bluuebunny/crossref_metadata_2025 huggingface dataset:
Production Data Analysis of Shale Oil Reservoir Using the Dynamic Drainage Pore Volume Concept: Lessons-Learned from Well-To-Well Fracture Driven Interaction in Lucaogou Shale Formation
Authors: Pan Yuewei , Qin Jianhua , Zhang Jing , Shang Jianlin , Ma Wei
Published: September 2022

Many pilot researches consider production gains or losses in parent/child wells in short-term thereby determining the optimal completion parameters (eg. well spacing, stage spacing). Long-term recovery varies from negative-to-positive during the post-frac-hit evaluation based on the magnitude of the pressure sink and the distance of parent/child wells. However, quantitatively analyzing frac-hits impact remains unsolved. This paper presents a novel workflow combining RTA diagnostic plots and the prediction of dynamic drainage pore volume (DDPV) to analyze the frequent well/well fracture-driven interaction (FDI) (commonly referred to as frac-hits) in the Lucaogou shale formation, Junggar Basin.

According to the published knowledge, different strategies have been employed in Lucaogou formation to minimize the negative effect and to avoid the parent/child wells (e.g cube-development). Thus, optimizing stage, cluster and well spacing in well-pad zipper-frac development is in necessity. This paper first reviews the frac-hit mechanisms in both parent/child wells and well-pad zipper-frac development. We then characterize, quantify and rank the historical frac-hit events in Lucaogou formation based on the documented data. With the prediction of DDPV using numerical integration/differentiation assisted by diagnostic plots and specialized plots in RTA (eg. flowing material balance plot, square-root-of-time diagnostic plot), the pressure sink front can be acquired. The accuracy of DDPV forecast is validated using a synthetic case study. We further apply it to three field case studies to demonstrate the versatility and applicability of the proposed workflow.

The successful applications suggest that the proposed workflow is an alternative to making field-development decisions, minimizing the negative impacts of frac-hits and thus freeing the cashflows. The outcomes are mainly but not limited to: 1) the common early departures from linear flow regime are in good alignment with the DDPV forecasts in both parent/child and well-pad development scenarios; 2) A competition of the per-well DDPV might be triggered during frac-hits in parent/child well and 3) long-term recovery in well-pad development with a tighter well-spacing might be boosted with a smaller per-well DDPV and DOI.
A Case Study of Flare Gas Reduction and Power Generation
Authors: Cottingham Byron , Bowman Zach , Kirch Paul
Published: September 2022

In the current energy industry, there is a strong emphasis on environmental, social, and governance (ESG). Specifically, managing the flaring of natural gas. Globally, 142 bcm of natural gas was flared in 2020. This resulted in around 265 Mt CO2, nearly 8 Mt of methane, and other GHGs being directly emitted into the atmosphere (Schulz, 2021). We have a focus of eliminating the emissions surrounding flare gas by utilizing the EPA’s Avoided Emissions and geneRation Tool.

The technology does this by utilizing a waste gas stream that would otherwise be combusted or flared and turn it into useable grid power. The waste gas stream is collected from the well and production equipment, then combusted in a natural gas generator. Power from the generator is converted to DC power, sent to a small capacitive bank, electronically synced, and sold back to the power grid using a 208 or 480v 3 phase connection. All applicable operational data is collected via sensors (power, pressures, errors, flow), stored in a database, and visualized through a website.

This paper presents and discusses a case study of using this waste gas stream technology to not only generate electricity but significantly decrease the emissions into the atmosphere through the EPAs avoided emissions tool. The first step involves identifying the appropriate pad site with stranded or flare gas volumes of at least 50 mcfd. Once a site is identified, the next step involves determining what the electrical infrastructure on location comprises and if it has 480v 3-phase power. With the location identified it is time to bring the unit on site. The unit is comprised of a natural gas generator skid and the patented technology skid. We installed a VRU and tied directly into the flare line and through a scrubber to the generator. The next step is to move the power to the proprietary technology skid unit and clean the DC power to grid acceptable AC power. We then moved the clean AC power to run the production equipment on site and the balance onto the power grid. On our case study test site, we captured 1.4 mmcf that would have otherwise been leaked into the atmosphere and generated approximately 80 MW that was sold back to the grid.

