bluuebunny/crossref_metadata_2025 huggingface dataset:
A 3D Acid Transport Model for Acid Fracturing Treatments With Viscous Fingering
Authors: Dong Rencheng , Wheeler Mary F. , Ma Kang , Su Hang
Published: October 2020

In acid fracturing treatments, the goal is to create enough fracture roughness through differential acid etching on fracture walls such that the acid fracture can keep open and sustain a high enough acid fracture conductivity under the closure stress. The viscous fingering phenomenon has been utilized in acid fracturing treatments to enhance the differential acid etching. For relatively homogeneous carbonate reservoirs, by injecting a low-viscosity acid into a high-viscosity pad fluid during acid fracturing, the acid tends to form viscous fingers and etch fracture surfaces non-uniformly. In order to accurately predict the acid- fracture conductivity, a detailed description of the rough acid-fracture surfaces is required. In this paper, we developed a 3D acid transport model to compute the geometry of acid fracture for acid fracturing treatments with viscous fingering. The developed model couples the acid fluid flow, reactive transport and rock dissolution in the fracture. Our simulation results reproduced the acid viscous fingering phenomenon ob-served from experiments in the literature. During the process of acid viscous fingering, high-conductivity channels developed in the fingering regions. We performed parametric studies to investigate the effects of pad fluid viscosities and acid injection rates on acid fracture conductivity. We found that a higher viscosity pad fluid and a higher acid injection rate help acid to penetrate deeper in the fracture and result in a longer etched channel.
A Shattered Visage and Choke Point Dilemma for Petroleum Engineers
Authors: Samuel Robello
Published: October 2020

The 1980s oil industry crash, which was caused by an increase in production and a slowdown of the world economy, resulted in a huge surplus of crude oil. Improved horizontal drilling, completion technologies and the underpinning of engineering advancements were major contributing factors. The crude oil price has continued to fall since mid-2014, and has dropped from $106 per barrel. This paper examines the supply and demand of the future workforce and the warning signs that were ignored before the crash.

The framework of questions to be addressed includes the following: "What is the fundamental problem in the industry and petroleum universities?", "Is it throttling the advancement of the petroleum industry?", and "What are the changes needed to meet the shortage of future engineers?" Although several challenges are inherently present, the article will particularly ponder the following primary challenges: talent pipeline and shortage, educational curriculum drought, petroleum education intake reform, academia-industry tighter participation, knowledge base erosion, and technical talent flight.

A surge in university enrollment has tilted the balance of the student and aging faculty ratio. The key takeaways from this paper include the challenge areas in education and how the industry is responding to its needs, outlining the emerging future direction to meet the challenges of the cyclical industry, as well as climate change pressures. This paper presents the future state of the petroleum program, which will be in a state of stunned growth similar to other industries, like mining and nuclear energy. It also shows a link to environmental pressures.
Quantification and Incorporation of Geomechanical Risks in Optimization of Geologic CO2 Storage Using Coupled-Physics Models
Authors: Zheng Fangning , Jahandideh Atefeh , Jha Birendra , Jafarpour Behnam
Published: October 2020

Numerical flow simulation models for CO2 injection, transport and trapping mechanisms have been used to optimize geologic CO2 storage (GCS) by improving trapping efficiency and injection strategies. Injection of CO2 into geologic formations can cause geomechanical changes and lead to reservoir expansion, ground surface uplift, and induced seismicity. Such deformations create geomechanical risks associated with GCS, which can compromise the safety and storage capacity of CO2. The geomechanical risks of CO2 sequestration have drawn significant attention in recent years due to considerable ground uplifting and induced microseismic activities that have been reported in several field cases. However, studies in this area have not considered the effect of geomechanical risks in optimizing the storage performance. We present an optimization framework to strategically place CO2 injection wells to maximize the storage capacity and minimize the associated geomechanical risks. To this end, we perform the optimization using three-dimensional coupled flow and geomechanical models, by applying the Mohr-Coulomb plastic failure criterion to model mechanical rock failure risk. Additionally, the geomechanical simulation results are used to quantify the risk associated with ground surface displacement and plastic strain, which are extracted from the simulation outputs. A multi-objective optimization problem is formulated to maximize CO2 storage while minimizing the two forms of geomechanical risks. The injection well locations are defined as decision variables and Genetic Algorithm is implemented to solve the multi-objective optimization problem. The solution of the proposed framework leads to nontrivial optimal decisions, which are different from the case where geomechanical risks associated with CO2 injection are ignored. We find that the wells may not necessarily be concentrated in areas with the highest storage capacity because that may lead to rock failure and unacceptable levels of ground surface uplift. Instead, the maximum storage is limited to keep the reservoir in the elastic state based on the specified reservoir geomechanical and flow properties. We also observe that well interactions during CO2 injection can cause shear failure of the formation between the wells. These observations suggest that accounting for geomechanical risks associated with CO2 injection is necessary to design a sustainable plan for CO2 injection and storage. The paper ends with a discussion about the importance of accounting for the uncertainty in rock properties and the resulting model predictions in optimizing the well locations.
Production Operations Efficiency Gains Enablers: Machine Learning or Physics Based Models?
Authors: Joseph Ayoub , Michael Thambynayagm , Jose Jimenez
Published: October 2020

