bluuebunny/crossref_metadata_2025 huggingface dataset:
Characterization of a New Litho-Density Logging-While-Drilling Tool to Ensure High-Confidence Reservoir Data
Authors: Vogt Andreas , Haeussler Andre , Banzarov Bair V. , Ritzmann Nicklas
Published: October 2023

Nuclear logging-while-drilling (LWD) tools delivering gamma-gamma density, photoelectric factor (Pe) and neutron-porosity measurements are essential services for the oil and gas industry to calculate accurate asset NPV (Net Present Value). As a part of the triple-combo bottom-hole assembly, neutron and formation density measurements enable accurate quantification of porosity, hydrocarbons volume and type, and through 360° coverage density imaging, bed boundary and structural measurements, and real-time reservoir navigation (Ellis & Singer, 2007), (Wahl, Tittman, & Johnstone, 1964). One of the crucial steps in tool development is the precise characterization and correction of any wellbore induced effects, in order to ensure accurate and reliable true formation properties to be evaluated, leading to a high confidence in formation properties calculated from them.

In this paper we describe how stringent radiation-transport simulations of the instrument response are utilized during the characterization process for the case of a high-temperature 4.75-in combined neutron-porosity and litho-density tool, designed to be utilized for demanding rotary-steerable drilling applications. The tool covers application ranges of temperature up to 175°C, pressures of up to 30,000 psi and dogleg severities of 15°/100 ft during rotation and corrosion resistance in demanding oil and gas drilling applications (Reckmann, et al., 2022). The nuclear measurements are improved by integral stabilizers and fluid displacers. Moreover, the tool determines borehole size shape orientation using multi-axis acoustic azimuthal caliper coupled with an in-situ measurement of mud sound speed and mud density. All nuclear and acoustic measurements are implemented with digital data acquisition chains and correction algorithms utilizing model-based design.

While neutron-porosity tools are characterized by nuclear simulation techniques since several decades, gamma-gamma density logging-while drilling tools, typically employing a 137Cs logging source and two scintillation gamma-ray detectors, are often characterized experimentally in a formation laboratory. The caveat of this procedure is that only a limited variety of formations, tool standoffs and drilling fluids can be covered. Another approach is the application of nuclear Monte-Carlo simulations, either to aid an experimental characterization with additional datapoints, or to derive a complete characterization that is scaled to reality in a later experimental test.
Locating, Quantifying, and Remediating Downhole Sand Infiltration to Minimize Equipment Failures and Increase Oil Production: A Case Study in Kuwait
Authors: Elias M. , Tagarieva L. , Alaryan A. , Tirkey N. , Prosvirkin S. , Vishnu R.
Published: October 2023

Sand infiltration requires immediate action to avoid costly downhole and surface equipment erosion. Additionally, sand particles may reduce hydrocarbon production by blocking downhole fluid flow. This study demonstrates the advantage of integrating multiple reservoir monitoring logs to identify the sand contribution zones, quantify the sand production, and plan the well remediation work required, while minimizing operation downtime.

A focused logging program and analysis method was developed to identify the sand infiltration location. Integration of passive acoustic and array-based production logs acquired the critical data to find the sand infiltration zones. The passive acoustic tool captured the count of inflowing sand strikes on the tool body generating a definitive acoustic signature. The array production logging tools mapped the fluid rates, flow delays, and fluid transport in the well. Post-processing of the passive acoustic data counted the unique sand strike events resulting in a quantitative sand infiltration assessment for a high deviation well penetrating Burgan and Wara reservoirs.

Sand and hydrocarbon production occurred in the Burgan reservoir, while the Wara formation was initially not producing any type of fluids due to Burgan sand infiltration. Within the Burgan formation large quantities of sand were detected inside the wellbore and approximately 100 feet below the inflow location. While some sand particles circulate up-hole with the flow others settle on the bottom. Acoustic logging analysis indicated that sand infiltration was generated from the middle Burgan perforations between 5737 ft and 5742 ft. According to the production logging analysis, less than 250 STB/D Burgan oil production was only flowing from the upper-most perforations between 5714 ft and 5718 ft due to sand fill below. Remediation action focused on a cement squeeze in the middle Burgan to close the sand infiltration perforations then a subsequent re-perforation of the Wara formation to resume production in that section. The Wara formation was relogged after perforation confirming reduced sand infiltration and an oil gain of 1530 STB/D with 170 STB/D of water production. Therefore, the sand infiltration information resulted in improved remediation outcomes. The integrated measurements clearly established the impact of sand infiltration on fluid inflow and created a road map for future well monitoring improvements.

