bluuebunny/crossref_metadata_2025 huggingface dataset:
Semi-Analytical Model of A Multi-Well System with well Interference During Underground Gas Storage
Authors: Chu Hongyang , Ma Tianbi , Jiao Yuwei , Zhu Weiyao , Zou Jiandong , Pan Yuewei , Gao Yubao , Lee John
Published: September 2022

Underground gas storage (UGS) is an important source for regulating natural gas supply. The large injection or production rate causes well interference in UGS to be particularly serious. Current well testing workflows for UGS assume a single well. This paper proposes a novel multi-well solution and related analysis method to analyze targeted well performance in a multi-well system. On the basis of the constant rate solution, Laplace transforms, and the superposition principle, we obtained multi-well solutions for transient flow. A systematic validation of the proposed method was conducted using a commercial numerical simulator for cases of gas storage and recovery process in UGS. Results show that the long-term gas injection and production process in UGS further exacerbates the influence of formation heterogeneity and interference. As adjacent wells are producing, the pressure derivative finally exhibits pseudo radial flow of the multi-well system under the influence of well interference. The horizontal derivative value is related to the dimensionless production rate of the target well, adjacent wells, mobility ratio, and the traditional 0.5 value. When adjacent wells are injecting, the last flow that appears in the derivative curve shows a drop-off feature. Our methodology applied to analysis of UGS performance in the Hutubi gas reservoir in China provides better estimates of the in-place natural gas resource and formation properties in this multi-well system. The methodology also provides a consistent and direct analysis of reservoir performance when "well interference "effects are observed.
The Positive Effect of Geomechanics on Adsorption and Transport Processes During Co2 Huff-N-Puff in Organic Shale
Authors: Zhang Wei , Mehrabian Amin
Published: September 2022

A thermodynamically rigorous constitutive model is used to describe the full coupling among the nonlinear processes of transport, sorption, and solid deformation in organic shale where the pore fluid is the binary mixture of carbon dioxide and methane. The constitutive model is utilized in a numerical solution that simulates injection of carbon dioxide in shale before producing carbon dioxide and methane from the same. The solution considers advection and diffusion as viable mechanisms of pore fluid transport where the latter comprises molecular, Knudsen, and surface diffusion in ultralow permeability shale. Results indicate that complete or partial exclusion of the coupling between sorption and solid phase deformation from the solution would result in underestimation of carbon dioxide storage capacity and natural gas recovery factor of the rock. In this aspect, sorption-induced deformation and strain-induced changes in gas sorption capacities are all conducive to both outcomes.
Rock Physics and Machine Learning Analysis of a High-Porosity Gas Sand in the Gulf of Mexico
Authors: Suleymanov Vagif , El-Husseiny Ammar , Glatz Guenther , Dvorkin Jack
Published: September 2022

Rock physics transforms established on the well data play an important role in predicting seismic rock properties. However, a data-driven approach, such as machine learning, can also estimate the targeted outputs from the well data. This study aims at comparing the accuracy of rock physics and machine learning analyses for the prediction of the P-wave velocity of porous rocks at the well log scale by employing the well data from the Mississippi Canyon, Gulf of Mexico.

Rock physics diagnostics (RPD) was used as a physics-driven methodology for predicting the P-wave velocity, while artificial neural network (ANN) was used as a machine learning approach. To train the neural network, the well data were divided into two sections where the ANN model was optimized on the upper well data interval and tested in the lower interval. During the rock physics analysis, the lower interval was employed to compare the obtained results from the physics-driven and data-driven approaches in the same well interval.

Based on the results from RPD, the constant cement model with a high coordination number describes the well data under examination. The established rock physics model is used for predicting elastic properties of rocks, including the P-wave velocity from measured petrophysical properties, namely porosity, mineralogy, and the pore fluid. However, the mineralogy input, such as the clay content, was missing in the well data. Therefore, the clay content was calculated from the gamma ray log and used in the rock physics model established. On the other hand, the ANN model was developed and tested using well log inputs such as porosity, gamma ray, and resistivity logs. Results showed that the accuracy of the machine learning model outperforms that of the rock physics model in the prediction of the P-wave velocity. In particular, a correlation coefficient (R) of 0.84 and absolute average percentage error (AAPE) of 2.71 were obtained by the ANN model, while the constant cement model reached CC of 0.65 and AAPE of 4.07. However, one should be aware that the computed clay content from the gamma ray log was a major factor in obtaining low CC compared to the ANN model as it significantly introduced uncertainty in our computations.
Nanotechnology Extended Release Asphaltene Inhibitor System/Formulation for Improved Squeeze Applications
Authors: Jayawickramage Rangana , Powell Kristin , Nguyen Bradley , Guraieb Paula , Tomson Ross , Salim Abdullah Dalia , Odeh Nadir , Punnapala Sameer , Pimenta Gervasio , Mark Fonseca Rahul
Published: September 2022