Industry reports confirm that while the unconventional wells drilling and completion operations have achieved significant efficiency gains, which translated into steep cost reductions, the production operations costs remained largely flat. The authors provide a quick review of the above and discuss technologies aimed at addressing this situation including machine learning, AI and physics-based modeling. The latter has been the cornerstone for production optimization since the early days of oil and gas exploitation, however, it has been uneconomical for systematic use in unconventional wells and is applied to only a small fraction of the large number of active wells. This is mainly due to their complex completions, which makes modeling a tedious and resource intensive task. Data science promises faster and nimbler solutions, however, while advanced techniques such as deep learning have achieved impressive advances in many areas like face and speech recognition, they remain mostly rooted in pattern recognition, with no grasp of cause and effect, which limits the type of problems they can successfully resolve. This paper will discuss the above solutions and limitations and presents a novel physics-based approach that would be economical for widespread deployment.
Role of Intermolecular Forces on Surfactant-Steam Performance Into Heavy Oil Reservoirs
Authors: Seng Lee Yeh , Hascakir Berna
Published: October 2020

This study investigates the role of heavy oil polar fractions in surfactant-steam flooding performance. Performance analyses were done by examination of the dipole-dipole and ion-ion interactions between polar head group of surfactants and charged polar fraction of crude oil, asphaltenes.

Surfactants are designed to reduce the interfacial tension between two immiscible fluids (such as oil and water) and effectively used for oil recovery. They reduce the interfacial tension by aligning themselves at the interface of these two immiscible fluids, this way, their polar head group can stay in water and non-polar tail can stay in oil phase. However, in heavy oil, the crude oil itself has high amount of polar components (mainly asphaltenes). Moreover, polar head group in surfactants is charged and the asphaltene fraction of crude oils carry reservoir rock components with charges. The impact of these intermolecular forces on surfactant-steam process performance was investigated with 10 coreflood experiments on an extra-heavy crude oil. 9 surfactants (3 anionic, 3 cationic and 3 nonionic surfactants) were tested. Results of each coreflood test were analyzed through cumulative oil recovery and residual oil content. The performance differences were evaluated by polarity determination through dielectric constant measurements and by ionic charges through zeta potential measurements on asphaltenes fraction of produced oil and residual oil samples.

The differences in each group of surfactant tested in this study are the tail length. Results indicate that longer hydrocarbon tail yielded higher cumulative oil recovery. Based on the charge groups present in the polar head of surfactants anionic surfactants resulted in higher oil recovery. The further examinations on asphaltenes from produced and residual oils show that the dielectric constants of asphaltenes originated from the produced oil gives higher polarity for surfactant-steam experiments conducted with longer tail length, which provide information on polarity of asphaltenes. The ion-ion interaction between produced oil asphaltenes and surfactant head groups were determined through zeta potential measurements. For the most successful surfactant-steam processes, these results showed that the changes on asphaltenes surface charges getting lower with the increase in oil recovery, which indicates that once asphaltenes are interacting more with polar head of surfactants, then, the recovery rate increases.

Our study shows that surfactant-steam flooding performance in heavy oil reservoirs controlled by the interaction between asphaltenes and polar head group of surfactants. Accordingly, main mechanism which controls the effectiveness of process is the ion-ion interaction between the charges in asphaltene surfaces and polar head group of crude oils. Since crude oils carry mostly negatively charged reservoir rock particles, our study suggests the use of anionic surfactants for the extraction of heavy oils.
Physics-Driven Machine Learning-Based Borehole Sonic Interpretation in the Presence of Casing and Drill Pipe
Authors: Liang Lin , Lei Ting , Donald Adam , Blyth Matthew
Published: October 2020