This case study illustrates the successful integration of passive acoustic and array-based production logging to detect the sand infiltration zones and the high value fluid inflow zones. Well remediation activities were further optimized, re-establishing oil flow of 1530 STB/D from a set of non-producing perforations of the Wara formation.
Impact of Pressure-Dependent Interfacial Tension and Contact Angle on Capillary Trapping and Storage of CO2 in Saline Aquifers
Authors: Ren Bo , Littlefield James , Jia Cunqi , Duncan Ian
Published: October 2023

CO2 capillary trapping increases the total amount of CO2 that can be effectively immobilized in storage aquifers. This trapping, manifesting itself as accumulated CO2 columns at a continuum scale, is because of capillary threshold effects that occur below low-permeability barriers. Considering that capillary pressure is dictated by heterogeneous pore throat size, the trapped CO2 column height and associated CO2 saturation will vary spatially within a storage aquifer. This variation will be influenced by two pressure-dependent interfacial parameters: CO2-brine interfacial tension and CO2-brine-rock contact angle. Our objective is to understand how the pressure-dependence of these two parameters affects the heterogeneity of capillarity-trapped CO2 at a continuum scale.

Our conceptual model is a one-dimensional two-zone system with the upper zone being a flow barrier (low permeability) and the lower zone being a flow path (high permeability). The inputs to this model include microfacies-dependent capillary pressure versus saturation curves and permeability values. The input capillary pressure curves were collected in literature that represents carbonate microfacies (dolomudstone, dolowackstone, dolopackstone, and dolograinstone) in a prevalent formation in the Permian Basin.

We then employed the Leverett j-function to scale the capillary pressure curve for the two zones that are assigned with the same or different microfacies. During scaling, we considered the influence of pressure on both the interfacial tension and contact angle of CO2/brine/dolomite systems. We varied the zone permeability contrast ratio from 2 to 50. We then assumed capillary-gravity equilibriums and calculated the CO2 saturation buildup corresponding to various trapped CO2 column heights. The CO2 saturation buildup is defined as the CO2 saturation in the lower layer minus that in the upper one.

We found that the saturation buildup can be doubled when varying pressure in a storage aquifer, after considering pressure-dependent interfacial tension and contact angles. Thus, assuming these two parameters to be constant across such aquifers would cause large errors in the quantification of capillary trapping of CO2. The whole study demonstrates the importance of considering pressure-dependent interfacial properties in predicting the vertical distribution of capillary-trapped CO2. It has important implications in developing a better understanding of leakage risks and consequent storage safety.
Shunted Gravel Pack Failures – And How to Prevent Them
Authors: Latini Carolina , Govinathan Kesavan , Wassouf Philip , Jain Samyak , Tibbles Raymond
Published: October 2023

The success of any gravel pack treatment implies effective gravel coverage of the screens. Shunt tubes are used in both open and cased hole completions to overcome some of the challenges present for conventional gravel placement techniques by allowing slurry to bypass any premature bridges and continue packing downstream. Shunted gravel packs are therefore viewed as the most forgiving gravel placement technique, which has generated a myth that the use of a shunt tubes "guarantees" a successful gravel pack. However, failures of shunted pack placement are being experienced, resulting in wells that are incompletely packed. A better understanding of the limitations of shunt tube systems and an appropriate engineering design can effectively reduce the risk of shunted gravel pack failures.

Case histories are used to present a variety of shunt tube gravel placement failures. Surface and bottom hole gauge data combined with an industry standard sand control simulation software has enabled more detailed evaluation and identification of the different failure mechanisms. These include incomplete packs due to shallow zone fracturing, the blockage of shunt entry due to fluid quality issues and shunts erosion failures, among others.

This paper consolidates the various shunted gravel pack failure mechanisms that have been experienced in field operations and makes recommendations on how improved treatment designs can prevent them.
Critical Evaluation of Chemical Additives in Reducing the Minimum Miscibility Pressure for Gas Injection Process
Authors: Qi Zhenbang , Jiang Li , Emakpor Maroghoke , Stewart Suzanne , Abbott Jonathan , Abedini Ali
Published: October 2023

