bluuebunny/crossref_metadata_2025 huggingface dataset:
Drilling Heat Maps for Active Temperature Management in Geothermal Wells
Authors: Khaled Mohamed Shafik , Chen Dongmei , Ashok Pradeepkumar , van Oort Eric
Published: September 2022

Geothermal (GT) energy has gained much attention as a promising contributor to the energy transition for its capacity to provide a reliable, environmentally friendly source of baseload power. However, drilling high-temperature reservoirs presents significant technical and economic challenges, including thermally induced damage to bits and downhole tools, increasing drilling time and cost. This paper introduces the benefits of drilling heat maps for pro-active temperature management in GT wells during the well planning phase and the real-time drilling operations phase to avoid thermally induced drilling problems.

This study uses a transient hydraulic model integrated with a thermal model to predict the bottom hole circulating temperature (BHCT) while drilling GT wells. The model was used to generate a large volume (1000's) of case scenarios to explore the impact of various cooling and other heat management strategies on downhole temperature, covering a wide range of drilling parameters. Results were captured, visualized, and analyzed in convenient heat maps, using the Utah Forge GT field as an example, illustrating the advantages of using such heat maps in GT well construction and real-time operations.

Model validation with Forge 16A(78)-32 well data and Hasan and Kabir's well temperature model show very good results, with a mean absolute percentage error (MAPE) of less than 3.2%. There is a clear logarithmic relationship between the drilling flow rate and BHCT at a constant mud inlet temperature, and a linear relationship between the mud inlet temperature and BHCT at a constant drilling flow rate. Pronounced variation of BHCT in GT wells was observed with mud type, mud weight, and mud viscosity. In addition, insulated drill pipe (IDP) technology was found to significantly reduce BHCT (14-44% on average for Forge scenarios) compared to conventional drill pipe (CDP), particularly in wells with extended measured depth where other heat management technologies and strategies become less effective.

Drilling heat maps can alert drilling engineers to strategies with the highest BHCT-lowering impact, allowing focused technology selection and decision-making regarding optimum temperature management during the GT well design phase. Real-time heat maps, on the other hand, are valuable for facilitating active temperature management and providing real-time guidance for optimum drilling parameters during daily drilling operations. In general, heat maps can help to avoid drilling problems related to high temperature, thereby helping to facilitate safe and cost-efficient development of GT resources.
Auto Driller Improvements and Open Source Modeling Reduce Drilling Time and Trips
Authors: Pastusek Paul , Barajas Pablo , Hinojosa Agustin , Clayton Patrick , Whatley Michael , Soni Somesh , Manocha Malini , Saxena Subodh , Dixit Rajat , Payette Greg
Published: September 2022

The objective of the auto driller is to maintain stable control of drilling parameters to reduce the time per stand and increase single run sections when possible. Large variation in rate of penetration, weight on bit, differential pressure, torque, and rotary speed have been found to damage the bit, motor, and bottomhole assembly (BHA), reducing the performance and life of these tools.

During operations it was found that some instability in drilling parameters was introduced by the auto driller. The first attempt was to find the best set point combination to improve stability and net rate of penetration (ROP). This helped, but the system still tended to be unstable with changes in formation. The next step was to adjust the auto driller tuning parameters to improve system stability. The tuning was modified so that the system could be stabilized over the range of formations being drilled and were sent to the real-time centers and recorded to become part of the drilling roadmap.

The net rate of penetration, or minutes per stand, was used as a key metric for real time performance. Variation in rate of penetration, weight on bit, differential pressure, torque, and rotary speed were used as leading indicators of BHA stress and thus life expectancy. Manually tuning these systems on the rig, with intensive support from the operator’s and contractors subject matter experts, and real time centers resulted in a reduction in drilling time and stress on downhole motors and tools.

The drilling time was improved from 30-50 minutes per stand to 18-25 minutes per stand in the fast drilling part of the lateral interval (about 1500 meters). Furthermore, the fluctuation of the drilling parameters were reduced to two-thirds compared to previous wells. The drilling team completed its first shoe-to-TD single run in two years in the 8-1/2" section, typically requiring three BHAs. This was drilled in about half the time compared to the prior single run and was followed by another 3000-meter single run lateral. The downhole temperature in this section exceeded the motor vendor’s specifications and reducing the stress on the BHA due to parameter variation was critical in improving performance.

Key performance indicators were developed to measure the health and function of the auto driller system. These were shown to be useful as real time and leading indicators of performance. A case study demonstrates how to use these KPIs to manually tune the system while drilling.