Interpretation of sonic data acquired by logging-while-drilling tool or wireline tool in cased holes is complicated by the presence of drill pipe or casing because those steel pipes can act as a strong waveguide. Traditional solutions, which rely on using frequency bandpass filter or waveform arrival-time separation to filter out the unwanted pipe mode, often fail when formation and pipe signals co-exist in the same frequency band or arrival-time range. We hence develop a physics-driven machine learning-based method to overcome the challenge. In this method, two synthetic databases are generated from a general root-finding mode-search routine based on two assumed models, one is defined as a cemented cased hole for wireline scenario, another with a steel pipe immersed in a fluid-filled borehole for the logging-while-drilling scenario. The synthetic databases are used to train neural network models, which are first used to perform global sensitivity analysis on all relevant model parameters so that the influence of each parameter on the dipole dispersion data can be well understood. A least-squares inversion scheme utilizing the trained model was developed and tested on synthetic cases. The scheme showed good results and a reasonable uncertainty estimate was made for each parameter. We then extend the application of the trained model to develop a method for automated labeling and extraction of the dipole flexural dispersion mode from other disturbances. The method combines the clustering technique with the neural network model-based inversion and an adaptive filter. Testing on field data demonstrates that the new method is superior to traditional methods because it introduces a mechanism from which unwanted pipe mode can be physically filtered out.

This novel physics-driven machine learning-based method improved the interpretation of sonic dipole dispersion data to cope with the challenge brought by the existence of steel pipes. Unlike data-driven machine learning methods, it can provide global service with just one-time offline training. Compared with traditional methods, the new method is more accurate and reliable because the processing is confined by physical laws. This method is less dependent on input parameters; hence a fully automated solution could be achieved.
Appropriately Characterizing Uncertainty in Estimated Ultimate Recovery for Unconventional Type Wells
Authors: Miller Patrick , Dauncey Keane , Gouveia James
Published: October 2020

Building type wells is arguably the most important exercise in decision making for unconventional resource plays. The type well and its associated uncertainty are often the largest drivers behind whether a project will be economic, or not. However, appropriately characterizing type well uncertainty is not trivial, and is often overlooked.

Recently, new methods have been developed to help estimate type well uncertainty; these methods include statistical aggregation, which reflects the idea that if more information is available, the type well uncertainty band should be narrower. Unfortunately, aggregation is often misapplied to Estimated Ultimate Recovery (EUR) estimates, ignoring the inherent uncertainty and bias in those estimates, which results in a type well uncertainty band that is too narrow. This paper demonstrates how to account for uncertainty and bias in EUR forecasts with a simple, practical Monte Carlo model.

To develop proper type wells, it is critical to distinguish between measured data and estimated data. The type well should have a narrower band of uncertainty where information is measured and tangible (initial production rates) compared to where it is estimated and intangible (EUR).This paper presents a workflow to easily capture this dynamic between initial production rates and EUR in the context of type wells. The concepts of the workflow are first illustrated with a simple analogy of estimating the mass of a bag of marbles; next, the concepts are applied to build example type wells for a real unconventional play.

A key implication of this work is that collecting new information (i.e. new well production data) does not always narrow the uncertainty band for type well EUR. The EUR uncertainty band depends not only on the number of wells with production data, but also on the P90-P10 ranges of individual well forecasts, bias of the evaluator,amount of production data, and consistency in well characteristics. Rules of thumb are developed to help integrate these factors into the final type well workflow and uncertainty assessment.
Developing Professionals Skills Through an Innovative Methodology of Transfer Knowledge
Authors: Velasquez Sergio , Ardila David , Pastor Chacon Paola Andrea , Galvis William Genghini , Ramirez Leyla , Tarazona Fabio
Published: October 2020

Oil price downturn has directly affected employability in our industry at a global scale since 2014, dropping the workforce to significantly low levels. In Colombia, many young professionals finished the undergrad with the intention of building a competitive industry and leverage the national economy through their knowledge; however, most of them have not even had the chance to get a first job as they are in a market that values the experience they do not have. Having said this, it makes evident the need of differentiation from candidates in selection processes and considering other alternatives for their life projects.

As a social responsibility act, the SPE Colombian Section – in conjunction with volunteers working on technical and human resources areas - created a solid strategy based on real needs concluded from data collected at SPE Colombian Section events to boost up young professionals development path and provide guidance for decision making on their careers. "ENJOG" Encuentro de Jovenes de la Industria de Oil and Gas proved that to join efforts is the best way to break barriers and to solve problems.