It is highly desirable to achieve minimum miscibility pressure (MMP) between injection gas and reservoir crude oil phase under the reservoir pressure in the gas injection (Huff-n-Puff) process, despite the obvious challenges, in order to gain more productive sweep efficiency and hence higher oil recovery yield. Here, we report on the evaluation of the performance of five discrete chemical additives in lowering the MMP of a hydrocarbon gas mixture with a representative crude oil through utilization of a microfluidic MMP measurement device. In the current study, a microfluidic platform was developed to accurately measure the MMP of a hydrocarbon gas and crude oil system in the presence and absence of chemical additives at 77°F and 150 °F, respectively. The gas stream consists of 70 mol% methane and 30 mol% propane, representing a typical hydrocarbon gas used for gas injection operations. A group of selected chemical additives were individually premixed with the oil phase at 1 wt% loading prior to the microfluidic testing to quantify the reduction in the MMP. The highly sensitive fluorescent microscopy was also employed to provide real-time insight into the porescale of the oil displacement during the gas injection process. The MMP of the gas and oil system was measured to be 3060 Psia at 77 °F. All the chemical additives demonstrated an effective reduction in the MMP within in a range of 9–21% with one of the additives outperformed the best, lowering the MMP to 2410 Psia. The direct fluorescent optical access into the microfluidic porous structure, however, showed considerable deposition occurred during injection for some of these chemical additives, a potential concern for formation damage. The top two chemical additives were then tested at 150 °F and compared with the gas–oil MMP with no chemical additive (3785 Psia at 150 °F). The selected two chemical additives lowered the MMP to 3425 Psia (10% reduction) and 3495 Psia (8% reduction) with no depositions observed in the porous media. The use of selected chemical additives to lower the MMP can make a significant contribution to the gas injection EOR processes in depleted reservoirs that can in turn potentially improve the performance of the reservoir-scale productions. This work reveals critical insight in chemical additive selection, plus dosages, for effective MMP reduction. Although the extent of MMP reduction was decreased at higher temperature, 10% reduction is nevertheless remarkable, given its low dosage, and can be improved further by adjusting the chemical loadings for high pressure operations. The microfluidic MMP testing platform is advantageous over the conventional slim tube method in significantly shortened turnaround time and minimized fluid consumption.
Measurement of the Static Proppant-Settling Velocity in Fracturing Fluids Through Digital Image Analysis
Authors: Huang Jiangshui , Lin Lijun , Lin Genyao , Richardi Bryant , Liu Fuchen , Li Jianshen , Yang Zhenzhou
Published: October 2023

This paper presents a novel method for quantitatively measuring the static proppant-settling velocity in hydraulic fracturing fluids through digital image analysis. The method developed is reliable and efficient for measuring the static proppant settling velocity (Sv) when there is no clear settling interface, which is useful for comparing the proppant carrying capability of different friction reducers (FRs), optimizing the concentration of friction reducers in the fracturing fluids for field operations, and improving the proppant carrying capability of friction reducers through the synthesis process.

The experimental procedure involves pouring a fracturing fluid with proppants into a transparent glass cylinder, taking images of the proppants settling using a camera, transferring the images into a computer, and analyzing the images using macro programs prepared to measure the static proppant settling velocity. The settling velocity is determined by measuring the position (height) change of a proppant concentration selected with time, which is realized through using image saturation to determine the position of the proppant concentration in the image analysis. The results obtained from this method show that the proppant size, friction reducer concentration, salinity of the friction reducer fracturing fluids, and friction reducer molecule weight and chemical structure have an impact on the static proppant settling velocity. Also, the method developed in this study can be helpful for selecting proper fracturing fluids for field applications and the optimization of friction reducers in the synthesis process through quantitatively measuring the settling velocity.

To the best of our knowledge, except for determining the settling velocity of a single particle in the fluids, this is the first study to quantitatively measure the static proppant-settling velocity in fracturing fluids through digital image analysis. The method developed offers several benefits including the ability to measure the settling velocity in real-time, low cost, and ease of implementation even when there is no clear settling interface. The results obtained from this method provide valuable insights into the transport behavior of proppants in fracturing fluids, enabling better design of hydraulic fracturing treatments to improve the recovery of oil and gas.
Revisiting Time-Rate-Pressure Production Analysis — Where Are We Almost 40 Years Later?
Authors: Blasingame T. A.
Published: October 2023

In the mid-1980s "time-rate-pressure" production analysis was proposed by this author to estimate reservoir properties, as well as in-situ volumes and EUR. This approach was primarily applied to conventional and tight reservoirs using "material balance decline curves" in the early 1990s and became known as "Well Performance Analysis" (WPA) before being rebranded by a vendor as "Rate Transient Analysis" (RTA) in the early 2000's. This analysis has been extended beyond fixed models (e.g., type curves for an unfractured or fractured well in a simple closed reservoir (e.g., a circle)) into analytical models for almost any case, as well as using numerical models for virtually any well reservoir configuration and complex multiphase fluid flow.

The "RTA" methodology has become a mainstay of modern reservoir engineering, but deserves a "look-back" and a "look-forward" in terms of where we can best utilize new modelling approaches (physical and data-defined models) to improve diagnostics and analyses. The primary goal of this work is to emphasize to both the casual and the experienced user that by whatever name we call it — Well Performance Analysis (WPA), Production Analysis (PA), or Rate Transient Analysis (RTA) — the purpose of these methodologies is to provide a diagnostically-driven analysis and interpretation of time-rate-pressure (TPR) data. WPA/PA/RTA are not just data fitting exercises, nor are they limited to simplified analyses (e.g., some sort of straight-line plots), these are fully integrated data diagnostic and analysis tools that warrant care and attention.