Mesoporous silica nanoparticles (MSN) are synthesized in the presence of asphaltene inhibitors such that asphaltene inhibitor is loaded within the nanoparticle carrier platform resulting particles with 50-400 nm average particle diameter. Particle size distributions, imaging of particles, surface charge measurements, and specific surface area measurements confirm successful synthesis. Synthesis parameters are customized to target particle size distributions, attachment to rock, inhibitor release rate, stability with time, temperature, shear and easy pumpability and no formation damage. Modification of particle surface chemistries was successful allowing for suspension in either aqueous or oil-based formulas and facilitate rock attachments. Further, these asphaltene inhibitor-loaded nanoparticles are synthesized in either an aqueous or oil solvents for customized squeeze design. Also, batch testing and measurements of core test effluents indicate that asphaltene inhibitor is successfully contained within nanoparticle carriers. These formulations have a 3x increase in treatment time compared to commercial asphaltene inhibitors in labscale core testing. This is a successful proof of concept that such nanoparticle systems can be pumped into reservoir material and provide a controlled release of asphaltene inhibitor.
Agile – Scrum Based Approach to Identify and Evaluate Opportunities in a Mature Field
Authors: Kannan Subash , Natasha Jeansonne , David Work
Published: September 2022

Agile, a Scrum-based project management approach, is typically used in the software development arena, but also has applications in the oil and gas industry. This paper demonstrates the feasibility of this project management approach when applied to a full field, subsurface development evaluation. Using this method for a multi-reservoir evaluation improved the quality and speed of decision making. The Agile methodology uses the Scrum process – a term borrowed from rugby where teams push the ball towards the goal together. We share a case study discussing the objectives, best practices, and lessons learned from evaluating a Gulf of Mexico producing field. Twelve reservoir intervals were thoroughly evaluated and ranked in only five months, a process that could normally take one to two years to complete.

The blueprint of the process involved Scrum lanes, sprints, and Minimum Viable Products (MVPs). Sprint meetings were held daily with the three core team members. Weekly Scrum lane updates were provided to stakeholders to show progress and potential opportunities identified. The Scrum lanes funneled the technical workflow into an iterative process across specific disciplines for multiple reservoirs, which culminated into economic evaluations. A Scrum lane tracker was provided to the management team for weekly updates. Weekly sprints helped the team create the priority list. In cases when there no reasonable MVP was identified, the evaluation was moved to a lower priority to allow refocus on other prospective intervals. The identified opportunities were then ranked using a pyramid hierarchy that was based on capital and regulatory requirements.

Using the Agile, Scrum-based approach for the analysis of multiple reservoirs in an offshore field proved to be highly advantageous. Even with a compressed timeline and small team, a high-quality technical and commercial product was delivered in a fraction of the typical project timeline. The level of technical detail when coupled with the relentless opportunity pursuit, frequent MVP results, and overall high energy level resulted in a positive and productive work environment that was acknowledged by the core team, asset peers, and management team. The success of this pilot project can be used and adapted as a template for future asset evaluations.
Successful AICD Application to Reduce Water Production in a Heavy Oil Greenfield
Authors: Pedroso Carlos A. , Rocha Paulo , Araujo Zaque
Published: September 2022

This paper aims to describe the successful use of AICD in Atlanta field, Eocene heavy oil reservoir located in ultradeep waters offshore Brazil. The HZ-OHGP with AICD installation and initial Atlanta's performance has been well described in previous papers (SPE-206153, SPE-199325, OTC-29757). This article will focus on the production analysis after 20,000,000 bbl produced in the field.

The use of AICD for reducing water production has been extensively reported in literature (SPE 187288-PA, OTC-27992, SPE-174341-MS, SPE-195617, OTC-30445, etc.). Atlanta's application, however, differs from others mainly for two reasons: first, and more important, the HZ-OHGP with AICD was installed in a green field, in the 3rd well of the Early Production System (EPS), before any water had been produced in the field. Second, all 3 wells were completed with a massive amount of oil and water tracers (6 for oil and 6 for water per well), which allows for in-depth analysis of the AICD performance, and an unprecedented comparison with 2 offset wells.

The results from the tracers indicate that the AICD achieved both objectives: equalizing the flux in the reservoir to the well and reducing water production, which, in Atlanta's EPS was especially important since the FPSO producing in this pilot project has limited water treatment capacity.

After 45 months and the total EPS production of more than 20.000.000bbl for the 3 wells, the one completed with AICD still has the lowest BSW, the highest production rate and the highest cumulative production. These results will be deeply discussed in this paper.
Reinjection of Produced Water with High Salinity After Applying a Novel Treatment Method
Authors: Mathews Tanya Ann , Hascakir Berna
Published: September 2022

This study investigates a novel method to reduce TDS in produced water to enable safe and effective reuse in hydraulic fracturing. In particular, we test whether evaporative technology can effectively separate dissolved solids from high-TDS wastewater produced in abundance in oil fields.