The results have shown a significant impact on those involved in the program created and the knowledge worth reproducing is documented in this paper. More than 500 young professionals have been participating in the strategy.
Semi-Analytical Modeling of Multi-Fractured Horizontal Gas Wells with Variable Production Constraints and Fracture Interference
Authors: Garcez Jonathan , Zhang Miao , Ayala Luis F.
Published: October 2020

This paper presents a semi-analytical method based on an integral formulation derived through Green’s Function Method to model multi-fractured horizontal gas well (MFHWs) production performance experiencing fracture interference. The nonlinear effect of retaining pressure-dependent gas properties, namely viscosity-compressibility product, in the pseudopressure-based gas diffusivity equation is rigorously captured in the proposed method, removing previous approximations used in existing conventional production data analysis methods. The proposed method is validated against finely gridded numerical simulations models to demonstrate the capabilities of the proposed approach to forecast multi-fracture horizontal gas well performance - including early and late time periods. Fracture spacing sensivity analysis is performed to showcase the importance of a proper hydraulic fracking design to improve the well productivity.
Feasibility of Combining Gas-Assisted Gravity Drainage GAGD with Water Injection in a Thick Heterogeneous Carbonate Reservoir Using 3-D Experimental Physical Model and Simulation
Authors: Peng Yingfeng , Li Yiqiang , Sarma Hemanta K. , Gao Shenen , Kong Debin
Published: October 2020

Enhancing oil recovery from thick heterogeneous carbonate reservoirs poses great challenges, be it through waterflooding or gasflooding. In this study, a three-layer 3D physical model was established based on artificial core technology and scaling criteria, taking into account the mineral composition, petrophysical properties, pore structure, wettability, heterogeneity, dynamic, bottom aquifer, interlayers, and well pattern. Experiments were carried out under circumstance of high temperature and high pressure. A numerical simulation model incorporated with local geological characteristics was built for subject well-area unit. The development process and ultimate oil recovery of conventional water injection, gas-assisted gravity drainage (GAGD), edge-bottom water injection (EBWI), and a method of combination of GAGD and EBWI proposed in this paper, named CGE were studied. For this kind of reservoirs, the experiments showed that, oil recovery of GAGD and EBWI were 40.01% and 37.11%, respectively, higher than conventional waterflooding process, while CGE had the most potential with oil recovery 43.85%. The numerical simulation showed that, oil recovery of CGE was 49.87% and the water cut was extremely low in the first 11 years. GAGD significantly increased Bond Number and had strong water control ability, but it relied on the pressure accumulation, thus there was a non-effective period. EBWI had no obvious non-effective periods, and thus enhancing oil recovery in the early stage through forced gravity displacement. CGE is a feasible and efficient combination development method, although there is still a problem of water control in the later stage. In addition to the research of EOR methods, this paper also helps broaden the means of researching carbonate reservoirs and design more schemes, based on the successful implement of the experiments.
Institutional Cooperation for Capacity Building of a Petroleum Engineering Department: A Case Study
Authors: Khan Abid , Tjåland Egil , Kleppe Jon , Lodi Sarosh
Published: October 2020

Pakistan requires intensive exploration activities and rapid development of its indigenous oil and gas resources. A well trained professional human resource, equipped with modern tools and skills, is essentially required. To achieve this, the Norwegian Centre of Excellence for Petroleum Studies (NCEPS) at NED University was established through collaborative efforts of NED University of Engineering & Technology (NEDUET) Pakistan and Norwegian University of Science & Technology (NTNU) Norway, in close cooperation with Petroleum Industry, under the umbrella of Pak-Norway, Institutional Cooperation Program.

The establishment of NCEPS included a six-pronged approach for capacity building of Petroleum Engineering Department at NEDUET. These included: i) post graduate studies and training programs for faculty members and laboratory staff, ii) strengthening of laboratory and office resources, iii) development of Master program, iv) transfer of technology, v) initiation of collaborative research, and vi) development of linkages between the two universities and the petroleum industry.

The main objective was achieved through capacity building of academic staff and strengthening of laboratory facilities at NED Universities. Among faculty members, four received master's degree, three were trained on latest teaching techniques, two received capacity building in research and five laboratory engineers were trained on laboratory equipment handling and operation. It also included a special training on drilling simulator at Abu Dhabi. Strengthening of laboratory resources have been undertaken through procurement of state-of-the-art research equipment. Master's program was also developed in collaboration with NTNU and industry. Transfer of latest teaching techniques has been acquired. A video conferencing facility was also developed to provide effective communication and learning opportunities. Sustainable linkages between academia and industry were enhanced.

The petroleum engineering department shows significant improvement in providing quality education, professional training and industry-oriented research. The experience was shared with other institutions in the country. Sustainable linkages have been developed between the two universities and the industry. This paper provides details of these tri-partite collaborative efforts.
Cellulose Nanocrystal Switchable Gel for Improving CO2 Sweep Efficiency in Enhanced Oil Recovery and Gas Storage
Authors: Telmadarreie Ali , Johnsen Christopher , Bryant Steven
Published: October 2020

CO2 injection is regarded as an important method for enhanced oil recovery (EOR) and greenhouse gas control by storing CO2 underground. However, the reservoir heterogeneity and low viscosity of CO2 will result in poor sweep and therefore inadequate oil recovery and inefficient gas storage. The entanglement of biopolymers is a well-known phenomenon that, when controlled, can result in a smart fluid with strong gelation properties. We have shown that when a suitable salt is incorporated into the cellulose nanocrystal (CNC), the fluids undergo gelation upon contact with bulk phase CO2 but remain a flowing liquid otherwise. In this study, we applied this composition-selective trigger to improve the sweep efficiency in CO2 EOR and sequestration.