Finally an example is shown on how to use source code from the Open Source Drilling Community to help tune the system offline and make it more robust to formation changes.
Wellbore Survey and Drilling Margin Optimization for Stress Change and Rotation Around Depleted Reservoirs
Authors: Su Xing , Nguyen Kien , Mehrabian Amin
Published: September 2022

Uniaxial models are commonly used to describe the change in magnitude of in-situ principal stresses around depleted reservoirs. The accuracy of these models is assessed in this paper through a reservoir-scale analytical solution for the stresses induced by depleting a disk-shaped reservoir embedded within an infinite elastic model of the subsurface. The Hankel-Fourier transform expressions of axisymmetric Green’s functions for a ring-shaped eigenstrain in an infinite elastic medium are used to develop the solution. This solution is validated against numerical simulation results of COMSOL®. The solution is next used to obtain the safest deviation survey, as well as the corresponding drilling margins of infill wellbores that are drilled in the general vicinity of depleted reservoirs. Inside and outside of a reservoir subjected to different faulting regimes are considered for the wellbore-scale stress analysis. Results indicate that despite their common use, the uniaxial models may return significantly erroneous predictions of the in-situ stress state in depleted reservoirs. In particular, the in-situ stress changes are found to strongly depend on the geological azimuth and radial distance from the reservoir center point. Consequently, the uniaxial models may fall short in accurate prediction of the shear or tensile failure gradients of infill wells. These errors would be more substantial for wells that are closer to the reservoir flanks.
Newly Developed Aqueous Paraffin Inhibitor Dispersion Provides Flow Assurance During and After Stimulation
Authors: Xu Liang , Sirak Sofia , Schenderlein Helge , Meister Claudia , Kakadjian Sarkis
Published: September 2022

A typical challenge encountered during hydraulic fracturing is severe wax deposition on the rock surface inside fractures as relatively cold fracturing fluids encounter hot crude oils in the reservoir. This results in multiple production challenges for operators because either crude oil viscosity increases due to loss of light compounds, or wax deposits clog the effective flow paths from interior of the reservoir to the wellbore. This is of particular concern when the temperature and pressure start to drop rapidly right inside the fractures. In the past, water-soluble surfactant-based wax dispersants have been frequently used to combat excessive wax deposition during frac. Polymer-based paraffin inhibitors, despite being more effective and more soluble in crude oils, however, have not been extensively deployed because they are insoluble in water and incompatible with commonly used frac additives, unless they are encapsulated or adsorbed in substrates. Most importantly, our water-based technology platform makes it possible to combine water dispersible paraffin inhibitors with scale inhibitors, clay stabilizers or surfactants, essentially creating a multi-functional frac additive. This new approach leads to potential logistic savings and reduced carbon footprints.

In this paper, a newly developed water dispersible paraffin inhibitor is discussed. This innovative solution allows the product to be fully compatible with most frac fluids, in particular regard to polyacrylamide-based friction reducers. Typical emulsion/sludging tendency, salinity tolerance, pour point, viscosity and cold finger tests, etc. were performed to ensure that the product remains effective and travels in the leading edge of frac fluids under downhole conditions.

In a similar mechanism to conventional emulsion-based friction reducers, the aqueous paraffin inhibitor dispersion was tailored to enable rapid phase inversion, releasing active polymer into frac fluids and interacting with waxy oils. Most importantly, it was demonstrated that molecular weight of aqueous paraffin inhibitor dispersion polymer played an important role in dictating its inhibition efficiency against wax deposits, while allowing additional components such as scale inhibitors, surfactants, etc. to be incorporated in the same formulation.
Installation Steps and Fishing Design of Rigless Cable Deployed Conventional ESP System
Authors: Zhao Mengpan , Hong Yuandong , Zeng Fanqian , Zhang Qiang , Zhu Lisha , Li Qijun
Published: September 2022

Cable Deployed Electrical Submersible Pumping (CDESP) System is a new generation of Rigless ESP technology, it utilizes the specialized cable for ESP changeout, which will save rig cost and reduce field operation time significantly.Cable deployed conventional ESP system is a game-changing technology in the Rigless ESP industry, which makes the CDESP compatibility possibleby using conventional ESP instead of inverted ESP assembly.

However, reliability is always the main concern of clients, especially when it fails to retrieve ESP assembly by the specialized cable, a rig will have to be neededto carry out the ESP replacement jobs.

This paper will introduce the design philosophy and installation procedure of Rigless Cable Deployed Conventional ESP System to demonstrate how to ensure the reliability and robustness. In addition, emergency fishing design is proposed to pull out from weak point in case of failing to retrieve ESPby cable and fully eliminate the rigs inESP replacement-jobs.
Successful Intervention Through Multilateral Completion Window for Logging and Wellbore Treatment
Authors: Sharma Hemant K , Almasri Abdulrakeeb
Published: September 2022

Effective well completion design is crucial to maximize reservoir recovery rates, with many exploration and production (E&P) companies utilize multilateral technology to achieve this important objective. However, as fields mature and more wells are drilled, cost-effective reservoir management becomes more challenging.