Experiments were conducted with distilled water (E1) and produced water (E2), among which the distilled water experiment served as a control experiment for comparison purposes. Produced water (PW) samples were taken from the Southern Midland Permian Basin. An evaporative air cooler was used for the experiments. We replaced the cellulose filters in the air cooler with Pozzolan filters as the latter is resistant to corrosion and can be easily regenerated. The filter was wet continuously by the water sample stored in the reserve tank of the evaporative cooling unit. Each experiment was run for 4 hours. To determine the system’s cooling efficiency, we measured inlet and outlet ambient temperatures, wet-bulb temperatures, dew point temperatures, and relative humidity every hour using a temperature humidity meter. In addition, the water samples were characterized before and after each experiment by measuring total dissolved solids (TDS), pH, particle size, and zeta potential.

Our experiments showed that E1 had a cooling efficiency of 21% while E2 had 16% in the laboratory environment, which does not have continuous airflow in and out like on the wellheads in an oilfield. Hence, we expect higher efficiencies in an oilfield. The reduction in cooling efficiency from E1 to E2 is primarily attributed to the precipitation of the suspended solids on the filter. Therefore, we recommend removing suspended solids from the water before filtering it through the evaporative cooling unit. In addition, we observed that the amount of water treated through the process was slightly less for E2 (35% of the initial volume) than E1 (40% of the initial volume). We believe this treatment efficiency can increase further if the experiments are conducted on the wellhead rather than in a laboratory. Furthermore, we observed a reduction in particle size and an increase in zeta potential in the reserve water post-experiment. In other words, the TDS was mainly eliminated and remained in the untreated water body, while the treated water contained significantly less amount of TDS with higher stability.

We prove that evaporative cooling is a novel method for low-cost TDS reduction. As a result, it can be instrumental in solving the decade-long problem of large volumes of high TDS wastewater produced during hydraulic fracturing, particularly in the Permian Basin.
A Novel Polysaccharide Friction Reducer That can be Used with Water of All Salinity Levels
Authors: Siddiqui Farhan , Emrani Arezoo
Published: September 2022

This work was carried out to compare a new system with synthetic polyacrylamide friction reducers used in the oil and gas industry. The most common friction reducers used for fracturing are anionic, and hence have limited use in high TDS brines especially in brines containing di and trivalent metal ions. When the new system is properly optimized, we were able to achieve a very efficient and low-cost carrier fluid that can give maximum friction reduction and effectively suspend proppant during a fracturing treatment.

The new technology for unconventional fracturing is a versatile and multifunctional product that can be pumped with the traditional frac equipment used in the industry for pumping powdered dry guar gum on the fly. The main objective of this work is to develop a new friction reducer formulation to aim to reduce cost and improve retained conductivity. This product is shown to be Gulf of Mexico green and biodegradable. Conventional breakers can be used to break these fluids and give excellent retained permeability on cores. The new system gives good friction reduction even at a very small dosage of 1ppt to 4ppt or 0.25-1.0 gpt, and it can be used similarly to guar gum as a linear gel or can be crosslinked with boron to yield better viscosity and proppant transport. The presence of iron in water can seriously affect the rheology and friction of traditional friction reducers, high viscosity friction reducers, and even guar systems. Laboratory studies have shown that this new product is very effective even in water containing very high concentrations of Ferric iron. Case histories from wells treated with this system containing high divalent and trivalent metal ions confirm the laboratory findings. In countries where equipment to pump on the fly is not available, the new system can be used as a slurry also.

This paper will present laboratory test results of using a new polysaccharide friction reducer with similar friction reduction to a Polyacrylamide Friction reducer and the proppant suspension of a crosslinked guar system. This system can be used with fresh or saline waters containing high concentrations of divalent and trivalent metal ions. This gives the operator the flexibility of using any water, and the water analysis step before a frac job can be eliminated.
Development of Multi-Stage Fracturing System and Wellbore Tractor to Enable Zonal Isolation During Stimulation and EGS Operations in Horizontal Wellbores
Authors: Fleckenstein William , Miskimins Jennifer , Kazemi Hossein , Eustes Alfred , Abdimaulen Dias , Mindygaliyeva Balnur , Uzun Ozan , Amini Kaveh , Hill Tom , Mailand Jason , Henschel Robert , King George , Ortiz Santos , Keyes Cullen
Published: September 2022