Benchtop tests were performed to observe the gelation time and strength of gel to optimize the chemical concentrations accordingly. Parameters such as CNC and salt concentrations were optimized to tune the gelation time and gel strength. The optimized CNC fluid was tested for its ability to turn to gel within the porous medium as CO2 encounters the fluid. Flow tests were performed in a representative model porous media to analyze the in-situ gelation inferred from pressure profile and fluid production. CO2 and N2 gas were used as the gas phases. A heterogeneous dual-sandpack was used to demonstrate sweep efficiency improvement during CO2 injection.

Tuning the chemical concentration enabled us to optimize the gel strength and more importantly gelation time across a wide range, from 5 minutes to more than 48 hours. The gel can be easily broken in contact with nitrogen gas. After CNC+salt fluid was placed in porous media initially containing water and CO2, subsequent injection of CO2 required a very large pressure gradient to initiate flow demonstrating the in-situ generations of gel. Once the flow was initiated, subsequent sequential injections of CO2 and N2 exhibited smaller resistance to N2 than to CO2, consistent with the reversible gel/solution transition in the presence/absence of CO2 observed in batch experiments. Flow tests in heterogeneous dual-sandpack (with permeability contrast of 5) revealed that in-situ gelation diverts injected CO2 almost entirely to the lower permeability layer, which had been almost completely bypassed during injection prior to the CNC+salt injection.

The composition-specific trigger, the ability to control the fluid's properties, and the renewable source of nanomaterials will open up an enormous opportunity for CO2 injection processes in heterogeneous reservoirs, in challenging locations (i.e. offshore) and in related applications such as CO2 sequestration.
Cost Comparison Between Carbon Neutral Fuel and Alternative Low Carbon Energy Options
Authors: Ehlig-Economides Christine , de Guzman Neil
Published: October 2020

In efforts to reduce carbon dioxide emissions from fossil fuel combustion, public funding for wind and solar alternative energy resources has enabled their evolution toward cost competitiveness with coal and natural gas options for electric power generation. To address combustion emissions from the transportation sector, the European Commission has committed to electrifying transportation, but this solution will not address transportation by air or by sea. Nor does it address continued production of petrochemical products that only require a small fraction of produced hydrocarbons. This study investigates the cost competitiveness of an alternative strategy to market crude oil priced to cover the cost of removing an amount of carbon dioxide equal to that produced through combustion of transportation fuels to be refined from it. This strategy enables continued use of fossil fuel for all transportation modes.

The cost comparison considers life cycle carbon dioxide emissions and does not address other externalities related to materials or batteries employed in renewable energy options. Rather, we report known costs for carbon capture, use, and storage (CCUS) with consideration of both nature and technology based carbon capture with focus mainly on geologic storage and utilization.

Because road and rail transportation can be electrified, of particular interest is the levelized cost comparison between carbon neutral fuel and electrified transportation, the latter including infrastructure implementation costs.

The resulting cost comparison informs investment decisions and justifies marketing fossil fuels on a carbon neutral basis.
Geomechanics of Compartmentalized Reservoirs with Finite Element Analysis: Field Case Study from the Eastern Mediterranean
Authors: Markou Nikolaos , Papanastasiou Panos
Published: October 2020

This paper presents an optimum way to produce down to depletion a compartmentalized reservoir in offshore deep environment by considering geomechanical stress-deformation mechanisms and associated problems. The case study is for a faulted reservoir zone of the Aphrodite field, located in the Eastern Mediterranean. The study is based on finite element modelling using 2D plane strain analysis that incorporates pore pressure and elastoplastic deformation of reservoir and overburden rock formations using the Drucker-Prager plasticity model. The mechanical properties of the reservoir sandstones were derived from calibration of data obtained from triaxial tests and for the overburden shale layers from acoustic velocities and correlation functions. The compartmentalized geometry was constructed based on seismic data and logging data obtained at the exploration and appraisal phases. The estimated insitu stress field was transformed and applied on the boundaries of the model blocky geometry.