The E&P companies drill dedicated wells to collect important data for reservoir planning, with well logging conducted periodically to monitor the changes in the reservoir. Observation wells have been drilled in different locations to monitor the reservoir and assist with planning and intervention decisions. However, these wells can be costly and occupy valuable space that could be utilized for production. An alternate technique enables E&P companies to drill a pilot hole, perform all the necessary logging, and obtain the required reservoir information. The pilot hole is then plugged and abandoned. Even though this technique saves the space occupied by a dedicated observation well, the collected data only remains valid for a limited period due to potential changes to the reservoir.

The production and completion engineers have further leveraged this solution and developed a new multilateral well technology that addresses these challenges. These enhanced technologies allow wells to be completed with a pilot hole (vertical) drilled for reservoir evaluation throughout the life of the well, with permanent downhole monitoring system (PDHMS) with permanent downhole monitoring gauges (PDHGs) installed for pressure and temperature monitoring, while the horizontal lateral functions as an oil/gas producer. Combining the observation and producer wells into one well results in cost savings and maximum reservoir recovery and management. In addition, the capability to access the lateral allows for intervention in both the motherbore and lateral at any time. A well completed with this multilateral technology recently required intervention for well logging and treatment to revive the well. Slickline runs were performed to gain access to the horizontal lateral, which included retrieval of an isolation sleeve and installation of a tubing exit whipstock (TEW) for lateral re-entry. Later, coiled tubing (CT) was run through the window into the lateral to perform intervention operations and revive the well. Upon completion of the intervention, the TEW was retrieved from the window, the isolation sleeve was reinstalled, and the revived well returned to production. Well intervention through this multilateral completion demonstrates the ease and efficiency of accessing both the vertical and horizontal lateral, without requiring a rig or completion retrieval.

This paper will highlight the multilateral completion technology for accessing both the laterals, including real-time monitoring capabilities that provide more reliable data to maximize the recovery and management of the reservoir, as well as perform effective intervention.
A Novel Mittag-Leffler Function Decline Model for Production Forecasting in Multi-Layered Unconventional Oil Reservoirs
Authors: Pan Yuewei , Li Guoxin , Ma Wei , Lee W. John , Yang Yulong
Published: September 2022

Over the past several decades, Arps decline curve analysis (DCA) has proved to be effective and efficient for production forecasts and EUR estimates due to its simplicity and applicability. However, as multi-stage hydraulically-fractured horizontal wells have unlocked the economic potential of unconventional reservoirs, forecasting future production accurately using Arps decline models becomes more challenging because of the complicated fluid flow mechanisms characterizing stimulated multi-layered ultra-low permeability porous media. Many field studies indicate unreliable forecasts and limitations in multi-layered field applications in particular. This paper presents a Mittag-Leffler (ML) function decline model which enhances the reliability of forecasts for multi-layered unconventional oil reservoirs by honoring anomalous diffusion physics for each layer.

Many traditional decline curve models fail to honor the sub- or super-diffusion phenomenon under the paradigm of anomalous diffusion. The general form of our proposed two-factor ML function consolidates anomalous diffusion and classical diffusion into a single model, specifically including Arps hyperbolic, harmonic, exponential decline models and the stretched exponential decline model (SEPD) as special cases. Comparisons show that the ML model falls between the predictions of Arps and SEPD models in which the estimates are consistently either "overly optimistic" or "too conservative." For a multi-fractured horizontal well, the fracture height partially penetrating different layers leads to a layer-wise flow pattern which is reflected and captured in the production profile by curve-fitting the corresponding ML function parameters. We provide a workflow to guarantee consistency when applying the approach to each layer in field cases. We applied the workflow to one synthetic case using embedded discrete fracture modeling (EDFM) and to two field cases. We used hindcasting to demonstrate efficacy of the model by matching early-to-middle time production histories, forecasting future production, and comparing forecasted performance to hidden histories as well as to the corresponding EURs. The comparisons demonstrate the validity and reliability of the proposed ML function decline curve model for multi-layered unconventional oil reservoirs.

Overall, this study shows that the novel ML-function DCA model is a robust alternative to forecast production and EUR in multi-layered unconventional oil reservoirs. The workflow presented was validated using one synthetic case and two actual field cases. This method further provides unique insight into multi-fractured horizontal well production profile characterization and facilitates well-spacing optimization, thereby improving reservoir development in layered unconventional reservoirs.
Overcoming Virtual Training Challenges to Promote the Adoption of Cloud Solutions
Authors: Yuan Zhaoguang , Hashemian Yahya , Morana Jorge , Celis Alexander , Tee Karen Ying Chiao
Published: September 2022

Cloud solutions play an essential role in digital transformation in the oil and gas industry. Training is key to promote cloud solutions and accelerate digital transformation. Unlike legacy computer-based software, agile development, which continuously releases new features of cloud solutions, makes the learning process more challenging because of the necessarily fast-paced adoption of the knowledge. Another challenge was that we had to virtually deliver the training sessions because of the pandemic during 2020 and 2021, which made the interaction with students very difficult without face-to-face contact.