This paper discusses the progress on a project funded by the DOE Utah FORGE (Frontier Observatory for Research in Geothermal Energy) for the development of a subsurface heat exchanger for Enhanced Geothermal Systems (EGS) using unique casing sleeves cemented in place and are used first as a system for rapid and inexpensive multi-stage stimulations and second to perform conformance control functions at 225 °C. The proposed sleeves will use a single-sized dissolvable ball to open for fracture stimulation. After stimulation, and once the balls dissolve, the sleeves are open for immediate fluid injection. A separately designed wellbore tractor specific for both fluid detection and valve manipulation is then deployed to detect and control the injection entry points to create an effective EGS through paired horizontal injectors and open hole producers. The wells will be connected through multiple networks of induced and natural fractures that can be controlled throughout the field life.
Optimizing Wasson ROZ CO2 Flood Pattern Configuration for Capital Efficiency: Case Study of 40-Year Field History
Authors: Gang Tao , Jones Andrew , Painter Kaitlyn , Cestari Nicholas , Nezhad Shahin , Burgos Jorge , Bandyopadhyay Parag , Sahni Vinay
Published: September 2022

The use of CO2 injection to produce oil from the residual oil zone (ROZ) of the Wasson field in the Permian Basin has proven to be highly successful when an appropriate development plan is used. The significant volume of oil in place in the ROZ presents a large target for both reserves addition and CO2 sequestration. More than 60% of the ROZ potential lies beneath the already developed San Andres main oil column (MOC) area, which is under CO2 flooding with varying states of maturity, making it challenging to develop such projects efficiently and economically.

Over the past 20 years, different pattern configurations (nine-spot, line drive, five-spot) and completion strategies (commingled injector, injection subsurface flow control devices, dual completion injection, dedicated and hybrid line drive) have been used at the Wasson oil development company (ODC) field to develop the ROZ. The results of these various pattern configurations and completion techniques and their pros and cons are discussed in this paper. Commingled production makes it more difficult to quantify incremental ROZ production and increases uncertainty in the performance forecast of future ROZ projects. The dedicated injectors provide better injection control to MOC and ROZ and improve CO2 utilization, especially where the MOC is mature.

In this paper, we present one of the key findings from a detailed analysis of field history that caused Oxy to switch from the original dedicated ROZ development to a hybrid line drive pattern configuration. This novel strategy will have higher CO2 retention and more sequestration potential, better areal sweep efficiency for improved oil recovery, and lower capital and operating cost. It also reduces the likelihood of injector interference, provides a stable injection throughput for a long time, and results in a sustained oil and CO2 production plateau, which leads to more efficient utilization of plant capacity.

Using ODC as an example, the total capital, F&D costs, and the number of new injection wells will be reduced by 33%, 35%, and 45%, respectively, for changing all the undeveloped patterns from the dedicated to hybrid line drive option. This novel development strategy improves the chance of promoting contingent resources (not currently considered to be commercially recoverable owing to one or more contingencies) to a higher category and offers higher returns with much lower F&D cost and shorter development time.
Technical, Economic and Environmental Considerations for Selecting Next Generation Hydraulic Fracturing Equipment Technology
Authors: Fu Dan , Zemlak Warren , Yeung Tony , Barclay Caleb , Gorchynski Trevor
Published: September 2022

Recently, the North America Oil and Gas industry has seen a rapid increase in the adoption of new hydraulic fracturing technologies such as dual-fuel diesel engine, electric system powered by gas turbine or engine on-site and turbine direct drive technology, to reduce emissions and operating costs. The objective of this paper is to provide a detailed analysis of economic, environmental, and technical considerations when selecting the next generation hydraulic fracturing equipment platform.

It is believed that any next-generation technology must meet the following key requirements: 1. Reduction of GHG and EPA regulated emissions; 2. Reduced equipment footprint; 3. Capable of meeting the most stringent noise standard; 4. Improved reliability; 5. Improved pad-to-pad mobility; 6. Reduced maintenance and personnel costs; 7. Competitive capital cost. For the selection process, a methodology was developed to evaluate the energy density of fuel, thermal efficiency of prime movers, mechanical power transfer efficiency, and equipment operating environment and configuration against the above objectives. The methodology also considered the technical and commercial feasibility of key components.

Natural gas is selected as the mobile primary energy source due to its higher energy density and lower emission profile than conventional diesel, and more economical and widely available on-site. Among all available natural gas-powered engines evaluated, which included dual-fuel diesel engine, gas reciprocating engine, single large turbine and direct drive turbine, the direct drive turbine scored the highest. The direct drive pumping unit is equipped with a 5,000 HHP continuous duty power end driven by a 5,000 HHP dual shaft turbine through a single speed reduction gearbox. This combination provides the most efficient mechanical power transfer efficiency resulting in significant fuel cost savings and reduction in greenhouse gas emissions. Because of its high-power density, the direct drive turbine system can potentially reduce the number of on-site equipment by 43% and personnel by 31%. Comparing to other next generation hydraulic fracturing system, the direct drive turbine technology has the lowest capital cost per HHP.
Gas Transport Modeling in Organic-Rich Nanoporous Media with Nonequilibrium Sorption Kinetics
Authors: Liu Zizhong , Emami-Meybodi Hamid
Published: September 2022