Four different initial and equilibrium depletion scenarios were examined and the obtained results in terms of deformation and effective stresses are compared. The first scenario reflects the initial stress state, the next two intermediate scenarios present non-uniform depletion cases for each fault block, and the fourth scenario presents the case of a uniform depletion. It was found that the uniform depletion of the reservoir compartments creates the least stress contrast in the field and consequently, ensures better control of stress-related impacts during the production. The analysis highlights the local regions of a fault blocks system that potentially suffer by high shear strains that can cause fault reactivation or induced fractured zones but the over-all risk remains low. Furthermore, the analysis establishes relationships between the mean effective stress, volumetric strain, and permeability changes in order to predict the regions with improved transmissibility characteristics or the less permeable compacted rock regions of the reservoir. Overall, the analysis can provide an appreciation of the stress/strain-driven characteristics of the reservoir showing the area of rock compaction tendencies of the faulted blocks and the further deformation in depletion conditions. The presented work demonstrates clearly that a properly calibrated reservoir geomechanical model can be used as a screening tool for examining depletion scenarios of compartmentalized reservoirs, highlighting areas of potential problems such as fault activation, wellbore shearing, reservoir compaction, permeability changes and fault sealing.
Data Determine the Optimal Drawdown for Woodford and Mayes in the Anadarko Basin
Authors: Alzahabi Ahmed , Trindade A. Alexandre , Kamel Ahmed , Harouaka Abdallah , Baustian Wade , Campbell Catherine
Published: October 2020

One of the continuing puzzle pieces for all unconventional plays is drawdown (DD) technique for optimal Return on Investment (ROI). A solid approach to determine this valuable piece of information has yet to be found, as many operators are reluctant to reveal the production, pressure, and completion data required. Among multiple parameters, various completion and spacing parameters add to the complexity of the problem. This paper aims to determine which drawdown strategy leads to the highest return in the Anadarko Basin,, specifically evaluating the Woodford and Mayes formation. Several drawdown techniques were used within the Anadarko Basin in conjunction with different completion techniques. Private production and completion data were analyzed and combined with well log analysis in conjunction with data analytics tools. This case study explores a new strategy to drawdown producing wells within the Anadarko basin to achieve ultimate ROI. We perform data analytics utilizing analytics (scatterplot smoothing) to develop a relationship between two dependent variables Estimated Ultimate Recovery (EUR) and Initial Production (IP) for 180 days of Oil vs. drawdown. We present a model that evaluates horizontal well production based on drawdown parameters. Key data were estimated using reservoir and production parameters. The data led to determination of the most optimal drawdown technique for different reservoirs within the Anadarko Basin. This result may help professionals fully understand the Anadarko Basin. By use of these optimal parameters, we hope to completely understand the best way to drawdown wells when they are drilled simultaneously. Our findings and workflow within the Woodford and Mayes formations may be applied to various plays and formations across the unconventional play spectrum. Optimal drawdown techniques in unconventional reservoirs could add billions of dollars in revenue to a company's portfolio and increase rate of return dramatically, as well as offer a new understanding of the reservoirs in which we are dealing with.
Successful Overflushing of Hydraulic Fractures Using Crosslinked Fluids in Conventional Permeability Reservoirs: Theoretical Basis for a Paradigm Shift with Field Results
Authors: Vitthal Sanjay , Chapylgin Dmitry , Liu Xin , Khamadaliev Damir , Fair Phillip
Published: October 2020

During hydraulic fracturing of low to moderate (0.1 – 50 md) permeability reservoirs using crosslinked gel fluids, the final proppant stage displacement is designed to leave some volume of proppant slurry above the perforated interval. This practice of underflushing is based on a paradigm that considers the overdisplacement of proppant past perforations to be a major risk to well productivity. The theory behind this paradigm is investigated and finds that it relies on several physically unrealistic assumptions. Numerical simulations were performed to understand the impact of a fracture overflush on well productivity. A new methodology was developed for overflushing fractures that enables significant cost/time savings without impacting well productivity. A multi-well field trial in a 2-20 md reservoir was conducted andcompared well performance from overflushed crosslinked gel fractures to underflushed fractures. Some of the trial results have been reported by the authors (Chaplygin et. al. (2019)) and are further updated/analyzed in this work. The analysis confirmed that the managed overflush fractures have equivalent performance to underflushed fractures. The analysis also confirmed multiple benefits from the managed overflush wells including reductions in completion costs/time and an improved HSSE risk profile. The results challenge the validity of this decades old paradigm.
An Operator and Rig Contractor Deliver Drilling Process Automation in the Bakken
Authors: Isbell Matthew , Munoz Ernest , Ramseyer Lacey , Farrow Blakley
Published: October 2020

An operator and rig contractor implemented new drilling operation automation (DOA) on two rigs in North Dakota’s Bakken field. A set of DOA projects were selected to promote alignment and deliver valuable tools to improve operational performance based on a collaborative technology agreement to develop innovative DOA process solutions to reduce operational variation. The first sprint of project work focused on delivering a system that automatically carries out recurring drilling activities previously completed manually by a driller interfacing with drilling rig controls.