The present push to provide automated/augmented analyses is actually a noble (and predictable) outcome of the methodologies developed in the 1980s to provide estimates of reservoir properties from data that were not being used for that purpose, but as we develop more comprehensive (and more complex) analyses for TPR data, we must acknowledge that these data are inherently affected by operational aspects as well as measurement capabilities. In short, these are just data, and we need to stay focused on the diagnostic value of the data before attempting any analyses and interpretations — no matter how simple or complex those analyses and interpretations may be.
Interfacial Dilational Rheology Between Nitrogen and Aqueous Surfactant Solutions: Implications for Foam-Assisted EOR
Authors: Pan Ziqing , Trusler J. P. Martin , Zhang Kaiqiang
Published: October 2023

Foam-assisted EOR is a promising technique to meet the ever-growing global energy demand. However, foam is thermodynamically unstable because of large gas-liquid interface. The stability of foam depends largely upon interfacial rheological properties, which represent the resistance capability to disturbance. Most previous studies address limited pressure ranges, not revealing the behavior under subsurface conditions. To fill this gap, we measured the interfacial dilational viscoelasticity of (N2 + SDS (aq)) at various pressures in a high-temperature high-pressure view cell by using the oscillating-drop-profile method. The interfacial elastic and viscous moduli were studied at pressures from ambient pressure up to 26.7 MPa, temperatures of 298 K and 348 K, SDS concentrations below the CMC (0.05 mass% and 0.15 mass%) and above the CMC (0.50 mass%) and oscillating frequencies of 0.125 Hz and 0.0625 Hz, which may correspond to the low-frequency fluctuation expected during the reservoir fluids flow in porous media. The effects of pressure, temperature, SDS concentration and oscillating frequency were examined. Both elastic and viscous moduli decreased with increasing pressure, indicating weaker resistance capability to external disturbance under high-pressure conditions. At concentrations below the CMC, elastic modulus decreased, and viscous modulus increased with increasing temperature, while at concentrations above the CMC, both moduli decreased with increasing temperature. Surfactant solutions with higher concentrations had larger dilational viscoelasticity. However, once the CMC was reached and surfactant micelles were formed in the solution, a significant drop in the interfacial dilational modulus was observed. At concentrations below the CMC, both moduli increased with increasing oscillating frequency, while at concentrations above the CMC, the effect of frequency was insignificant. The expansion and compression of pendant drop during interfacial dilational modulus measurement is closely analogous to foam flow through the heterogeneous porous media. The foam interfacial dilational properties under a variety of pressure, temperature, composition, and oscillating conditions were systematically studied for the first time. The results obtained can help to advance understanding of foams stability, enhance the design of surfactant solutions and provide guide for the implementation of foam-assisted EOR.
CO2 Foam Flow Dynamics at Reservoir Conditions
Authors: Alcorn Z. P. , Halsøy H. , Sæle A. , Brattekås B. , Ellingsen A. , Graue A.
Published: October 2023

Foam is a promising technique to reduce CO2 mobility and mitigate the impacts of reservoir heterogeneity in CO2 enhanced oil recovery (EOR) and CO2 storage processes. However, the success of foam applications depends on maintaining adequate strength at reservoir conditions. Foam can breakdown in the reservoir due to surfactant adsorption, the presence of oil, and at elevated temperatures and salinities. Therefore, foam formulations must be screened to perform optimally at reservoir-specific conditions. This work presents steady- and unsteady-state supercritical CO2 foam corefloods evaluating the effects of foam quality, injection velocity, surfactant type and concentration on foam generation and strength at reservoir conditions. We also aim to reveal real-time foam displacement mechanisms with combined positron emission tomography (PET) and computed X-ray tomography (CT), high-resolution in-situ imaging technologies.

Foam quality scans with a commercially available water-soluble nonionic 0.1wt.% foaming solution indicated optimal foam qualities of 80% at 180 bar (2610 psia) and temperatures of 40°C (104°F) and 60°C (140°F). Foam rate scans showed shear-thinning foam rheology at both temperatures with a more rapid reduction in apparent viscosity with increasing injection velocity at 60°C. Unsteady-state single-cycle surfactant-alternating-gas (SAG) corefloods using different surfactant types (anionic and nonionic) at variable concentrations (0.35 wt.% and 0.50 wt.%) revealed that the foam strength was not dependent on surfactant concentration for the nonionic surfactant. However, the strength of foams stabilized by the anionic surfactant were sensitive to surfactant concentration, where the higher concentration generated a stronger foam. PET/CT images acquired during single-cycle SAG and WAG corefloods revealed real-time displacement mechanisms and saturation development during dense phase CO2 foam flow at reservoir pressure. The dynamic PET/CT images confirmed foam generation and showed that the foam displacement front was more stable and piston-like, resulting in additional fluid production, compared to experiments without foam.
Contractual Solutions to Barriers of Technology Transfer in the Upstream Contracts
Authors: Fathalizadeh Ali. , Belhaj Hadi
Published: October 2023