We present a mathematical model for one-dimensional gas transport in organic-rich nanoporous media subject to nonequilibrium sorption. The model is developed from two governing equations to simulate Knudsen diffusion and viscous flow in the free phase, and surface diffusion in the sorbed phase. The pore space is shared between the free and sorbed phases by defining concentration-dependent free- and sorbed-phase volume fractions. The governing equations are coupled through a source/sink term described by a kinetic sorption model. The impact of the reduced effective pore space and sorption on free-phase mass transfer is characterized by defining effective diffusion coefficients. The governing equations are numerically solved based on the finite element method. The diffusion model is utilized to analyze the temporal and spatial concentration data obtained using X-ray micro-CT scans from two experiments, including Krypton transport into a coal sample and Xenon uptake into a shale sample. The proposed model can closely reproduce total concentration profiles in both experiments. The model also captures the concentration peak in Xe-shale system due to the significant nonequilibrium sorption and slower process of reaching equilibrium. The results show that surface diffusion dominates the total mass transport in Xe-shale system with higher adsorption affinity. In Kr-coal system with lower adsorption affinity, the sorbed phase contributes significantly to the total mass transport mostly at high pressures. In addition, the sorbed phase can occupy up to 30% of pore space, which reduces the free-phase diffusion coefficient by 40% in Xe-shale and 80% in Kr-coal. Accordingly, neglecting the sorbed-phase volume in nanoporous media may overestimate the effective free-phase diffusion coefficient.
Case Study: Plunger Lift Optimization Leveraging Physics-Assisted AI and the Impact on Greenhouse Gas Emissions Reductions
Authors: Olszak Evan , Yoho Michael , Greaser Ralph , Srivastava Ravi , Lanke Ramesh , Moffett Ross , Chan Chun Sik , Dabrowski Dariusz , Pond Burke , Hingerl Ferdinand
Published: September 2022

Natural gas has been playing an increasingly important role in the global energy transition with various efforts underway to minimize greenhouse gas emissions during gas production to align natural gas E&P operations with strategic ESG goals. Plunger lift (PL), one of the major artificial lift types applied to natural gas wells, leverages the potential energy naturally present in gas wells to lift liquid to the surface and hence has a lower operational greenhouse gas emissions footprint than other lift types leveraging pumps (ESP), compressors (Gas Lift) or electric motors (Rod Lift). A common challenge in PL wells is the occurrence of liquid loading events, during which the mass of the liquid column and plunger becomes too large to be naturally lifted, and manual intervention techniques are required to bring the plunger and liquid back to the surface. One such intervention technique is the venting of pressurized gas from the well. During this process, very large amounts of methane and other pollutants are released into the atmosphere, which not only presents a significant economic loss but also results in a substantial negative impact on the greenhouse gas footprint of the PL operation. This study presents results from a field pilot during which physics and AI-assisted technology are leveraged to automatically optimize plunger lift operations with the objective of minimizing flowing bottom hole pressure, decreasing the variance of plunger velocities, and avoiding plunger rise velocities that are outside safe operating standards. During the presented field pilot, production of natural gas was increased by 4% while the number of required venting events and the associated release of greenhouse gas was reduced by 48% due to enhanced well stability.

Novel/Additive Information

Fully automated setpoint management leveraging physics-assisted artificial intelligence algorithms was implemented in a field-based pilot, which resulted in a monthly production uplift up to 4% over plan as well as a 48% decrease in greenhouse gas emissions due to increased well stability and fewer venting events.
Design and Development of a High Pressure-High Temperature Wellbore Simulator for Investigation of the Impact of Cyclic Stresses on the Integrity of Wellbore Sections with Cement/Casing Interfaces
Authors: Lin Zichao , Kuru Ergun , Iremonger Simon , Yang Xinxiang , Fisher Blair , Spence Jeff
Published: September 2022

Understanding the mechanisms of leakage-pathway formation are crucial for proper assessment, remediation, and in the end, prevention of leaking wells due to severe modern-day well stresses such as multistage hydraulic fracturing operations. Aiming to improve the understanding of the drivers behind fluid leakage from wells subject to modern-day well stresses, an experimental study of the cement sheath integrity under downhole stress conditions was conducted using a custom-designed and fabricated physical wellbore simulator. The physical wellbore simulator was designed and constructed to be capable of measuring the permeability (up to nanodarcy level) of the cemented annulus between two casings under cyclic temperature and pressure conditions (up to 43 MPa and 120°C).

Permeability (nitrogen) of the casing-cement-casing system was measured under i-) non-cyclic temperature and pressure; ii-) non-cyclic temperature and cyclic pressure; iii-) cyclic temperature and non-cyclic pressure conditions. Potential leakage pathways were visually inspected after each experiment. The rough shear bonding strength between the inner casing and the cement sheath was also measured.