The technology presented in this paper reduced GHG emissions, provided a power source on location, and generated revenue for the operator. Our case study application would reduce GHG emission by approximately 3,400 lbs. in a one-year timeframe. The result of this technology is a new and novel technique for the energy industry to use to decrease emissions, generate onsite power, and generate revenue from selling power back onto the grid.
Autonomous Inflow Control Valves Restore Oil Production by Controlling Gas and Water Breakthrough in Acordionero Field, Colombia: A Case Study
Authors: Kearns Kent , Rios Felipe , Montero Jesus , Uzcategui Alberto A. , Fipke Steven , Molina Juan Luis , Mohd Ismail Ismarullizam
Published: September 2022

The Acordionero field is located in the Middle Magdalena basin of Colombia and produces from 2 main multilayered formations. Water injection is utilized to maintain reservoir pressures and improve recovery factors. API gravities vary between 14° and 24°. C&P vertical wells are drilled to access oil from several producing intervals. This inherently creates a challenging production environment, as injection water and/or formation gas can unpredictably breakthrough in any of the formation layers, impacting well performance and leading to well shut-ins and expensive workovers to re-establish production.

Even though Inflow Control Devices (ICDs) and Autonomous Inflow Control Devices (AICDs) have been successfully deployed to control unwanted fluids in oil producer wells, its application in vertical wells have been limited. The challenging environment and the inability to identify the problematic intervals led to the selection of the AICD-Valve due to its ability to autonomously shut-off gas/water based on the fluid properties of each zone. This technology is sensitive to both fluid viscosity and density and can autonomously choke zones that have higher gas/water concentrations. A detailed study was conducted, including well simulations and analysis of production data, which determined the benefits of the technology, particularly to control gas breakthrough.

A total of 6 wells have been retrofitted to date. Overall results have been positive with the AICD-Valves successfully restricting flow from intervals with unwanted fluids and applying a more effective drawdown to oil-rich zones. Gas production have been reduced to more than 50% in all wells and in some cases over 90%. The electric submersible pumps (ESPs) have shown a more stable behavior in comparison to pre- AICD-Valve installations, reducing gas locking events, leading to less common failures and well interventions. Water control is still under evaluation due to the obtained production results.
A Novel Cost-Effective Stimulation Workflow Unlocks New Perspectives for Matrix Acidizing in Fractured Carbonate Reservoir – A Case Study from Egypt
Authors: Hegazy Amr , Abdel Hakim Emad , Farouq Mohamed , Badran Hesham , Shalaby Roshdy , ElKaragi Alaa , Saleh Khaled
Published: September 2022

Matrix acidizing can effectively stimulate carbonate reservoirs, often resulting in skin factors on the order of –3 to –4. Wormholes can effectively connect the well with the reservoir. However, if the carbonate reservoir is naturally fractured, it will be difficult to generate dominant wormholes using conventional matrix acidizing. Hence, an effective acidizing technique is crucial to handle such heterogeneous carbonate rock, especially if the permeability contrast is vast between the matrix and fracture.

This paper exhibits a novel workflow developed by a multidomain team to reveal the true potential of the fractured carbonate reservoir in a heterogeneous complex basin in the Eastern Desert in Egypt called the GoS basin. The new logging program uses high-resolution wellbore imaging, nuclear magnetic resonance (NMR), and casedhole pulsed neutron logging technology and processing algorithms to record capture and inelastic elemental spectroscopy for matrix parameters, detailed mineralogy, and oil saturation. The output of this characterization portrayed complex challenges that prevent having defined acid distribution between the flow zones of the natural fractures and the unfractured matrix due to the permeability contrast of 130:1.

The key to success in dealing with such stimulation jobs is choosing the optimal chemical diversion, main acid treatment, pumping placement, and establishing a fit-for-purpose pumping schedule. Many experimental and laboratory tests were performed to prepare a viscous pill to be utilized as temporary isolation for the fracture or the fissures network prior to starting the full acid treatment. In addition to that, employing a passive diverter instead of an active acid-based diverter was a seamless technique to divert the acid away from each zone after pumping. The results of this novel workflow and the new acid technique indicate a sixfold increase in well productivity. The falloff analysis followed by the viscous pill reinforces the potency of the temporary isolation; this aids in treating the lower-permeability layers, which are the candidates for matrix acidizing. The applications of this novel workflow unlock the true potential of the lower-permeability reservoirs and maximize the estimated ultimate recovery.

This paper showcases our experiences with the use of this unique recipe in fractured carbonate reservoirs, and in reservoir characterization and provides lessons learned to fill knowledge gaps in this area and provide a complete workflow that can be utilized everywhere worldwide.
Success Story of Designing the First ESP-AICV Integrated System
Authors: Almusharraf Abdullah , Alghamdi Anwar S.
Published: September 2022

Electric Submersible Pumps (ESPs) are one of the most commonly used means of artificial lift, producing higher oil rates compared to other methods. On the other hand, Autonomous Inflow Control Valves (AICVs) have been proven effective to reduce water or gas production in high GOR wells. The objective of this paper is to address ESP design challenges when combined with AICV completion.

