angle of Intersection Analysis
Authors: Zhang Jianguo , Edwards Stephen
Published: September 2022

Numerous wellbore instability problems have been reported when drilling through laminated shale formations because of anisotropic (weak) strength along bedding layers. The anisotropic strength is defined through the analysis of stress distributions around wellbore and angle of intersection (AOI) between well trajectory and weak bedding plane.

This paper presents a method to calibrate a wellbore stability model, design mud weight and control breakout width based on analysis of AOI and anisotropic strength. The proposed method includes four (4) steps as follows:

AOI is calculated by using bedding plane data (dip angle and dip azimuth) and well trajectory information (well inclination and azimuth). Based on single plane of weakness theory, the stress distributions around deviated wellbores in laminated shales are analyzed to show that failure can occur either along or across bedding planes depending on AOI. The profile of collapse pressure for both isotropic and anisotropic strength model are calculated along with the AOI. Drilling data (mud weight, cuttings/cavings pictures etc.) combined with azimuthal density image are used to choose and calibrate the wellbore stability model.

Lab strength test results with different angle to bedding plane are used to calibrate rock strength model and field data are collected and analyzed to define acceptable breakout width. Field data demonstrates that AOI can have a significant effect on wellbore stability. It is observed that severe borehole problems occurred in hole sections with low AOI (<30°) especially when a low mud weight is used to allow a wider breakout. Minor wellbore instability still occurred in some hole sections with low AOI even when the zero breakout criteria was used for mud weight selection. The instability observed can be attributed to swab – decreased ESDs being exerted on the formation while pulling the bottom-hole-assembly out of the hole and time-dependent effect.

The ‘zero breakout width’ criterion is recommended for AOI less than 30°, the ‘(90°-Inclination) breakout width’ criterion for AOI between 30° and 60°, and the ‘(90°-2/3*Inclination) breakout width’ criteria for AOI greater than 60°. If the mud weight window permits, then it would be beneficial to increase the mud weight by an extra 0.2 ppg to cover swab effects in shale formations that have an extremely low AOI (<15°). If not, mechanical means to prevent hydrostatic pressure drops such as slower pipe reciprocation or managed pressure drilling (MPD) need consideration.
The Redesign and Evolutive Development of Legacy Reservoir Data Management Systems – A Case Study
Authors: Pires Paulo , Gramorelli Fernanda , Nunes Fabiano , Elerati Luiz , Souza Fabio , Netto Carlos , Silva Charles , Nazareth Leandro
Published: September 2022

Apart from proposing fundamental changes in every part of the value chain (namely, people, processes, and technology), Digital Transformation may induce the abandonment of long-established legacy systems for new, modern technologies. However, instead of their replacement, the redesign and evolutive development of these systems might prevent negative disruption new software may cause on critical processes or routines. In this paper, the successful case of a Petrobras reservoir data management system is described. Relevant aspects related to redesign and evolutive development are discussed. The outcomes from this experience places the modernisation of legacy systems as valuable Digital Transformation strategy.
Improved Information Retrieval From Well Related Documents Using Supervised Learning
Authors: Miers Glenn , Czernuszenko Marek , Hughes Brian
Published: September 2022

We introduce a system for rapid retrieval of relevant well related information from a corpus of over 20 million documents. This allows for exploration workers to retrieve important business data more quickly. Tracking down all of the information required to make complex business decisions is a time consuming and error prone process. This poses a direct risk of expensive miscalculations and missed opportunities. A first version of this system is currently undergoing tests with select users. As the work here represents the first version of the system, it is expected that improvements will be made. This is a system that can be used at enterprise scale to enable searches to more easily yield usable information to workers.

This system uses a supervised learning model to identify well related documents from several categories. Examples of these categories include (but are not limited to) formation evaluation and well completion reports. A machine learning model was trained to classify documents according to input from a well document expert. This input came in the form of a set of labeled documents compiled by said expert. This model was then applied to over 20 million documents that are deemed relevant to the exploration process. The inferred classifications for each document were stored in a search engine in order to facilitate retrieval of documents by each of the labels from above. The benefits of this system are twofold. First, it reduces the number of documents that come back for a given search of a large corpus of documents. Second, it allows users without technical experience in well-related work to more easily find documents.