For Oil and gas producing countries it is important to transfer the advanced technologies used in upstream segments from E&Ps to NOCs and local companies. However, in upstream contracts, a large number of technology transfer agreements have failed to reach their initial intended goals. Therefore, the primary objective of this study is to examine barriers to technology transfer in upstream contracts and provide better contractual solutions. Library documents, previous studies, and semi-structured interviews have been used as research tools for this investigation. The statistical population of the research includes oil companies’ experts, high rank managers, engineers and project managers. Data analyses conducted using three stages of open-centered and selective coding, as well as the review of previous studies. The result shows that the four categories "lack of international communication", "lack of proper financing of projects", "lack of technology management knowledge", "inappropriate methods of technology transfer" are causal conditions stand as barriers to technology transfers. The results also showed that in order to tackle current obstacles of technology transfer in the upstream domain, infrastructures such as the research and technology centers, the role of technology transfer in the upstream contracts, relationship between educational and research centers with oil companies and contractors, and the bonuses in contracts regarding technology transfer should be strengthened and highlighted. In short, the contribution of this effort is twofold; first is to explore and find the impediments in technology transfer in the upstream contracts, and the second is to provide proper solutions for the upstream contracts to avoid or reduce the effects of these challenges.
Application of Artificial Intelligence (AI) Based Algorithm to Predict Contamination During Formation Fluid Sampling
Authors: Hunnur A. T. , Smith S. S. , Hall E.
Published: October 2023

Reservoir fluid sampling using the wireline or LWD tools has long had a difficult time predicting the filtrate contamination flowing through the tool. When the conventional curve fitting method was developed, changes in measured dynamic fluid data were thought to be best explained by fitting the entire data to a power law equation. Results from simulation study shows that the complete change cannot be explained by a single exponential fit, especially the later time data which is most important for predicting contamination. Thus, the conventional method requires a selection of data just during the later time to give better results. The results are thus extremely dependent on the user and the data used to create the fit.

A novel method was developed which uses an artificial intelligence (AI) based algorithm which was created using an extensive database of over 15,500 numerical simulations based on the fluid flow dynamic and accounting for most of the varying reservoir conditions for contamination prediction. Eight different models were developed and tested to provide not just accuracy of the results but also keeping in mind that this is a real-time decision-making tool, the time and computing power needed as well were considered.

Multiple sets of fluid sampling data from wireline and LWD tools were run through the contamination prediction algorithm in this study. Each dataset had multiple sensor responses and for each set of results at least 3 sensor responses were selected to be run through the conventional as well as the new algorithm. These results were then compared to lab determined contamination values to determine the error from each method.

Based on results from the multiple sets, this technique provides good predictions on the level of contamination not only in the conventional probes for which it was designed but also for focused sampling and sampling in LWD environments. This contamination prediction algorithm removes this user ambiguity and gives consistent and reproducible results.
Modeling of Gas-Liquid Anomalous Diffusion in Undersaturated and Saturated Unconventional Reservoirs and its Effect on Pressure and Rate Transient Responses
Authors: Yildirim G. , Ozkan E. , Artus V.
Published: October 2023

This study presents a one-dimensional numerical model for anomalous diffusion of three-phase, oil-water-gas, flow in a fractured, nanoporous medium. The focus is to address the current knowledge gap regarding gas-liquid anomalous diffusion in saturated and undersaturated unconventional reservoirs. To account for multiphase flow, we extend a modified flux law for anomalous diffusion using the relative permeability and capillary pressure formalisms. Caputo's representation is used to express time- and space-fractional derivatives with Murio's fractional finite difference approximation. A fully implicit computational scheme that incorporates Newton's iteration is employed for the treatment of non-linear terms. The proposed computational scheme should enable extension of anomalous diffusion concept to more realistic multiphase fluid compositions encountered in unconventional reservoirs. For illustration, we consider flow toward a constant-pressure vertical fracture along a horizontal well with one-fourth of the surrounding stimulated reservoir volume. The study showcases the production, pressure, and saturation behaviors resulting from super-diffusion phenomena caused by the presence of natural or induced fractures within the stimulated reservoir volume. It is shown that the effects of anomalous diffusion become more prominent in the presence of the gas phase. Super-diffusion accelerates production and enhances the efficiency of reservoir depletion. The results emphasize the importance of considering anomalous diffusion in modeling the flow and predicting the performance of a gas-liquid system in an unconventional reservoir.
First Challenging Geothermal Well for Carbon Neutral Campus
Authors: Gustafson O. , Bezner W. , Ibrahim A. Salaheldin , Jafri A. , Barton L. , Reyes A. , Poroli M. , De La Parra A. Cortes
Published: October 2023

Cornell University is exploring the direct use of geothermal energy as a sustainable energy source to heat its Ithaca campus. The Earth Source Heat (ESH) project is an essential component of Cornell University's solutions to achieve carbon neutrality by 2035.