In AICV completed wells, reservoir parameters such as well productivity index and bottom-hole pressure may vary throughout the lifespan of the well which must be taken into consideration during ESP design. Multiple trials were attempted using ESP design models to cover optimal-case and worst-case scenarios at open and closed AICVs. Each scenario was presented with a different productivity index and bottom-hole pressure with corresponding flowrate, motor load, and motor temperature. In which, the ESP design ensured continuous flow to the surface, no gas presence at the pump intake, and sufficient flowrate for motor cooling, within acceptable pump thrust and motor load ranges.

Results have shown that following comprehensive ESP design modeling in AICV completed wells can potentially yield a resilient ESP system that can withstand dynamic reservoir conditions. It was observed that the AICV position has a direct impact on the productivity index. An open AICV increases the productivity index, whereas a close AICV reduces the productivity index. Moreover, reduction in productivity index drives down reservoir downhole pressure and pump flow rate, which increases the possibility of gas present at the pump intake and ESP motor overheating due to insufficient flow for cooling. ESP equipment was carefully selected to accommodate the fluctuating reservoir parameters. As a result, the ESP was integrated into the AICV completion and delivered the desired rates with minimal water cut and at the desired operating conditions.

This paper demonstrates a novel approach to designing ESP systems compatible with AICV technology by illustrating important factors to be considered in such complicated completions.
Fracture Conductivity Created by Proppants and Acid in the Austin Chalk Formation
Authors: Brashear A. T. , Hill A. D. , Zhu D. , Kerr E. , Scofield R. , Jordan D. , Estrada E. , Tajima T.
Published: September 2022

The Austin Chalk formation has seen numerous periods of active development since the early 1980's and has recently become a new focus as an unconventional resource. Due to the low permeability, fracturing, with proppant or acid, is required to economically produce the reservoir. This study presents the results of a series of conductivity tests performed to evaluate the stimulation efficiency of proppant fracturing and acid fracturing in the Austin Chalk.

The study uses both downhole core and outcrop samples. The downhole cores were from an Austin Chalk well in Webb County, Texas. The outcrop samples were collected from similar Austin chalk sub-intervals that the core samples were from and were collected from a road cut in the Del Rio, Texas area. Testing samples were prepared for the fracture conductivity tests based on API RP-61. Fracture surfaces were created either by tensile fracturing the sample, or by saw-cutting. For acid fracture conductivity, 15% HCl was injected to create acid-etched surfaces, and the effect of acid contact time was investigated. For propped fracturing, proppant size and concentration were set as study parameters. The fracture surfaces were scanned before and after each experiment in order to characterize changes in the fracture surfaces, such as acid etching and proppant embedment. Proppant size distribution was measured by sieve tests before and after conductivity measurement to evaluate proppant crushing. Closure stress up to 6000 psi was applied during the conductivity measurements, and some experiments stopped before reaching this upper limit because the sample lost mechanical integrity under a lower closure stress.

The study results show that because the mechanism of creating conductivity is different for acid fracturing and propped fracturing, the conductivities from the two stimulation methods behave differently. The initial conductivity varies but the level of conductivity at low closure stress generated from acid and proppant are similar. The conductivity from propped fracture exhibits a semi-log decline trend, with a low decline rate and sustained conductivity at high closure stress. The conductivity from the acid fracture experiments strongly depends on acid injection conditions and mechanical integrity of the rock after acidizing, indicating that design of the stimulation is critical for a successful treatment. Acid fracture conductivity in general declined more rapidly with increase in closure stress than did proppant conductivity. The observations from the experimental study revealed that both acidized and propped fractures have potential to create sufficient conductivities in the low permeability Austin Chalk formation.
Integrated Characterization of Sand Production for Clayey-Silt Hydrate Formations by Coupling Geomechanics and Pressure Gradient-Based Sand Failure Criteria
Authors: Yurong Jin , Daoyong Yang , Yanlong Li , Nengyou Wu
Published: September 2022

In this work, a robust and pragmatic technique is developed to characterize the sediment deformation and sand production for clayey-silt sediments in the absence and presence of hydrate by coupling reservoir simulation and geomechanics. Such an integrated model considers the pressure gradient-based (PGB) sand failure criterion, changes in both porosity and permeability, and the three-dimensional (3D) displacement dynamics (i.e., deformation). Within the modified hydrate reservoir simulator, its geological module including displacement dynamics and changes in porosity and permeability due to deformation is solved with the staggered grid finite difference approach. Subsequently, the proposed model is validated by reproducing the experimentally measured profiles for both hydrate-free and hydrate-bearing sediments under various conditions. Excellent agreements between the measured profiles and simulation data have been achieved. It is found that, for the radial consolidation, the unconsolidated clayey-silt sediment is excessively compressed with a slight increase in external pressure (σex<0.50 MPa), and then the compaction rate slows down. Consistent with the gas and water production, the sediment subsidence is also composed of three stages, i.e., before hydrate dissociation (confining stress dominated), during hydrate dissociation (both confining stress and hydrate cementing effect), and after hydrate dissociation (confining stress dominated). The numerical results show that the sediment subsidence plays a critical role in porosity variation compared with sand creeping (i.e., development of wormholes or fluidization channels), while the permeability increment from the sand creeping substantially exceeds the permeability impairment from sediment subsidence.
Forward Modeling of Natural Fractures within Volcanic Reservoir by Using Continuum Damage Mechanics
Authors: Shen Xinpu
Published: September 2022