To be ready for the virtual training challenges, a self-guided quick-learning page was created and leveraged to bridge the gap between the continuous release of new features in cloud solutions and the fast-paced knowledge adoption. Training materials, including the self-training page, were updated once every quarter to reflect the new features in the cloud solutions. Unlike traditional software, after each training, the web-based training environment (tenant) was occupied by many training projects created by students, which made it difficult to be used by the new group of students. To solve this issue, a new procedure was developed to efficiently reset the tenant to ensure a smooth and data-secured training.

As the training requests grew exponentially, more than 35 training tenants were created to meet the high demand and frequency of training from different customers across the world. The self-guided quick-training page has more than 17,454 visits and 600 unique users, with positive feedback from students. In 2021, more than 630 users from 40 countries were successfully trained. This is a two-fold increase from 2020 and a five-fold increase from 2019.

In this paper, we provide new insight to successfully deliver virtual training and promote the adoption of cloud solutions in the digital transformation of the exploration and production industry.
Real-Time Bacteria Monitoring Applications in Oil & Gas Operations can Help to Prevent and Mitigate Corrosion
Authors: Steffensen Aurelija , Miller Morten , Elleskov Susan , Vilain Eric
Published: September 2022

Controlling bacteria in Oil & Gas operations is essential for flow assurance and avoiding unhealthy environments developing in the systems.

The resistance of bacteria grows stronger as they manage to survive environments, In gaming terms, the bacteria is "leveling up" every time it faces and overcomes adversities, thus getting more resilient. Once bacteria are present in medias of Oil & Gas, they will already be bacteria with high survival skills and with very complex development and growth path. Knowing the total content of bacteria can provide confident decision-making on aspects such as HSE, system integrity, biocide selection, and dose frequency.

As anaerobe bacteria are very harsh on metal structures, they can cause corrosion and damage and shortened lifetime on flow structures and pipelines. Ideally, bacteria are monitored closely with short testing times to ensure rapid decision-making and initiation of mitigating actions.

However, the traditional methods for detecting and enumerating bacteria in Oil & Gas operations are cumbersome and time-consuming, with analysis times of 24 hours to 28 days, making them inefficient in an operational environment that requires rapid decision-making to stay in control. Tools that address these limitations are thus in high demand.

In this study, we will describe how a field portable technology for fluorometric determination of a hydrolase activity can be used to identify and monitor bacterial contamination in an offshore operation in near real-time.The study demonstrates how the use of the enzyme method allowed the platform chemical engineer to quickly identify a bacterial contamination issue, related to a failed biocide injection pump and allowed the platform manager to rapidly initiate relevant mitigation of the problem.
Validation and Analysis of the Physics-Based Scaling Curve Method for Ultimate Recovery Prediction in Hy-Draulically Fractured Shale Gas Wells
Authors: Arias Ortiz Daniela , Bounceur Nabila , Patzek Tadeusz W.
Published: September 2022

Patzek et al. (2013, 2014) proposed the generalized physics-based scaling curve method as an alternative approach to the empirical decline curve analysis that predicted shale gas well production. Independently, (Patzek, 2019; Patzek et al., 2019) also introduced the Generalized Extreme Value statistics to evaluate cohorts of shale wells and their survival rates. In this work, we built a conceptual reservoir model of a typical, hydraulically fractured well in the northeast Pennsylvania Marcellus shale using a commercial reservoir simulator (CMG-GEM) to validate the generalized master curve numerically. We use the simulated gas production as the input data to estimate the generalized reservoir scaling curve, and we compare it to the master curve presented in Saputra et al. (2022). Our results reveal that the physical scaling method captures the physics behind gas production from mudrock plays. Our reservoir simulations agree with the master curve. We conclude that the simple method is an excellent alternative to the current industrial forecasting methods as it is computationally cost-effective, more flexible, and requires fewer input data. Also, the numerical reservoir simulations confirm the behavior of the generalized scaling curve with the variation of selected input factors. We complemented this study by conducting a global sensitivity analysis (GSA) to systematically examine the impacts of hydraulic fracture half-length and spacing, unstimulated shale permeability and gas adsorption on the variations of two master curve scaling parameters, the gas mass in the stimulated reservoir volume (MSRV), and the characteristic pressure interference time (τ). GSA using a reservoir simulator is prohibitive. Therefore, we implement and validate a Gaussian process emulator that represents probabilistically the scaling parameters estimated from the reservoir simulation output. We calibrate the emulator with a small set of experiments sampled with a space-filling design. The conducted study provides new insights into the relationship between the production scaling variables MSRV and τ and the reservoir parameters. The results reveal the high importance and nonlinear effects of the hydraulic fracture height, half-length, maximum gas volume adsorbed, and matrix porosity in varying the scaling variable MSRV. Also, the unstimulated matrix permeability and the hydraulic fracture spacing contribute significantly to nonlinear variations of the scaling variable, τ. Finally, gas adsorption has a small effect on the cumulative gas produced but significantly affects the scaling factor MSRV. Thus, gas adsorption becomes essential when estimating the ultimate recovery factor in the Marcellus shale wells.
Automating Log Interpretation for Optimal Well Placement and Increased Drilling Efficiency
Authors: Jonsbråten Fredrik , Iversen Marianne , Røsvik Jensen Kåre , Vik Constable Monica , Haktorson Hilde , Holbrough David , Wessling Stefan
Published: September 2022