Collaboration between the operator and rig contractor has been vital in developing technical workflows for automation that deliver value to all stakeholders. The operator and rig contractor developed, field tested, and proved the value of the implemented devices and systems. The project development process is described along with the methods used to overcome the challenges encountered during the first project sprint. Developing and deploying repetitive process automation has enabled greater control and driven operational consistency for repetitive drilling practices. The process will be shared to manage, design, and implement automated sequences to the field. The first project sprint delivered a valuable drilling system which executes automated drilling operations. This tool will act as a platform for the next stages of project work to improve management of a drilling automation plan and operations at the rig site. The results described in this paper were outlined as future steps in SPE 195818.

The operator and rig contractor overcame some of the traditional cultural and technical barriers to efficiently develop DOA through technology collaboration. The project team used the operators’ standard well delivery processes to deliver a valuable tool to aid the driller’s workflow while standardizing repetitive and recurring steps in drilling operation activities. Engaging and collaborating with field personnel drove improvements to the automated processes and enhanced the value-adding tools to impact operations at a field level.
Predicting Trouble Stages with Geomechanical Measurements and Machine Learning: A Case Study on Southern Midland Basin Horizontal Completions
Authors: Romberg Eric , Fisher Aaron , Mazza Joel , Niedz Chris , Wehner Brian , Zhou Alex
Published: October 2020

Unexpected problems during completion create costs that can cause a well to be outside its planned AFE and even uneconomic. These problems range from merely experiencing abnormally high pressures during treatment to casing failures. The authors of this paper use machine learning methods combined with geomechanical, wellbore trajectory, and completion datasets to develop models that predict which stages will experience difficulties during completion.

The operator collected geomechanical data for 26 lateral wells. Several of these wells experienced significant difficulties during completion, including casing failures. By examining the completion data for the study wells, engineers developed two objective proxies for trouble stages: a high fracture gradient cut-off and a sand-to-water ratio cut off. The geomechanical data were combined with wellbore trajectory and stage-level completion data. Machine learning techniques were then used to predict the fracture gradient at the end of treatment and the sand-to-water ratio of a stage. The data were subdivided by target horizon to ensure the model results were not skewed towards a specific horizon. The models were cross validated, hyper-parameter tuned, and then tested against a subset of the data withheld from the training algorithm (the test data subset).

Multiple metrics were applied to measure the effectiveness of the models. For the fracture gradient regression, the model that minimized the root mean squared error (RMSE) was chosen. This model was compared to a prediction that each stage would have a fracture gradient equal to the average fracture gradient. The correlation between predicted and measured frac gradients was also calculated. These metrics were analyzed for both the entire data set and the test data subset. By all these measures the model performs significantly better than the control prediction. For the sand-to-water ratio metric, the model that maximized the receiver operating characteristic area under the curve (ROC-AUC or AUC) score was chosen. We chose to measure the success of the model with the precision of its prediction of outlier (trouble) stages on the test data subset. The model performs with a precision of at least 73%. Both models identify stages where casing failures occurred as trouble stages. With these initial results, the authors are confident they can predict the probability of any stage causing a significant operational disruption in these horizons.

By predicting the probability of a trouble stage, mitigation plans can be implemented to reduce costs ahead of time. By further analyzing the models, engineers can identify the major drivers for the trouble stages and work to reduce them as early as the well planning stage.
An Integrated Equation-of-State Compositional Hydraulic Fracturing and Reservoir Simulator
Authors: Zheng Shuang , Sharma Mukul
Published: October 2020

In this paper, we present an integrated equation-of-state based compositional hydraulic fracturing and reservoir simulator. The goal of this research is to develop a general simulator that can simulate the lifecycle of wells, which includes hydraulic fracturing treatment using water-based or energized fracturing fluid, post-frac shut-in and flowback with fracture closure and proppant settling, primary production with proppant embedment and fluid reinjection in a multiple well pad.

This simulator fully couples the reservoir, fracture, and wellbore domains with multiple physics in each domain. The rock deformation, porous flow and temperature change in the reservoir domain, fluid and proppant transport in the fracture domain, and wellbore slurry flow and fluid/proppant distribution among clusters are fully coupled together and solved fully implicitly using the Newton-Raphson method. The phase behavior of hydrocarbon phases is modeled using Peng-Robinson Equation-of-state. The fracture propagation is modeled by mesh topology change (dynamic remeshing and local refinement) and the propagation direction is evaluated using the stress intensity factors. This simulator has been fully parallelized using MPI. We show two applications of this simulator for lifecycle analysis in US unconventional oil reservoirs on frac-hits and CO2 fracturing.