By using the continuum damage mechanics’ model and finite element numerical simulation technology, this paper studies natural fractures’ distribution within volcanic reservoir and presents numerical solution of contour of damage variable which represents distribution of natural fractures within target formations. Workflow of numerical calculation was proposed. These techniques were applied to investigate natural fractures distribution generated by tectonic movement within volcanic reservoir of an oilfield in west China. Quasi-brittle plastic damage model is used to simulate fractures generated by technical movement within volcanic formations given in this region. Initial-strain-method is used to simulate loading applied to target formation caused by tectonic movement instead of using boundary displacement loading. Different values of magnitude and orientations of principal strain components have been tested in order to find their proper values. Values of parameters of damage models are calibrated by matching numerical results of natural fractures’ distribution to those obtained by interpretation of seismic data. Principal results are: (1) in the upper Triassic Xiaoquangou formation reservoir and the lower Tiaohu formation reservoir, numerical solution of natural fractures’ distribution is consistent with those obtained from interpretation of seismic data. (2) The maximum value of damage variable of the upper Triassic Xiaoquangou formation is 0.2678, i.e., the degree of crushing is 26.78%. The width of the zone of damage localization is about 10 meters to 300 meter. The maximum value of damage variable in the lower Tiaohu formation is 0.2569, which is slightly less than that in the upper Xiaoquangou formation. (3) Within the target block, zones of natural fractures are mainly distributed in central-east part of the block. Therefore the planned new wells should be located in this part of the block. Zones of natural fractures in the west part of the target block are in the shape of narrow bands which are lack of connections, and thus this west side of the block is not a good place for new wells. This case study provides a best practice for identification of natural fractures within volcanic reservoir.
Novel Deployment of Noninvasive Sensing Technology Improves Wellhead Installation
Authors: Lim Haw Keat , Hogg Bruce , Gil Alberto , Lee Yong Wee , Ozen Onur , Loviken Pontus , Kherroubi Josselin
Published: September 2022

Correct installation of the wellhead is crucial to drilling operations. As drilling activities come to involve increasingly critical and challenging operations, the demand for improved reliability, performance, and safety continues togrow. Hanger and packoff installations during well construction can be negatively affected by debris, misalignment, and stuck casing, either independently or in combination,leading to costly downtime. Currently, these installations are verified using manual methods (markings, visual inspections, and weight indications), posing a high potential risk for errorsas a result of human factors. The wellhead installation digital position sensing solution removes the human factor and provides assurance that the equipment is properly landed as designed.

The wellhead installation digital position sensing solution is the industry’s first digital installation advisor that provides real-time feedback to improve the reliability of wellhead equipment installation. The core technology is a set of ultrasonic transducers working in pulse-echo mode that is mechanically mounted on the wellhead housing exterior. The ultrasonic pulses sent into the housing reflect against the internal components, providing a unique signature of the internal state of the housing using anonintrusive method. The reflected signals are digitally recorded and analyzed using a binary classification network that was trained through machine learning to confirm correct installations.

The technology and algorithm were developed using extensive data collected through full-size prototype laboratory testing. A test fixture simulating a wellhead system was constructed to collect digitalsignatures of various scenarios of hanger landings and packoff settings at carefully controlled offsets from proper installations. The collected signatures were then used to train the binary classification network. The first field trial was performed on a modular compact wellhead system in collaboration with an operator in the Middle East. The digital position sensing solution performed robustly in the field with 93.5% accuracy during the hanger landing operation. The hardware prototype was deployed on two different rigs and successfully detected and confirmed the correct landing of wellhead components during all operations.