The Troll oil field has been one of the largest oil producers on the Norwegian continental shelf for the last 25 years and is now moving into late life. The remaining oil column is thin, and the fluid contacts vary due to production effects. To extend field lifetime and secure the last reserves, enhanced well placement and increased drilling efficiency is needed to reduce cost and increase recovery in the long multilateral horizontal wells. Due to thin oil column and low reserves number, every meter correctly placed in the reservoir counts. To investigate these challenges a technology development project was initiated between Equinor and Baker Hughes to develop automatic interpretation of the oil-water contact (OWC) based on inversions, and automatic steering advice for taking faster geosteering (RNS) and downlink decisions placing the wellbores at the optimal distance to the OWC.

Automating log interpretation is a complex task, but solvable given a known environment. As an engineering problem it must be split up into multiple smaller tasks that can be independently solved and when combined, solve the greater task. Logging while drilling (LWD) deep azimuthal resistivity data is run through inversion processing which provides a resistivity profile from which the OWC position is identified. The inversion input model constraints are set based on field/area specific data and is run automatically as drilling progresses.

To assess the quality and validity of these results, several flag curves are computed and used. This automatic quality control of the OWC points enables the creation of a forward projection of this boundary. A steering advice is calculated, giving a recommendation on how to achieve the desired stand-off and inclination above the OWC as efficiently as possible.

All the output from the automatic interpretation is published to a central datastore and is immediately available for the geoscientists to optimize operational decisions.

Close co-operation between the operator and the vendor during the development and testing of the service has proven beneficial for identifying areas for further improvements. The service has been tested for well placement in actual producers.

Several loops have been made in the development between the different tests and the learning curve has been steep in both companies. Based on the experiences and results from the actual wells, the project has moved into a new phase for further optimization of the steering advice and linking the automated steering advice to an Automatic Drilling Control (ADC) system to deliver a more automated closed loop service.
An Engineered Microparticles-Based Slurry Pumped in Over 10,000 Stages Provided Notable Operational and Production Improvements in Challenging Formations
Authors: Radwan Amr , Ramanathan Raja , Ivanishin Igor , Ibrahim Ahmed Farid
Published: September 2022

In some shale plays, insufficient formation breakdown and presence of near-wellbore tortuosity make it challenging to reach the designed pumping rate and lead to premature screen-outs. Screen-outs during a fracturing operation are a tremendous burden for operators as they diminish the well's total production and add cost to do a wellbore cleanout. In some cases, these issues could cause suboptimal perforation cluster efficiency and production loss. There is a critical need for an easy-to-implement solution that can help operators in achieving their desired fracture designs. This paper presents field case studies of a new microparticles-based slurry (MPS) technology that proves ease of operations and an improvement in production across four different US shale basins.

Non-hazardous water-based slurry contains engineered glass microparticles with a median size of 550–625 mesh. It was implemented in the Rockies, Powder River, Permian, and SCOOP/STACK with over 10,000 stages stimulated so far. The slurry was usually deployed as an additive to the pad or as a pill before pumping the proppant-laden slurries. It is compatible with commonly used fracturing fluids. The MPS technology helps in scouring the perforations and lessening fracture entry restrictions. This results in better fracture initiation and lowers the screen-out potential. The technology also widens fracture openings, restricts fracture complexity, reduces near-wellbore tortuosity, and increases reservoir connectivity. The slurry can be used as a far-field diverter pill as well.