In the first field application, we simulate a multi-well fracture diagnostics. We used the parent well to monitor the child well fracture growth. Child well fracture growth is correctly interpreted using the monitoring data. In the second field application, we perform lifecycle analysis of hydraulic fracturing treatment using hybrid CO2-slick water-crosslinked gel fracturing fluids and 100/30-50 mesh proppants and the following production phase from a well in the Bakken formation. We successfully match the complex surface treating pressure data from the field. We also successfully matched the cumulative production of oil, gas and water and explained the long-term CO2 flowback phenomenon in the field.

The novelty of this simulator comes from its unique modeling capability in the well lifecycle analysis. Fully coupled reservoir-fracture-wellbore framework allows accurate modeling of hydraulic fracture propagation in multiple well pads using multiple fracturing fluids and proppants, fracture closure during shut-in, primary production, refracturing, and pre-loading for parent well protection, and huff-n-puff improved oil recovery, all in one simulation. This simulator can be used as a reliable and efficient tool by operators in well lifecycle analysis.
A Modified Acid System to Enhance Carbonate Matrix Acid Stimulation – An Experimental Study
Authors: Zhu Ding , Uribe Julian , Sohn Daniel , Hill Dan , Ugursal Assiya , Shuchart Chris , Purdy Clay , Weissenberger Marcus
Published: October 2020

In carbonate matrix acidizing, the critical design parameters are interstitial velocity and pore volume to breakthrough for wormhole propagation at the optimal condition (vi,opt and PVBT,opt). These two parameters are determined by the formation rock properties including permeability, porosity, temperature, pressure, and mineralogy, and the acid system that will be used. HCl has been the most commonly used acid in carbonate acidizing. However, the efficiency of wormhole creation using strong HCl solutions is sometimes low because the injection rate needed for optimal wormhole propagation is not attainable, especially when applied to long completion intervals and/or low permeability carbonates. High concentration HCl solutions also raise safety and environmental concerns. When retarded acid systems are used to overcome these challenges, the efficiency of acid stimulation often suffers from low reaction rate and low dissolving power. This study presents testing results of a modified acid system that has controlled reaction rate with favorable wormhole propagation characteristics, especially at low interstitial velocities.

Due to the increased activation energy barriers utilized in these modified-acid systems, it is possible to control the reaction rate of the hydrogen proton and optimize the wormholing effect based on the completion method and formation specifications. Single phase modified acid systems are applicable and can be tailored for limestone and chalk formations. Laboratory linear core flooding experiments and acid jetting experiments were conducted to study the wormhole efficiency with the new acid systems. Core flood tests were designed to generate the wormhole efficiency curves and compare the results from the tests with HCl under the same conditions. Jetting experiments were conducted to evaluate the structure of cavity and wormhole development, and the results were also compared with HCl injection at similar conditions. Results from the experimental study were then used to compare the acid systems through wormhole efficiency curves and CT scans of acid dissolution structures.

The experimental results showed clear advantages of the modified acid systems. The modified acids have similar or better wormhole efficiency parameters compared with HCl having comparable dissolving power. When combined with acid jetting, further improvement in wormhole growth in low permeability limestone is achieved. In addition to minimizing the hazardous exposure levels, corrosion rates, and negative HS&E properties compared with hydrochloric acid, the new acid system provides the positive aspects of solubilizing ability and reaction rates thus improving optimal wormhole conditions (lower vi,opt and PVBT,opt). This potentially allows for better stimulation results with less fluid required.
Design of a Fiber Optic Based Wellhead Perimeter Monitoring System
Authors: Idachaba Francis
Published: October 2020

The advent of Digital Oil Fields (DOF), Data Analytics and Artificial Intelligence has led to an increase in the number of instruments installed at wellheads and also an increase in the reliance on these instruments and the data they provide for the operation of the field. The critical nature of this equipment and their roles in the operation of the oil field has also led to the need for a system of remote monitoring of these wellheads to enable the detection of third-party intrusion (TPI) at the wellhead area with the provision of video feedback on demand. The most popular security scheme currently deployed at securing these wellheads is the use of metal cages of different sizes, but the location of these wellheads provides vandals with ample time to cut through the metal cages as there is no means of detecting their presence. This system utilizes a fiber optic cable and cameras to provide intruder detection and identification. It transmits the signals wirelessly through the remote telemetry units at the wellhead. The fiber optic cable is buried around the wellhead, and the flowlines from the wellhead and a wireless transmitter are coupled to the fiber optic cable. The distributed acoustic system of the optic fiber is used to detect the presence of third-party interference at the wellhead locations, and the camera is activated by the system whenever TPI is detected around the wellhead area. The system provides both video feedback and color-coded alerts at the remote monitoring centers to indicate the location of the intruders and the intrusion activity around the wellhead area.