The digital position sensing solution provides cost savings to operators by reducing equipment installation time, decreasing unplanned downtime, and reducing the potential for human error. It also provides operators and field service teams with greater confidence that the wellhead equipment has been properly installed.
An Efficient Deep Learning-Based Workflow for CO2 Plume Imaging Using Distributed Pressure and Temperature Measurements
Authors: Nagao Masahiro , Yao Changqing , Onishi Tsubasa , Chen Hongquan , Datta-Gupta Akhil
Published: September 2022

Geologic carbon dioxide (CO2) sequestration has received significant attention from the scientific community as a response to global warming due to greenhouse gas emission. Effective monitoring of CO2 plume is critical to CO2 storage safety throughout the life-cycle of a geologic CO2 sequestration project. Although simulation-based techniques such as history matching can be used for predicting the evolution of underground CO2 saturation, the computational cost of the high-fidelity simulations can be prohibitive. Recent development in data-driven models can provide a viable alternative for rapid CO2 plume imaging. Here, we present a novel deep learning-based workflow that can efficiently visualize CO2 plume in near real-time.

Our deep learning framework utilizes field measurements, such as downhole pressure, distributed pressure and temperature as input to visualize the subsurface CO2 plume images. However, the high output dimension of CO2 plume images makes the training inefficient. We address this challenge in two ways: first, we output a single CO2 onset time map rather than multiple saturation maps at different times; second, we apply an autoencoder-decoder network to identify lower dimensional latent variables that compress high dimensional output images. The ‘onset time’ is the calendar time when the CO2 saturation at a given location exceeds a specified threshold value. In our approach, a deep learning-based regression model is trained to predict latent variables of the autoencoder-decoder network. Subsequently the latent variables are used as inputs of the trained decoder network to generate the 3D onset time image, visualizing the evolving CO2 plume in near real-time.

The power and efficacy of our approach are demonstrated using both synthetic and field-scale applications. We first validate the deep learning-based CO2 plume imaging workflow using a 2D synthetic example. Next, the visualization workflow is applied to a 3D field-scale reservoir to demonstrate the robustness and efficiency of the workflow. The monitoring data set consists of distributed temperature sensing (DTS) data acquired at a monitoring well, flowing bottom-hole pressure data at the injection well, and time-lapse pressure measurements at several locations along the monitoring well. Our approach is also extended to efficiently evaluate the uncertainty of predicted CO2 plume images. Additionally, an efficient workflow for optimizing data acquisition and measurement type is demonstrated using our deep learning-based framework.

The novelty of this work is the development and applications of a unique and efficient deep learning-based subsurface visualization workflow for the spatial and temporal migration of the CO2 plume. The efficiency and flexibility of the data-driven workflow make our approach suitable for field-scale applications.
Buoyant Flow of H2 Versus CO2 in Storage Aquifers
Authors: Ren Bo , Jensen Jerry , Duncan Ian , Lake Larry
Published: September 2022

Hydrogen will play an important role in the quest to decarbonize the world’s economy by substituting fossil fuels. In addition to the development of hydrogen generation technologies, the energy industry will need to increase hydrogen storage capacity to facilitate the development of a robust hydrogen economy. The required hydrogen storage capacity will be much larger than current hydrogen and natural gas storage capacities. There are a several geological storage options for hydrogen that include depleted hydrocarbon fields and aquifers, where more research is needed until the feasibility to store hydrogen at scale is proven. Here, we investigate the buoyant flow of H2 (as a working gas) versus CO2 (as a cushion gas) separately in a representative storage aquifer. Buoyant flow can affect the maximum storage, capillary trapping, likelihood of leakage, and deliverability of aquifer-stored hydrogen.

After building a two-dimensional geological reservoir model initially filled with saline water, we ran numerical simulations to determine how hydrogen placed at the bottom of an aquifer might rise through the water column. The Leverett j-function is used to generate heterogeneous capillary entry pressure fields that correlate with porosity and permeability fields. Hydrogen viscosities were based on the Jossi et al. correlation, and the density was modeled using the Peng-Robinson equation of state. We then simulated several scenarios to assess flow during short- (annually) and long- (several years) term storage. For comparison purposes, we also ran CO2 storage simulations using the same geological model but with CO2-brine-rock properties collected from the literature.

For a representative storage aquifer (323 K, 15.7 MPa, and mean permeability of 200 mD), significant fingering occurred as the hydrogen rose through the saline water column. The hydrogen experienced more buoyant flow and created flow paths with increased fingering when compared with CO2. Individual hydrogen fingers are thinner than the CO2 fingers in the simulations and the tip of hydrogen finger fronts propagated upward roughly twice as fast as the CO2 front for a typical set of heterogeneity indicators (Dykstra-Parson’s coefficient Vdp = 0.80, and dimensionless autocorrelation length λdx = 2).