Field studies in multiple challenging formations involving alternating stages between the microparticle slurry and the standard control showed a 12–25% reduction in pump time due to significant pressure relief. In another pad, the MPS reduced the screen-outs by over 6 folds. Production data showed up to 19% uplift within a 15-month period against control wells. The production improvement analysis is a subject of further study. Oil and water tracer tests confirmed the production improvement in stages that had the microparticle slurry. Overall, the success rate of the technology has been unprecedented and has been gaining significant ground over the past year.

Realizing a treatment design is a critical step in maximizing the rate of return on a well. This new chemical slurry offers operators a simple, cost-effective, and field proven solution to alleviate operational issues and potentially be more aggressive in completion designs. The diverse case studies in this paper prove the efficacy of this innovative technology in solving the major day-to-day fracturing challenges faced by completion engineers.
An Investigation into Non-Reservoir Components that Undermine Reservoir Responses in Transient-Test Data
Authors: Rahman N M Anisur , Sarac Sukru
Published: September 2022

Transient-test data can be significantly affected by subtle non-reservoir noise generated by natural or operational factors. The impact of such noise on the pressure-transient analysis depends on the signal-to-noise ratio achieved during transient tests. Often, a misleading interpretation of the reservoir characteristics can result. This study will quantify such effects on the interpretation results by evaluating the signal-to-noise ratio as in wireline testing operations, deep transient testing, drill-stem testing and production testing.

Effects of non-reservoir factors can be difficult to identify, and often may lead to misrepresentations or misinterpretations. Analytical and numerical reservoir simulations will be used to illustrate quantitative criteria of defining the acceptable operating conditions and preferable techniques for pressure-transient-tests, depending on the reservoir characteristics. Convoluted effects of noise, drift, resolution, periodic tides have been quantitatively evaluated to demonstrate the situations when the reservoir signal is too weak to achieve meaningful characterization. Different pressure-transient techniques will be evaluated with a focus on the signal-to-noise ratio.

Certain disruptive behaviors of equipment and nature tend to distort the measurements performed during such tests. Depending on the amount of disruption caused in the measurements during the tests, there are situations when the test objective may not be achieved at all. Failure to create dominant reservoir responses can result from an insufficient signal-to-noise ratio with the rate of production and pressure drawdown. It is a function of formation and fluid properties and/or mechanical environment. A minimum rate of production is needed for creating a necessary magnitude of signal-to-noise ratio to interpret correctly the reservoir response. The paper will help determine the minimum rate of production and the duration of flow needed to obtain the presence of deep heterogeneities or boundaries with a reasonable level of certainty. If a test is run with a rate lower than the critical value, for example, the data will be biased by other hardware or natural factors that are unrelated to the reservoir signals. Illustrative examples will also be presented to show how misleading characteristics of the reservoir and the well can be deduced without sufficient signal-to-noise ratios.

This study will quantify the non-reservoir factors by evaluating the corresponding signal-to-noise ratios. As a result, a practical guide will be created for selecting a proper testing method from a quantitative point of view.
Using AI Cuttings Load Classification to Assess Hole Cleaning and Wellbore Stability
Authors: Holt Calvin , Ruel Francois
Published: September 2022

This paper discusses a field test that placed computer vision cameras on rigs' shale shakers to measure drilled cuttings and cavings. The images from the camera were processed using proprietary computer vision software and sent to the drilling team, where it was used to assess drilling performance, hole cleaning, and wellbore stability. This Proof of Concept (PoC) test was conducted over five months on two drilling operations in the Marcellus shale, using three different camera types placed in two shaker locations. Over 200,000ft of video data from 11 wells were collected from the West Virginia / Pennsylvania regions. This paper describes the research and development of this technology's hardware (camera) and software (computer vision).

To the author's knowledge, this is the industry's first use of computer vision to measure drill cuttings autonomously and continuously at the rig site. Computer vision applied at the shaker will increase overall ROP, greatly improve the speed and accuracy of wellbore instability detection, reduce the exposure in a hazardous zone and improve the detection of pending downhole problems.
Adapting Petroleum Reservoir Engineering Principles to Carbon Capture & Sequestration (CCS) and Hydrogen Underground Storage (HUS) Projects: Opportunities and Challenges
Authors: Mishra Srikanta , Datta-Gupta Akhil
Published: September 2022