The project's first phase included drilling a 3-kilometer-deep exploration well to collect subsurface data from the deep sedimentary and crystalline basement rock formations. These data will inform the design and specifications for creating an "enhanced geothermal system" comprised of a network of open fractures that will serve as a heat reservoir for a demonstration well pair, injecting cool water and producing hot water to heat Cornell University's campus in the cold New York winter.

The engineering design of the project's first phase involved many challenges, from selecting optimum casing seats with minimum offset well information to overcoming potential subsurface risks related to drilling through a thick salt formation and highly unstable shales. Which were taken into consideration during the design phase.

The Engineering team, along with Cornell University's scientists, collaborated in the design phase and utilized innovative engineering solutions on a cloud-based platform for optimizing the well design. This design was coupled with a dedicated mechanical earth model study for the well to reduce the mud window uncertainty.

Each component of the well design was analyzed to ensure optimum design practices and safe operational limits based on an extensive risk assessment of all potential hazards along with prevention and mitigation plans.

For the execution phase, the engineering team utilized a state-of-the-art digital solution for drilling automation and optimization, where drilling dysfunctions such as shock and vibrations and variable formation hardness were displayed in a real-time advisory mode for drilling performance optimization.

The well construction phase was a continuous, agile process between the well engineering team and the University's scientists to achieve the project's challenging goals.
PDC Bit Selection Guidelines Based on Physics and Lessons Learned
Authors: Pastusek Paul E. , Barajas Pablo E. , Payette Greg , Sowers Steve
Published: October 2023

The objective of bit selection is to drill a round, ledge free hole, without patterns, with minimum vibration, minimum dog leg severity, that reaches all directional and geologic targets. And to do this in one run per section where rate of penetration (ROP) is unconstrained by the bit, and it remains vibration free in control drilling situations. The objective of this paper is to share these guidelines, accumulated from forensics investigations and sometimes costly lessons learned over the past decade.

Bit selection can be based on; offset runs, forensics analysis, and first principles. Offsets capture past learnings. Forensics analysis is applied to past and current wells, and it is the foundation for continuous improvement. First principles, based on independent thinking, are required to challenge the status quo.

These guidelines are the distillation of forensics observations, offset analysis, and physics modeling. It is important to note that these are guidelines, not rigid standards. They are presented in their current state, to be challenged, tested, and revised as new ideas and technology are developed. They are not a substitute for thinking.

The guidelines start with a description of the formation properties, drilling environment, and other requirements such as directional objectives, drill out considerations, and required life. They cover how to suppress bit whirl, stick slip, and borehole patterns; improve structural integrity, allow for predictable build rates, reduce gauge trimmer damage, and design for appropriate aggressiveness, ribbon flow, bit stability and life. These functions and dysfunctions are paired with design features such as depth of cut elements; gauge pad length and relief; cutter materials, size, and geometry; back rake; blade count and standoff; hydraulic design; and blade strength. The guidelines document specific and general lessons learned and why each rule was established. They help drilling engineers and service companies determine which design features are most important for a given application. Applying them across teams and applications highlights design elements that may be of concern and has helped avoid repeat failures. The first failure is for learning, the second failure is a failure to learn.

Design features have been matched up with associated critical performance limiters. This transparency in thinking allows the assumptions to be questioned, provides knowledge of which rules apply in each application, and provides background to evaluate when new technology may help. Some of the hard problems that remain are; consistent forensics analysis, chip flow modeling, cutter stress verses rock strength and penetration per revolution, understanding and suppressing high frequency torsional oscillation, and improvement and expansion of in-bit instrumentation.
A Two-Phase Type-Curve Method with Fracture Damage Effects for Hydraulically Fractured Reservoirs
Authors: Zhang Fengyuan , Pan Yang , Rui Zhenhua , Emami-Meybodi Hamid , Yang Chia-Hsin , Wang Ruiqi , Zhang Wei
Published: October 2023

Type-curve analysis on flowback and production data is a powerful tool in characterizing hydraulic fractures (HF) and reservoir properties. In order to evaluate HF characteristics and their dynamics for multi-fractured horizontal wells (MFHWs) in hydrocarbon reservoirs, we provide a novel type-curve method and an iterative workflow. The type curve incorporates the fracture damage effect, which is characterized by choked-fracture skin factor, into the two-phase flow in HF and matrix domains. The type-curve method can be applied to inversely estimate choked-fracture skin factor, fracture pore-volume, fracture premeability, and fracture permeability modulus through the analysis of two-phase production data. By introducing the new dimensionless parameters, the non-uniqueness problem of the proposed semianalytical method is significantly reduced by incorporating the complexity of fracture dynamics into one set of curves. The proposed type curve's accuracy is examined by numerical simulations of a shale gas and shale oil reservoir. The validation results demonstrate the good match of analytical type curves and numerical data plots and confirms the accuracy of the proposed approach in estimating the static and dynamic fracture properties. The flexibility and robustness of the proposed method are illustrated using the field example from a shale oil MFHW. The interpreted results from the flowback analysis of the field example offers a quantitative insight of fracture properties and dynamics.
First Complete Digital Drilling Package Deployment For Risks Reduction And Performance Optimization: Africa Case History
Authors: Ferrara Paolo , Dal Forno Luca , Magni Gianluca , Santoro Domenico , Sanasi Carla , Mutidieri Luigi
Published: October 2023