The implications of buoyant flow for hydrogen in saline aquifers include an increased threat of leakage, more residual trapping of hydrogen, and, therefore, the need to focus more on the heterogeneity and lateral correlation behavior of the repository. If hydrogen penetrates the caprock of an aquifer, it will leak faster than CO2 and generate more vertical flow pathways. We identify possible depositional environments for clastic aquifers that would offer suitable characteristics for storage.
A Transmitter-Less Inspection Tool for Pipe Defect Detection and Characterization
Authors: Mostafa Tarek M. , Khater Moutazbellah , Ozakin Mehmet , Ooi Guang , Bagci Hakan , Ahmed Shehab
Published: September 2022

Pipe strings are commonly employed in the oil and gas sector, where they are subjected to immense strains and highly corrosive fluids. Electromagnetic (EM) based inspection tools are widely used and typically require one or more excitation sources (i.e., transmitter coil(s)), as well as sensing devices, which adds complexity and expense. By utilizing the inductive sensing principle, this work introduces a novel inspection method with no transmitter coil(s) capable of characterizing inner and full metal loss on the pipe's body. The proposed technique has been modeled and simulated using the commercial EM solver ANSYS Maxwell, as well as a proof of concept prototype, has been built. The results reveal that the tool could detect full and partial metal loss and fully characterize the defect's size, location, and depth.
Surfactant Blends for Steam Foam Applications up to 570°F (~300°C)
Authors: Wilson Daniel , Landry Thu , Morgan Carla , Stanciu Cornell , Nguyen Nhut , Nguyen Quoc
Published: September 2022

Steam injection with foam presence (steam foam) was successfully implemented in the 1970's and 1980's. The purpose of having steam foam as a mobility control agent was to improve sweep efficiency by minimizing detrimental effects associated with steam injection processes such as viscous fingering, gravity override, loss to thief zones, etc. Previous work, published in SPE-190473-MS and SPE-193634-MS, discussed results on thermal stability and foamability of Alkyl Ether Carboxylate Acid (ECA) at temperatures up to 200°C-250°C in the presence/absence of bitumen. This paper, as a continuation of the work mentioned above, presents the blending of ECA with surfactant A (a chemically different surfactant) at 50/50 ratio and different injection foam qualities (30% to 90%) for further improvement of steam foam performance at 300°C without bitumen.

For safety reasons, thermal stability test at 300°C using Parr reactors was not conducted because of identical rated temperature on the instrument. Surfactant foamability was evaluated through bulk foam test in a high temperature high pressure (HTHP) visual cell based on the recorded life-time of foam column. Two Internal Olefin Sulfonates (IOS) from Shell were also tested and used as benchmark for comparison with ECA itself and the blend at 250°C and 300°C. Through sand-pack tests conducted at 300°C, foamability in porous media of ECA – surfactant A blend at different injection foam qualities was compared against ECA itself for observation of improvement with regards to increasing steam apparent viscosity in the absence of bitumen.

Results showed that the presence of surfactant A improved foamability by 50% at 50/50 blend in bulk foam test. Sand-pack test results confirmed significant increase of steam appearance viscosity with the addition of surfactant A. Varying injection foam qualities resulted in 30% and 50% being the best foam qualities in terms of increasing steam apparent viscosity as compared to 70% and 90% foam qualities.

The findings of this study once again confirm the effectiveness of steam foam as a mobility control agent for steam injection processes. The addition of surfactant A to ECA improves foamability at 300°C which broadens the application of steam foam to reservoirs with similar operating temperature. Sensitivity study on injection foam qualities provides insights on process design with respect to desired foam strength and gas availability.
Application of Machine Learning for Mineralogy Prediction from Well Logs in the Bakken Petroleum System
Authors: Laalam Aimen , Boualam Aldjia , Ouadi Habib , Djezzar Sofiane , Tomomewo Olusegun , Mellal Ilyas , Bakelli Omar , Merzoug Ahmed , Chemmakh Abderraouf , Latreche Abdeljallil , Berrehal Badr Eddine
Published: September 2022