Carbon Capture and Sequestration (CCS), which combines capture of CO2 from large stationary sources with geological storage, has emerged as an attractive option for emissions reduction. Hydrogen underground storage (HUS) is viewed as an effective strategy for storing large volumes of surplus electrical energy from renewable sources. The objective of this paper is to discuss the opportunities and challenges for adapting petroleum reservoir engineering techniques for the subsurface aspects of CCS and HUS projects based on a critical review of field projects and conceptual studies. Areas of focus include: (a) storage resource estimation, injectivity analysis from field data, dynamic reservoir modeling, and coupled flow and geomechanics for CCS, and (b) well deliverability, dynamics of fluid withdrawal and reactive transdport of hydrogen in-situ for HUS projects. Specifically, our goal is to discuss how traditional workflows for oil and gas applications have been (or could be) modified for CCS projects in deep saline formations and HUS projects in salt caverns or aquifers. We also identify specific areas where reservoir engineering practitioners can add value in CCS and HUS related reservoir analysis and modeling.
Comparative Analysis of Data-Driven, Physics-Based and Hybrid Reservoir Modeling Approaches in Waterflooding
Authors: Mogollon Jose Luis , Tillero Edwin , Calad Carlos , Lake Larry
Published: September 2022

Hydrocarbon production optimization is essential in pursuing the best scenarios for economic outcomes. But because of complex and multi-dimensional nature of production processes, thousands of scenarios are possible. Extensive data collection may allow uncovering patterns still unidentified. With on-site computing power increasing, cloud availability, and artificial intelligence evolution, mathematical optimization methods are becoming powerful and accessible. Data type-tailored models are implemented for history matching and prediction of operational efficiency of the asset. This paper presents a comprehensive analysis and comparison of three data type-tailored reservoir modeling methods and their optimization process for waterflooding field cases.

The mathematical techniques used were Data-Driven Capacitance Resistance Model (CRM), Numerical Simulators (Data-Physics) coupled to Smart Algorithms Optimizers, and Hybrid Model (Machine Learning Physics-Based). They were compared to 1-identify the benefits of mathematical optimization techniques, 2-illustrate the methods developed to sort out time and computing capacity restrictions, and 3-validate the techniques by comparing the forecast with actual results.

The six study cases of different reservoir types in Argentina, Venezuela, and the USA, had different types data availability. Four had no static model. In two cases, field results were available to confirm the accuracy of the forecasted injection and production. The forecasted increase in Net Present Value (NPV) and cumulative oil production (Np) ranged to 30%, and optimized water injection rates decreased by 50%.

Traditional modeling techniques yielding unreliable result in one field with hundreds of producing layers and unknown lateral and vertical continuity were solved using a machine learning technique. In some cases, they pointed toward non-intuitive infill drilling sequence and injection water redistribution. Also, they pointed to options that reduce economic risk. The methods yielded many better economic scenarios and increased the flexibility of operationalizing plans. In one field requiring excessive computing power, using time horizons reduction and successive year-by-year optimization yielded 4 times the NPV of the base case. This approach solves objections related to long computing time and system instability. With the three mathematical techniques, the asset value could be continually maximized by a novel implementation of a heuristic decision-making approach that continuously challenge the current scenario. It makes a systematic formulation of conceivable new scenarios, competing through an objective function determining the probity of compared scenarios.

The optimization also resulted in an up to 50% decrease in water injection requirements and the same percentual CO2 emissions reduction.
The Impact of Petrophysical Heterogeneity on the Carbon Capture Utilizations and Storage Strategies
Authors: Alqahtani Fahd Mohamad , Althehibey Mohammed Talal , Ghasemi Mohammad
Published: September 2022

Carbon capture utilizations and storage strategies (CCUS) have recently attracted many interests to mitigate the global warming and reducing CO2 emission in the atmosphere. Injecting CO2 into the depleted hydrocarbon reservoirs and aquifers has been focused as one the main CCUS strategy. This paper presents a comprehensive study on the effects of reservoir heterogeneity that are defined as important physical criteria to determine the success of CCUS projects.

We develop an equation of state (EOS) fluid characterization with 34 components. Wide range of fluid composition from black oil to gas condensate system was generated to capture the degree of fluid heterogeneity in the reservoir. The results of various PVT tests such as CCE, swelling test with CO2 and MMP were compared for different heterogeneous fluid systems. The pseudoized EOS model was optimized to a minimum number of pseudo components that reproduce the physical properties of full-EOS model. The detailed EOS model was then employed by a full compositional reservoir simulation model to study the CO2 injection in a depleted oil reservoir with high degrees of heterogeneities. Various range of porosities, permeabilities, formation temperature and injection pressure scenarios were considered during sensitivity analysis of CO2 storage in depleted reservoir.

Prior to CO2 injection the reservoir depleted from initial reservoir pressure to its abandoned pressure which resulted in forming a gas cap zone with low residual oil saturation. Case scenarios with homogeneous fluid composition, and petrophysical heterogeneity at different reservoir conditions where considered for initialization of the reservoir sector model. Results show that the oil saturation at the abandoned pressure is strongly dependent to the initial condition which effect the CO2 storage efficiency at the later period. During CO2 injection period, the oil recovery profile and the CO2 storage are considerably affected by reservoir heterogeneity, reservoir conditions and different injection scenarios. High CO2 storage was achieved with high CO2 injection pressure with a certain degree of heterogeneity and at low reservoir temperatures.