Three factors were identified as having the most significant impacts on the permeability of the cemented annulus between two casings: i). Cement and/or casing shrinkage/expansion caused by the temperature change, ii). Casing shrinkage/expansion caused by the inner casing pressure change and, iii). Test duration time (time after curing and before each permeability measurement). The final permeability of the cemented annulus was controlled by the combined effects of these three factors. Overall, cement was extremely resilient to stresses, and slight increases in permeability were only observed after subjecting the cement sheath to significant stress. Once the debonding occurred at the cement/casing interface due to the initial change in pressure and/or temperature, applying cyclic pressure load did not significantly alter the permeability of the cemented wellbore section. The shear bonding strengths were on the high side, and the final permeabilities were below or around the critical permeability of 0.1 mD (Ozyurtkan et al. 2013).

Through the development of the physical wellbore simulator the factors affecting the integrity of the cement-casing interfaces under representative real-world wellbore conditions of variable temperature and pressure conditions have been investigated. The improved understanding of the factors contributing to leakage-pathway formation are now being used to implement more reliable barrier technologies for effective mitigation of fugitive emissions.
RTA-Assisted Numerical History-Matching and Co-Optimization of CO2 Storage and HnP Performance for a Near Critical Gas Condensate Shale Well
Authors: Hamdi Hamidreza , Clarkson Christopher R. , Ghanizadeh Amin
Published: September 2022

Due to strong non-linearities in the diffusivity equation, numerically-assisted rate-transient analysis (RTA) techniques have been suggested for analysis of multi-phase production data from multi-fractured horizontal wells (MFHWs). However, these methods are based on some limiting assumptions that cannot be generalized for three-phase flow or when relative permeability is unknown. In this study, a new RTA-assisted history-matching technique is proposed to simultaneously match production data and diagnostic plots during the calibration process.

In the proposed method, the objective function is modified to include the derivative of the integral of rate-normalized pressure for the primary phases. As such, in the history-matching process using compositional numerical simulation, the flow regimes are also matched, which can increase the reliability of the calibrated numerical model. This approach is applied to a challenging dataset: production data from a MFHW completed in a Canadian shale reservoir hosting a near-critical gas condensate fluid. The calibrated model is then applied to co-optimize CO2 storage and oil production using a cyclic gas injection scheme.

The results demonstrate that when the modified objective function is used, the history-matching scheme will reject models that cannot reproduce the flow regimes even if the production data are visually matched. Another benefit of this modified history-matching workflow is that, unlike other numerically-assisted RTA techniques, it is not limited to any specific conceptual model or reservoir geometry. Further, interactions between parameters are accounted for during the calibration process. Co-optimization using the calibrated model leads to an optimized Huff-n-Puff (HnP) design that can produce 40% additional (incremental) oil, while around 17% of the injected CO2 is stored during the cyclic CO2 injection process.

In this study, a modified objective function is introduced for the first time to enhance the numerical history-matching process to ensure the resulting calibrated model can also reproduce the observed transient flow regimes. This approach is easy to implement and is not limited to a specific model geometry or any input-output relationship.
Economic Yardsticks for the End of Economic Life: Holdback and Its Adjuncts
Authors: Purvis D.
Published: September 2022

Traditional economic measures use chiefly net present value to compare on-going net revenue to plugging liabilities and other retirement liabilities, but operators onshore in the US plan to pay for plugging costs from cash flow. Liabilities have accumulated and continue to accumulate as operators defer plugging. At the same time, production declines, and cash flow tapers and becomes riskier.

When retirement liabilities become significant compared to thinned cash flow, traditional yardsticks obscure the risk of ultimate insolvency. Future cash flow becomes insufficient to fund liabilities years before the present value flags the inversion. Recognizing the cash shortfall – which can occur surprisingly early when liabilities are allowed to accumulate – can fundamentally change the way the investment is viewed, valued, and managed.

Planning, therefore, requires new economic yardsticks to characterize the nature of cash flows with large retirement obligations, what can be called "holdback" and its adjuncts. These yardsticks look differently at the timing and risk of asset retirement obligations, namely backward from the end of the projection. "Holdback" is analogous to payout but in reverse from the end of economic life. Related measures similarly use other conventional yardstick concepts in reverse to characterize the situation more fully and to help an operator avoid orphaning its abandonment liabilities to be paid by taxpayers.
Demonstration of Autonomous Drilling on a Full-Scale Test Rig
Authors: Mihai Rodica , Cayeux Eric , Daireaux Benoît , Carlsen Liv , Ambrus Adrian , Simensen Per , Welmer Morten , Jackson Matthew
Published: September 2022

During recent years there has been an increased focus on automating drilling operations and several solutions are in daily use. We describe here results and lessons learned from testing on a full-scale test rig, the next step in drilling automation, namely autonomous drilling. By autonomous drilling we mean a system capable of taking its own decisions by evaluating the current conditions and adapting to them while considering multiple horizon strategies to fulfill the drilling operation goal.