In an era of reduced profit margin and high market uncertainty, more than ever it is important to meet operational excellence as a key factor for business sustainability. This is common to most technical applications, but it is particularly true for the drilling operations, where considerable investments and associated risks are involved. During last years, as part of its digital transformation process, the operator has equipped itself with several digital tools for the diagnosis and the monitoring of drilling and completion operations. Goals and reached benefits can be summarized in risk reduction, operational efficiency and performance optimization.

Based on an already wide case history started in 2019, a Digital Drilling Package was developed for operations support, from the design to the construction phase. Three main tools are now available to be applied to the most complex wells, either stand-alone or in parallel, covering Non-Productive Time (NPT) prediction, performance advanced analytics and drilling operations real time simulations. This last simulation tool has been deployed for the first time in 2021 on some wells in Africa and is now being included in the engineering and operation workflows.

Attacking operational NPT and invisible lost time with the aim to increase safety and to reach the technical limit is not only a matter of processing tools. It requires a deep integration among headquarters, geographical units and field locations, with the definition of a strong data management infrastructure. This paper describes operator’s experience both on-site and in office, showing how the portability and integration of big data systems, suitable data lake architectures and human factor synergies can create effectiveness at all levels. An Africa field case history will be reported to show how predictive and data analytics modelling and tools interact. In addition, the way in which these tools have been managed to support optimum decision-making processes will be also highlighted.

Next development steps will target an even higher level of integration of all available digital tools in order to have a single diagnostic approach based on univocal dashboards and in-house data server infrastructures.
Five Keys to Shortening the Innovation Cycle - A Case Study from Cancer Genomic Sequencing to Unconventional Reservoir
Authors: Yamali Nampetch , Emery Daniel
Published: October 2023

Due to society’s increasing interest in the impacts of climate change, a new sense of urgency is driving the demand for shorter, successful innovation cycles with increased need for greater technology impact and global scalability. To make this happen, a comprehensive strategy to manage ambiguity, potentially competitive technical environments, and consequential communication hurdles from cross-industry backgrounds are required.

For over two decades Chevron Technology Ventures has been hard at work on accelerating our innovation cycle through a specific leadership approach. We have observed five connected challenges frequently encountered when taking an idea from inception to full-scale adoption. We will present this method through looking at one of our projects, adapting genomic sequencing from medical cancer research for drainage heights and well-to-well communication for unconventional reservoirs.

This case study will help diverse technical leaders gain direct insight into the 5 keystrategies which we’ve foundshorten the innovation cycle.

Proven strategies Include: Forming a dedicated team incorporating an energized champion, along with both technical experts, as well as resources from the business unit targeted for initial deployment.Managing technology ambiguity with key stakeholdersMitigating the potential competitiveness that can stifle innovation and progressBridging communication challenges due to diverse technical backgroundsGrowing healthy relationships and promoting a one team culture

This is the firsttime that thiscutting-edge research from the medical industry has been adopted and delivered results in an oil field application. The potential benefits of scaling this technology can aid in optimal unconventional resource development. The strategies presented can help technical leaders and practitioners champion innovation within their organizations.
Predictive Power of Theoretical Adsorption Models for Hydrogen/Coal System: Implications for Hydrogen Geostorage
Authors: Raza Arshad , Mahmoud Mohamed , Arif Muhammad , Glatz Guenther , Alafnan Saad , Hassan Amjed
Published: October 2023

