bluuebunny/crossref_metadata_2025_split huggingface dataset:
Novel Completion to Manage Crossflow in a Newly Completed Openhole Gravelpack Gas Well. A Case Study From the Norwegian Continental Shelf
Authors: Hewitt Neal , Tay Boon Li , Rincon Alexander , Ringe Thomas 
Published: September 2022

Abstract
An openhole gravelpack (OHGP) gas well was planned as part of an infill drilling campaign on a mature Norwegian Continental Shelf field. A geological pilot hole unexpectedly identified a significant pressure differential between two reservoir intervals. This paper describes an innovative modification of the lower completion, within a short turnaround time, in order to manage the clean-up of the reservoir intervals and limit crossflow.
Calculations based on the pilot hole results predicted that the low pressure reservoir would not flow until there was significant depletion in the high pressure reservoir. This risked formation damage due to delayed clean-up. Additionally, there was potential for very high crossflow rates that risked mechanical damage to lower completion equipment and/or causing formation damage.
There was insufficient time to completely redesign the completion. A solution, supported by simulations, showed that a fixed choke in the lower completion would enable immediate clean-up of both reservoir intervals. Additionally, aplug had to be set in the gravel-filled annulus to prevent flow diverting around the fixed choke. These modifications would reduce the potential crossflow rate to an acceptable level.
The OHGP was performed as originally planned. A wireline tool was run to inject an epoxy resin plug into the gravel and the fixed choke was then set at the same depth. The well was cleaned up as planned to the drilling rig, with both reservoir intervals observed to be producing.
The choke toolstring included an additional flow area that automatically opened after a pre-defined time delay. Simulations predicted the pressure differential at this time to be significantly lower. Reducing the choking effect in this way, once the risks from crossflow at the start of well life had been minimised, avoided hindering production in later well life.
The well has performed as expected with no indications of production impairment having occurred, despite the initial period of high differential pressure between the reservoir intervals.
This is believed to be the first injection of epoxy resin into a newly completed gravelpack. Coupled with the implementation of the two-sized choke it has been possible to manage a problematic reservoir pressure differential in a new well without resorting to costly and lengthy redesign of the completion.
A Knowledge-Based Artificial Intelligence Approach to Risk Management
Authors: Canon Javier , Broussard Theresa , Johnson Andrew , Singletary Will , Colmenares-Diaz Lolymar 
Published: September 2022

Abstract
This paper details experiences gained while developing a novel technology-driven approach to Risk Assessment methodologies, e.g., Process Hazard Analysis (PHA), Hazard Identification (HAZID) and Hazard Operability (HAZOP), in oil & gas. Emphasis has been placed on combining encoded human knowledge with Artificial Intelligence techniques, in a way which fosters safer designs and operations, while maintaining Subject Matter Experts (SMEs) at the center of decision making.
Encoding of human knowledge (e.g., Subject Matter Expertise, Industry best practices) in digital applications has traditionally been associated with creating static pieces of information, such as lessons learned documentation and validation activities for hazard analysis. New digital technologies, however, make it possible to create truly dynamic knowledge representations, which capture key concepts and their relationships, creating a new type of "source of truth." As a result, corporate and external knowledge can be made more readily accessible to engineers and operations personnel participating in decision making.
Digital corporate knowledge can also be supplemented with Artificial Intelligence (AI) techniques which can help uncover latent threats and better guide optimal decision making. This is particularly relevant in Workforce, Health & Safety (WH&S) and Process Safety contexts, where the impact of flawed or suboptimal decisions can lead to catastrophic consequences.
Practical examples from an oil & gas major show how the risk assessment domain can be represented in a computational knowledge graph, in a format which is comprehensible not only to software developers, but more importantly, to oil & gas SMEs. A presentation of different AI techniques overlaid on top of this computational knowledge graph, can also offer a glimpse of the possibilities of marrying SME expertise with emerging digital technologies.
Drilling Heat Maps for Active Temperature Management in Geothermal Wells
Authors: Khaled Mohamed Shafik , Chen Dongmei , Ashok Pradeepkumar , van Oort Eric 
Published: September 2022

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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.