Autonomous drilling was demonstrated during a series of experiments at a full-scale test rig in Norway. The focus of the experiments was to reach the target depth as quickly and as safely as possible. Since the formation at the test rig is very hard, a previously drilled well was filled with weak cement of variable strengths to allow for fast drilling. As part of the experiments, it was planned to have drilling incidents to test the system capabilities in managing arising issues and recover from them. During the experiments no real-time downhole measurements were available, only surface data.

In total 500 meters have been drilled in autonomous mode. The autonomous system is built as a hierarchical control system containing layers of protection for the machines, well and the commands, in addition to recovery procedures, optimization of the rate of penetration and autonomous decision-making. The system continuously evaluates the current situation and by balancing estimated risks and performance, e.g. risk of pack-off versus prognosed time to reach the target depth, decides the best action to perform next. The autonomous decision-making system is tightly connected with the control of the drilling machines and therefore it executes the necessary commands to follow up the computed decision. Drilling incidents may occur at any time and an autonomous system needs to be able to adapt to the current situation, such that it can manage drilling incidents by itself and recover from them, when possible. During the experiments, several drilling incidents occurred, and the system reacted as expected.

Surface data, together with internally computed data from the autonomous decision-making algorithms, were logged during the experiments. Memory-based downhole data was available after the experiments were concluded. Based on all the data collected, an analysis of the behavior of the system was performed after the experiments.

During the drilling experiments at the full-scale rig, the autonomous system adapted its decisions to the surrounding environment and tackled both smooth drilling situations and drilling incidents. To cope with possible lower situational awareness, the autonomous system manages by itself transitions from autonomous to manual mode if necessary. This feature, together with fault detection and isolation capabilities, are crucial for safe operation of an autonomous system.
Polymer Augmented Low Salinity Flooding in Low Permeability Carbonate Reservoirs
Authors: Haofeng Song , Pinaki Ghosh , Annalise Bowers , Kishore Mohanty
Published: September 2022

Low salinity waterflooding improves displacement efficiency in initially oil-wet reservoirs if it can alter wettability, but it is often a slow process. Polymer flooding usually does not improve displacement efficiency, but enhances sweep efficiency. In this work, the synergy between low salinity and polymer flooding is studied for low permeability carbonate rocks. Polymer solutions were consecutively filtered through a 1.2 µm mixed cellulose ester membrane and a 0.4 µm polycarbonate membrane. With the proper preparation method, two polymers (HPAM and AN132) with the molecular weight of 6 MDa were successfully injected into the oil-aged carbonate rocks with the absolute permeability of 10-20 mD. Low salinity polymer flood was carried out using HPAM prepared in diluted seawaters (with modified sulfate concentrations). After extensive water floods, HPAM prepared in the 10 times-diluted seawater produced the same incremental oil recovery (4-5% original oil in place) as the ATBS-polymer AN132 prepared in the seawater. Increasing the sulfate concentration by four- and eight-folds doubled the incremental oil from low salinity polymer floods.
Investigation of Corrosion Inhibitor Actives for Anti-Agglomerant Low Dose Hydrate Inhibitor/Corrosion Inhibitor (AA/CI) Combo Products
Authors: Bartels Jeremy , Rana Geeta , Sharma Pritesh , Moloney Jeremy
Published: September 2022

Objectives/Scope

Anti-agglomerant low dose hydrate inhibitors (AA-LDHIs) have the potential to exhibit corrosion inhibition due to their phase-boundary association and surfactant properties as well as containing similar functional groups as corrosion inhibitors (CI). However, it is often found that AA-LDHI molecules, on their own, do not possess the corrosion inhibition efficacy to meet commonly used industry standard corrosion rate criteria of less than 4 mpy general corrosion and minimal localized corrosion, even when dosed at typical AA-LDHI treatment rates (at the percentage level). For offshore applications, where an operator may have limited umbilicals for production chemical delivery and are conscious of capital expenditure, a combination chemical product would be the preferred option. In the search for such a single umbilical combination product to provide both corrosion and hydrate protection, a highly effective AA-LDHI/CI combination product was formulated.

Methods, Procedures, Process

The newly developed AA-LDHI/CI product was first evaluated in the laboratory under field simulated environments: rotating cage autoclave (RCA) to test corrosion inhibitor performance and visual sapphire hydrate rocking cells to test anti-agglomerant performance before being taken to the field.

Results, Observations, Conclusions

The corrosion inhibitor performance testing was conducted under sweet conditions using RCA at a temperature of 158 °F and a shear rate of 40 pascals. The post-test coupons were further evaluated for pitting corrosion performance using Vertical Scan Interferometer and coupon surface features were measured. After a 7-day test, the AA-LDHI/CI reduced the general corrosion rate to <4mpy whilst localized corrosion features were no greater than what was already present on the surface before exposure. The product was also tested for AA-LDHI performance utilizing visual sapphire hydrate rocking cells at 2,000 psi and 40 °F under shut-in/restart conditions which showed no impacts on performance when compared with the AA-LDHI chemistry by itself at the same dosage.