One of the significant unconventional oil reserves in the USA is the Bakken Petroleum System located in the Williston Basin. It is known for its complex lithology, composed of three prominent members, Upper and Lower Bakken, with similar properties of organic-rich shale relatively uniform compared to the middle member with five distinct lithofacies, formed mainly from calcite, dolomite, or silica. The higher properties variability makes the reservoir characterization more challenging with low permeability and porosity. Understanding lithology by quantifying mineralogy is crucial for accurate geological modeling and reservoir simulation. Besides that, the reservoir's capacity and the oil production are affected by the type and the mineral volume fractions, which impact the reservoir properties. Conventionally, to identify the mineralogy of the reservoir, the laboratory analysis (X-Ray Diffraction, XRD) using core samples combined with the well logs interpretation is widely used. The unavailability of the core data due to the high cost, as well as the discontinuities of the core section of the reservoir due to the coring failures and the destructive operations, are one of the challenges for an accurate mineralogy quantification. The XRD cores analysis is usually used to calibrate the petrophysical evaluation using well logs data because they are economically efficient. To remedy to these limitations, artificial intelligence and data-driven based models have been widely deployed in the oil and gas industry, particularly for petrophysical evaluation. This study aims to develop machine learning models to identify mineralogy by applying six different machine learning methods and using real field data from the upper, middle, and lower members of the Bakken Formation. Efficient pre-processing tools are applied before training the models to eliminate the XRD data outliers due to the formation complexity. The algorithms are based on well logs as inputs such as Gamma Ray, bulk density, neutron porosity, resistivity, and photoelectric factor for seven (07) wells. XRD mineral components for 117 samples are considered outputs (Clays, Dolomite, Calcite, Quartz, and other minerals). The results' validation is based on comparing the XRD Data prediction from the developed models and the petrophysical interpretation. The applied approach and the developed models have proved their effectiveness in predicting the XRD from the Bakken Petroleum system. The Random Forest Regressor delivered the best performance with a correlation coefficient of 78 percent. The rest of the algorithms had R-scores between 36 and 72 percent, with the linear regression having the lowest coefficient. The reason is the non-linearity between the inputs and outputs.
Challenging Standard Practices: How a Review of Standard Practices Resulted in an Improvement in BHA Reliability
Authors: Marland Christopher , Gonzalez Duane , Koy James
Published: September 2022

Bottom Hole Assembly (BHA) reliability is critical to deliver wells on-time and within budget. Improving reliability is a combined effort between operators and service providers. In the D.J. Basin, well drilling times are between 48-60hours. A 10-hour trip for failure can account for over 20% of well time. Onshore operations have benefited from focusing on performance metrics. To achieve some metrics, drilling procedures have been implemented that may have had unintended consequences. It will be shown how a review and change to standard drilling practices helped improve BHA reliability

BHA failures occurred on 35% of wells in the operating area of this project. Although steps were taken, such as third-party inspections of tool builds, trialing various BHA components, and adjusting drilling parameters, failure still occurred. Failures were split between motors, measurement while drilling (MWD) and rotary steerable system (RSS) tools. Motor chunking was present on most BHAs, regardless of vendor. Chunking either caused motor failure or blocking of MWD or RSS components despite filters downstream of the motor. A review of operating practices with the service provider concluded that modifications could reduce on-bottom and off-bottom BHA loads and improve reliability. A series of procedural changes were made to connection practices, back-to-bottom procedures and downlink practices and the results tracked.

Increased motor reliability was the main goal and would be determined by post-run observations of chunking evidence. A secondary aim was to reduce other failures that may be caused by mechanical overload. After implementing the procedural changes, the first 11 wells were completed in a single run, with no non-productive time (NPT) for BHA failures and no motor rubber observed in filter subs. Several wells were also able to re-run the RSS resulting in an invoice credit and further cost savings. Although the changes have resulted in a small increase in connection time per well, the pad level time savings from improved BHA reliability offsets that cost. There is also greater confidence that the applied drilling parameters start from a zero-load point. This allows the operator and service company to have more confidence that downhole tools are not being overloaded and gives more opportunity to optimize drilling parameters for performance.

This paper will challenge standard practices that target incremental performance gains but may result in seemingly unrelated BHA reliability problems. Modeling drillstring stretch and understanding BHA load conditions has resulted in reliability improvements for the basin that can be applied to similar applications for the operator and the industry.
Coupled Enhanced Natural Gas Recovery and Blue Hydrogen (EGRBH) Generation
Authors: Hatzignatiou Dimitrios Georgios , Ehlig-Economides Christine
Published: September 2022

Natural gas can be used to generate either blue or grey hydrogen depending on whether or not the carbon dioxide byproduct is captured and stored. When captured, the carbon dioxide (CO2) produced from a steam methane reforming (SMR) or partial oxidation (POX) process can be injected into the same natural gas reservoir for enhanced gas recovery (EGR) while simultaneously storing CO2. The objective of this work is the effective integration of these three major processes – blue hydrogen generation, carbon dioxide capture and storage, and enhanced natural gas production.

Surface processes include separation of methane from CO2 and other inorganic and organic components in the produced natural gas. Produced CO2 will be injected back into the reservoir, and other components would be managed in ways standard to produced natural gas processing. An SMR or POX process followed by a shift reaction one will generate hydrogen and CO2 followed by separation of the hydrogen and CO2. To avoid a need for post combustion capture, continuous operation can use produced hydrogen to energize the SMR process. Integration of natural gas reservoir production, blue hydrogen generation, and CO2 injection back into the same reservoir leads to a process termed enhanced gas recovery and blue hydrogen (EGRBH). To optimize the reservoir management, analytical and numerical simulation models that address physical mechanisms such as CO2 diffusion, advection, and CO2 solubility in connate water provide guidelines on placement of injection and production wells, on their geometry (vertical or horizontal) and completion interval locations, and on well operating conditions.