This paper provides a better understating of CO2 storage mechanism under various range of petrophysical heterogeneity and different reservoir conditions.
The Impact of Regional vs. White Sand on Long Term Multi-Fractured Horizontal Wolfcamp Well Production
Authors: Shelley Robert
Published: September 2022

Proppant selection is an important aspect of hydraulic fracture completion design. Recently, the industry has moved toward the use of lower cost regional sand as the propping agent for multi-fractured horizontal well completions in the Permian Basin Wolfcamp. An evaluation of early time production data indicates that there is minimal difference in first year well production with the use of regional vs white sand. These comparisons are the subject of SPE 199751, Shale Frac Designs Move to Just Good Enough Proppant Economics. However, does this conclusion hold up when evaluating longer term well production. The subject of this paper is a follow-up study which incorporates re-allocated production and new data to facilitate the evaluation of regional vs white sand on longer term well production.

A database consisting of reservoir, completion, frac and production data from 297 Multi-Fractured Horizontal Wolfcamp B Completions was assembled. New production allocations and previously unavailable production data are incorporated to allow comparisons of two and three year cumulative oil, gas and water. A Self Organizing Mapping (SOM) methodology was used to determine relevant well groups of like reservoir characteristics in which valid comparisons of regional vs white sand well production can be made. This type of approach is intended to normalize on differences in well reservoir characteristics and compensate for inconsistencies in the data that could impact comparisons of regional vs white sand well production.

Within this database there is a wide variation in reservoir characteristics and completion design. These wells were completed by many different operators using lateral lengths up to a high of almost 15,000 ft., proppant intensities from 500 to 4,000 lb./ft. and frac stage spacing from 59 to 769 ft. In the performance of this project, it became apparent that reservoir characteristics along with completion design factors have a dominate impact on multi-fractured horizontal Wolfcamp B well production. It was critical to factor out these non-sand type factors to quantify the influence of regional sand usage. As we would expect, wells with the most pay thickness, greatest permeability along with relatively higher pore pressure, effective porosity and low water saturation have the greatest potential for hydrocarbon production. The most productive completion types have longer length laterals, more frac stages (closer spacing), more proppant and fluid intensity.1

Based on this evaluation, the use of lower cost regional sand as the fracturing propping agent results in a negative 4% impact on first year well production. After 3 years of production this negative impact has increased to over 7% compared to white sand completions. In areas with better reservoir quality rock, the negative impact of regional sand use can be more significant. Conversely in areas with poor reservoir quality rock, the use of regional sand use has a less significant impact on well production.
Quality Isotope Analysis at the Wellsite: Two Case Studies that Validate GC-C-IRMS Mud Gas Isotope Logging for Deepwater Exploration and Development
Authors: Furghieri Bylaardt Caldas Priscila , Snatic Jonathan , Kronenberger Kurt
Published: September 2022

Geochemical analysis of gases produced during the drilling process is a common study on oil and gas exploration and development wells. This process typically includes the use of gas sample containers or other vessels that allow for single point samples to be collected for shipment to an offsite laboratory. Laboratories use high precision devices to obtain valuable information for reservoir characterization including stable carbon isotope ratios. In recent years there have been efforts to provide similar analyses during the drilling process, using ruggedized equipment suitable for wellsite deployment. This paper demonstrates that a Gas Chromatograph-Combustion-Isotope Ratio Mass Spectrometer (GC-C-IRMS) analyzer, using similar technology to what is most widespread in offsite laboratories (Dashti et al, 2018), can be successfully deployed to the rig site.

This type of advanced gas analysis, commonly known as Mud Gas Isotope Logging (MGIL), provides continuous sampling of stable carbon isotopes of methane (δ13C1), ethane (δ13C2), and propane (δ13C3). The service, performed with a GC-C-IRMS analyzer, was proven and validated for an operator through two case studies. 98

The first case compares real time data with discrete gas sample tubes analyzed in an offsite laboratory. It shows how accurate results are possible, even with the presence of artificial gases generated by drill bit metamorphism (DBM) (Wenger et al, 2009). This example also demonstrates how the service enabled immediate analysis for operational decisions by indicating the presence of biodegraded thermogenic fluid.

The second case study demonstrates how this wellsite service could corroborate the geological prognosis in a complex field influenced by salt tectonics. In this basin an upthrown reservoir changed the typical behavior observed in conventional wells of increased oil maturity with depth. Stable carbon isotope readings obtained in real time, integrated with cuttings analysis, indicated the presence of out of section lithology. This information allowed for estimating the thermogenic fluid maturity of reservoirs and diagnosis of geological formations that were out of sequence in terms of age (uplifted).