Novel/Additive Information

The paper describes the development and laboratory testing of new AA-LDHI/CI combination products that showed exceptional corrosion inhibition performance while also maintaining hydrate inhibition metrics with no change to secondary properties and with positive sustainability impacts. After laboratory development and testing, the new product was then field deployed. Preliminary data from an ongoing field trial is also shared.
Flowing Bottomhole Pressure Prediction with Machine Learning Algorithms for Horizontal Wells
Authors: Baki Sohrat , Dursun Serkan
Published: September 2022

Flowing Bottom Hole Pressure (FBHP) is one of the critical parameters during evaluation of unconventional oil and gas horizontal wells. The FBHP is mainly used for production optimization, calculation of productivity index and assessment of well performance evaluation with respect to offset wells. To calculate FBHP, production engineers use physics-based models and empirical correlations calibrated with actual physical measurements from offset wells. The objective of the paper is to develop a data driven approach for prediction of the FBHP with machine learning algorithms during post frac flowback period with multi-phase flow regimes. Surface production data from 30+ wells were collected with the key attributes such as wellhead pressure, gas rate, condensate rate, water rate, wellhead temperature, choke size, fluid density. FBHP was calculated based on physics-based software calibrated with physical downhole pressure gauges. In machine learning workflow, data collection and cleaning, exploratory data analysis, train-test split, pre-processing, cross-validation and tuning tasks were employed to obtain the accurate and generalized predictive models. Ensemble tree-based, support vector machines, and neural network models were explored in this study and their performances were evaluated by several regression error metrics. Analysis of model results showed the potential of machine learning approach for predicting the FBHP especially in multiphase flow regime. The model results showed accurate prediction of the FBHP within acceptable confidence interval application period. It is important to note that model accuracy dependents on testing period and flow condition as expected from interpolation nature of machine learning predictive models. The models were applied to new wells which were not used in the training process. The prediction results on the new wells showed outstanding performance and thus enabled decision making for wide area of application. This study shows that machine learning based predictive models can learn the patterns in complex parameters governing the FBHP behavior. Furthermore, robust machine learning models can be used for different phase of production period to optimize field development.
High Temperature Dissolvable Materials Development for High Temperature Dissolvable Plug Applications
Authors: Yue Wenhan , Ren Jiaxiang , Yue Jianpeng , Cheng Peng , Dunne Tim , Zhao Lei , Patsy Matthew , Nettles Damon , Liu Yu , Liu Huailiang
Published: September 2022

Dissolvable tools have been used more in unconventional oil and gas operations in recent years. Currently, more and more wells in Southwest of China quires high temperature (HT) dissolvable plug. The HT dissolvable plug needs to hold pressure in water at 150°C for 24 hours. On the other hand, the dissolvable plug needs to be dissolved in 1% KCl at 95°C in less than 15 days. These requirements put big challenges on dissolvable materials.

Several HT dissolvable rubbers were developed to meet the requirements. The ambient and high temperature tensile testing were performed on the dissolvable rubbers. The dissolution testing of the dissolvable rubber was performed in brine at 140°C for 1 day and then at 95°C. Several dissolvable metals were developed and the slow strain rate testing (SSRT), Scanning electron Microscope (SEM)/Energy Dispersive Spectroscopy (EDS) testing were performed on these dissolvable metals. A special coating was developed to reduce the stress corrosion cracking of the dissolvable metals. Two HT dissolvable plugs were developed based on the dissolvable materials. The pressure holding testing and dissolution testing were performed on the two dissolvable plugs.

It was found that the tensile strength of the HT dissolvable rubber at 150°C was higher than 1200 psi and elongation was higher than 700%, which was higher than that of most of the commercial HT dissolvable rubbers. The dissolvable rubber coupon disintegrated to tiny pieces at 95°C in 4 days. One dissolvable metal displayed better stress corrosion cracking resistance than the other dissolvable metals. The dissolvable metal promotes discontinuous grain boundaries and secondary phases within the grain boundary to prevent crack growth and propagation at the expense of strength. The dissolvable metal was used for lower slip of the dissolvable plug. The special coating on the dissolvable metal significantly reduced the dissolution rate of the dissolvable metal at high temperature. The two dissolvable plugs passed the pressure testing a of 10 ksi at 150°C in water for 24 hours. The dissolvable plug was dissolved in 1%KCl at 95°C in 14 days. The weight loss of the plug was more than 95%, All the remining residues of the dissolvable plug was less than 2 cm. The pressure holding and dissolution testing results of the dissolvable plug successfully meet the field testing requirements.

This is the first time in the industry based on our knowledge a HT dissolvable plug passed 150°C, 10 ksi 24 hours pressure holding test in water and then dissolved in brine at 95°C in less than 15 days. The HT dissolvable rubber was specially designed to possess both high mechanical properties at 150°C and dissolution properties at 95°C. The dissolvable metal for lower slip was formulated to prevent crack growth.