Displacing methane with CO2 is a miscible process with favorable mobility ratio, and simulations show that the methane recovery factor at CO2 breakthrough depends on both molecular diffusion and dispersivity related to reservoir heterogeneity. Continued production at constant methane rate enables additional blue hydrogen generation while increasing CO2 flow through the reservoir under declining average reservoir pressure. Injection of additional CO2 captured from other stationary point sources can achieve enhanced CO2 storage (ECS) up to a limit pressure less than the original reservoir pressure.

The EGRBH process produces blue hydrogen at a price competitive with gasoline or diesel for transportation applications. When used for power generation, blue hydrogen decarbonizes natural gas fired generation at lower cost than can be achieved with post combustion capture from standard natural gas power plants. Blue hydrogen is also less than half the cost of so-called green hydrogen produced via electrolysis using electricity generated with renewable energy. This appears to be an ideal approach for developing and producing new natural gas discoveries.
Fit-For-Purpose Fracturing Technique Enables Breakthrough in Marginal Gas Field Development of Ordos Basin, China
Authors: Ma Zhanguo , Bi Man , Chen Junjie , Shi Mingxing , Li Haoyan , Fu Yunlong , Zhang Jie , Luo Yin , Liu Yuan
Published: September 2022

Some areas in Ordos basin, such as Sudong block, suffer from poor economic returns caused by low production. The development of this reservoir has multiple geologic and engineering restrictions. In addition to the complex lithology and abundant clay content that reduce formation effective gas porosity and permeability, the low net-to-gross (NTG) ratio requires a larger quantity of proppant to adequately support a fracture that covers the entire thickness of the sand interval.

Because of these issues, the reservoir potential is not capable of supporting costly conventional fracturing techniques. Finding a fit-for-purpose stimulation solution that balances the cost effectiveness and production enhancement has been a challenge for years.

Channel fracturing has been introduced to achieve better fracture performance with less cost. A pilot project of one deviated well and one horizontal well was done in 2019. The goal of this step was to verify the subsurface suitability and engineering feasibility.

Despite the smooth operation and record-breaking post-fracturing test results, multifaceted study continued. The laboratory study of proppant and formation rock established a solid foundation for fluid formulation and proppant concentration design. The design optimization with a multiphysics simulator minimized the fluid volume while ensuring conductivity and lateral coverage. Finally, the equipment layout and rate distribution among pumps was planned so that the slurry pulses formed at the blender would be delivered to downhole with integrity.

These success of these efforts is proven by the outstanding post-fracturing results of two vertical wells and one horizontal well in 2021. Despite the discrepancy in reservoir quality, all the wells had faster cleanup period, less gas kickoff, and 80% increase in horizontal well absolute open flow (AOF) compared with 2019.

As is demonstrated by field observation and production results, channel fracturing creates highly conductive channels in the fracture with less material consumption and less cost, sustainably. Compared to the conventional fracturing solution, channel fracturing technology enables balancing of budget saving and production increase. The success of implementation has led the way to a more economic cost model to develop the marginal fields in Ordos basin.
Petroleum Engineers Need a Strong Professional Society
Authors: Michael Andreas
Published: September 2022

The thrust of this paper is to objectively challenge the recently-emergent talking point for a "Society of Professionals in Energy," which manifests a mentality which heralds trouble for the future of the petroleum engineering (PE) discipline and profession. Such approach dilutes any domain expertise and competitive advantage that PE graduates should have over non-PE graduates, with the next step inadvertently being the gradual phasing of PE into something along the lines of "energy engineering," all this while oil and gas (O&G) production keeps growing year-after-year.

Petroleum reservoirs are the result of subsurface processes that took place through an extensive geological history. Conceptualizing how petroleum reservoirs are configured underground, at great depths and sometimes also below thousands-of-feet of water, is an extremely challenging task. This unique-to-PE visional barrier is an inherent challenge to every subsurface O&G project, making technical expertise (not essentially experience) invaluable, as it requires more than basic critical thinking to understand what goes on in the opaque underground.

One may disregard the 2021-22 merger fiasco between SPE and the American Association of Petroleum Geologists (AAPG) as an aberration. It certainly can serve as a teaching moment for its architects. There are many within and outside PE who would question even the need for the existence of PE academic programs. The reason students enroll in PE programs is supposed to be for developing expertise in solving upstream O&G problems. Rebranding or generalizing to "energy engineering" will make more harm than good, diluting any competitive advantage for PE graduates within what should be their domain of expertise.