Experimental methods are commonly used to determine the ability of a rock to adsorb gas by means of isothermal adsorption experiments. Adsorption isotherms quantitatively describe the relationship between the amount of gas adsorbed onto a rock surface and associated equilibrium conditions. It is imperative to study the adsorption of hydrogen (H2) on coal for various pressure and temperature conditions to de-risk subsurface hydrogen storage. This study aims to provide a theoretical analysis of the adsorption behavior of hydrogen onto coal, based on representative models in order to assess the suitability of theoretical isotherms. Specifically, we employ a modeling strategy to quantify the applicability of the Langmuir, Tóth, and BET framework for a hydrogen/coal system based on literature data. The novelty of the work derives from that fact that the predictive power of well-known gas adsorption isotherms for experimental H2-coal adsorption data has not been studied yet. To assess storage security and economics via modeling, in situ hydrogen storage requires suitable isotherms. Here we consider data for pressures up to 102 bar and temperature in between 303-333 K. Findings suggest that in a RMSE-sense, adsorption isotherms may be ranked as Langmuir>Tóth>BET for the coals studied. The results of this study contribute to an improved understanding of the predictive powers of adsorption isotherms and provide valuable numerical input variables for modeling coal seam formations at the reservoir scale, facilitating history matching and enabling predictions of formation behavior.
Leveraging Autonomous Moon-Based Rovers for Multiple, Near-Term Applications in Field Operations
Authors: Cyrus Justin , Wagner Van , Kenrick Joseph
Published: October 2023

Lunar Outpost is an advanced technology startup specializing in the development of sophisticated robotic platforms for both space and terrestrial applications. Recognizing the need for automated site inspection and observation in industries such as upstream oil and gas, Lunar Outpost has developed the ‘Hound’ rover—a terrestrial robot designed for monitoring and gathering operational measurements of various field assets, including wellheads, flowlines, separators, tanks, pump stations, and pipelines.

This paper describes the research and development efforts behind the Hound rover, focusing on the discovery of end-user requirements to effectively address industry pain points. The development process involved extensive stakeholder engagement, allowing for the identification of critical needs and challenges faced by the industry. The resulting platform was designed to meet these requirements and underwent rigorous verification and validation processes to ensure its capability and effectiveness.

The research findings informed key decisions regarding prototyping, design, and the implementation of various features and capabilities. Each of these elements underwent thorough verification or validation, confirming their alignment with the original needs expressed by industry stakeholders. By addressing these needs, the Hound rover offers a comprehensive solution for autonomous monitoring and observation in the oil and gas industry.

Furthermore, a comparative analysis was conducted to assess the advantages and disadvantages of implementing the Hound rover compared to existing operational procedures and other robotic platforms in use today. This analysis highlights the cost-effectiveness, improved visit frequency, enhanced observation capabilities, and strengthened regulatory compliance offered by the Hound rover. By replacing traditional site visits with autonomous systems, operators can achieve significant cost reductions, increase operational efficiency, and ensure compliance with safety and environmental regulations.

The development of the Hound rover represents a transformative opportunity for the oil and gas industry. It addresses critical pain points, improves operational efficiency, and enhances worker safety. The findings and insights from this research have broader implications for the use of autonomous robotic platforms in various industries. Continued research and development efforts can further optimize these platforms and expand their applications, driving advancements in the field of robotics and automation.
Unlocking Stranded Marginal Gas Fields in Malaysia with Low CAPEX Approach
Authors: How L. L. , Farina N. Norintan , Azmukiff K. , Osman Z. , Chang Y. S. , Shahardin S. , Azhar S. Fairudul
Published: October 2023

Vestigo Petroleum Sdn. Bhd. (VPSB) has been awarded the right to develop and produce gas fields via a Petroleum Sharing Contract in offshore Peninsular Malaysia. The contract area consists of undeveloped Field T, Field I and Field B integrated late life asset. The undeveloped Field T and Field I marginal gas fields lie within 60km from existing Field B production hub. The production comes from gas dominant Field B, a producing field that is in decline and of which VPSB assumed operatorship in 2017. The immediate business driver is rapid monetization of the asset via tapping into nearby potential marginal gas fields. To enable this, low CAPEX and rapid development with fast investment return are required.

Among the undeveloped gas fields, Field T was identified to anchor the development as it carries significant discovered gas volume. However, majority of the gas volume comes with H2S, and CO2 content which is beyond sales gas specification. Therefore, inter and intra fields blending were considered. Owing to the complexity of Field T that is dependent on other fields to provide blending medium, it is crucial to outline sequencing, timing of the other gas fields appraisal and development to optimize the development.

To start with, Field T development from a wellhead platform tied back to existing VPSB processing facilities via a 60km long pipeline was the identified concept. A standardized wellhead platform, batch drilling and fit purpose well design in conjunction with application of Zap-Lok, mechanical connection technology in pipeline and sharing of operation cost with existing facilities led to cost effective development. This is the first application of Zap-Lok technology offshore Malaysia. The deployment of VPSB standard wellhead platform enabled rapid field development, with platform installed in less than eleven (11) months after project approval. All five (5) development wells were batch drilled to penetrate multiple stacked reservoirs and completed monobore to accommodate selective bottom-up perforation. These monobore wells either commingled minor reservoirs within similar pressure regime or selectively perforated at major reservoirs only for production to meet committed gas rate. This also ensures not to jeopardize major reservoirs gas reserves and reservoir management plan.

Future developments are being planned to duplicate the success of Field T development to other identified marginal fields to drive cost reductions over time with higher efficiency.