bluuebunny/crossref_metadata_2025 huggingface dataset:
Solid-State Gyro Technology Allows Safe And Reliable Real-Time Remote Operations
Authors: Ledroz Adrián , Smart Barry , Maharaj Navin
Published: September 2021

There are several reasons for obtaining gyroscopic surveys in directional wells. A gyro measurement provides reliable data when magnetic measurements are affected by interference from nearby wells; it can significantly reduce the positional uncertainty and provides redundancy data and gross error checks on MWD surveys. However, the complexity and extent of the necessary testing and handling of the tools have prevented widespread adoption, and gyro services have remained limited to "must-have" scenarios. The benefits of solid-state technology and new developments in communication capabilities are gradually changing the way of thinking related to wellbore positioning.

The first gyro while drilling tools were introduced in the early 2000s and were based on spinning mass gyro technology. These gyros can be very accurate with low noise levels and drift; however, they are fragile, built with moving parts, and susceptible to calibration shifts. Extensive pre-job testing, validation during job execution and post-job analysis are required to obtain reliable directional survey data. Solid-state gyros have reached the same, or even better, levels of noise and drift without the fragility of their spinning mass counterpart.

With different degrees of complexity and coverage, remote operations have been used for many years in the oilfield. Still, the adoption of monitoring gyro services with no personnel at the rig-site has been minimal due to the described complexity of the system and the small volume of jobs that prevented investment and the development of the necessary processes. Solid-state gyro technology addresses these challenges

More than 30 gyro-while-drilling jobs have successfully run remotely. The changes in operational procedures forced by the Covid-19 pandemic accelerated the demand for uncrewed operations, and solid-state gyro technology has shown high reliability with zero non-productive time due to tool failures or shifts in the calibration. This new way of working also results in a significant reduction in the environmental impact of the operations as all travel related to personnel and equipment has been reduced and battery life extended by up to 10.

Several scenarios related to wellbore positioning and directional drilling greatly benefit by having a gyro in the BHA. The gyro technology and the workflow described in this paper show how this can be done reliably, maintaining the quality of the survey data and reducing the environmental impact.
Smart Lost Circulation Materials to Seal Large Fractures
Authors: Tabatabaei Maryam , Dahi Taleghani Arash
Published: September 2021

Lost circulation problems may result in a significant downtime, a considerable reduction of the rate of penetration, or even well control problems. Despite advances in manufacturing lost circulation materials (LCMs), some formations, like heavily fractured carbonates, have complete losses during drilling. We develop smart LCMs using shape memory polymers (SMPs), and program them thermo-mechanically to satisfy size limitations imposed by bottomhole assemblies (BHA). Elevated downhole temperatures act as an external trigger to recover the permanent shape of LCMs, which could expand ten times larger than the temporary (programmed) dimensions for deployment. Smart LCMs are a combination of various material categories such as granular, fibrous (one-dimensional or 1-D) and planar (two-dimensional or 2-D) configurations that resume to the original shape after exposure to high temperatures. The LCMs form different structures such as flatted pellet, disc-shaped, spider-shaped, and spindled, which, respectively, presents grains, 1-D fibers, 2-D stars, and 2-D lattices after recovery. A combination of the above categories attempt to build three-dimensional (3-D) plugging capabilities across various sized fractures.
Extending Production Life of Mature Fields in the North Sea with Multilateral Technology
Authors: Kelsey Matthew , Raaholt Magnus , Einervoll Olav , Nafikov Rustem , Amble Stian
Published: September 2021

Multilateral technology has for nearly three decades extended the production life of fields in the North Sea by delivering a higher recovery factor supported by the cumulative production of the multiple laterals. Additionally, operators continue to look at methods to reduce the environmental impact of drilling and intervention. Taking advantage of the latest multilateral technology can turn otherwise unviable reservoirs into economically sound targets by achieving a longer field life while minimizing construction costs, risk, and environmental impact.

This paper will focus on mature fields in the region that have used multilateral applications for wells that were reaching the end of their life and have been extended to further economic production.

This paper discusses challenges faced to provide a multilateral solution for drilling new lateral legs in existing wells where there is a lack of available slots to drill new wells. Additionally, discussion will cover completion designs that tie new laterals into existing production casing. The case study will include discussion of workover operations, isolation methods, and lateral creation systems.

The paper focuses on the challenges, solutions, and successful case study of a retrofit multilateral well constructed in the North Sea which extended production life in a mature field by using innovative multilateral re-entry methods. The paper also provides insight as to methodology for continually improving reliability of multilateral installations to maximize efficiencies.
Cognitive HSE Risk Prediction and Notification Tool Based on Natural Language Processing
Authors: Danabal Tharunya , Sarah John Neethi , Pramod Ghawade Abhijeet , Padharinath Ahire Pranjal
Published: September 2021

The focus of this work is on developing a cognitive tool that predicts the most frequent HSE hazards with the highest potential severity levels. The tool identifies these risks using a natural language processing algorithm on HSE leading and lagging indicator reports submitted to an oilfield services company’s global HSE reporting system. The purpose of the tool is to prioritize proactive actions and provide focus to raise workforce awareness.

A natural language processing algorithm was developed to identify priority HSE risks based on potential severity levels and frequency of occurrence. The algorithm uses vectorization, compression, and clustering methods to categorize the risks by potential severity and frequency using a formulated risk index methodology. In the pilot study, a user interface was developed to configure the frequency and the number of the prioritized HSE risks that are to be communicated from the tool to those employees who opted to receive the information in a given location.

From this pilot study using data reported in the company’s online HSE reporting system, the algorithm successfully identified five priority HSE risks across different hazard categories based on the risk index. Using a high volume of reporting data, the risk index factored multiple coefficients such as severity levels, frequency and cluster tightness to prioritize the HSE risks. The observations at each stage of the developed algorithm are as follows:In the data cleaning stage, all stop words (such as a, and, the) were removed, followed by tokenization to divide text in the HSE reports into tokens and remove punctuation.In the vectorization stage, many vectors were formed using the Term Frequency - Inverse Document Frequency (TF-IDF) method.In the compression stage, an autoencoder removed the noise from the input data.In the agglomerative clustering stage, HSE reports with similar words were grouped into clusters and the number of clusters generated per category were in the range of three to five.

The novelty of this approach is its ability to prioritize a location’s HSE risks using an algorithm containing natural language processing techniques. This cognitive tool treats reported HSE information as data to identify and flag priority HSE risks factoring in the frequency of similar reports and their associated severity levels. The proof of concept has demonstrated the potential ability of the tool. The next stage would be to test predictive capabilities for injury prevention.
Modeling of Compositional Grading in Heavy Oil Fields
Authors: Vinhal Andre , Azeem Jawad , Pedersen Karen
Published: September 2021

Field data for the compositional variation with depth in five petroleum reservoirs have been analyzed including one rich in asphaltenes with a very high compositional gradient. The data follows the well-known pattern with an increasing concentration of heavy components with depth. The observed compositional variation is higher than what could be explained by gravity segregation alone. An enthalpy term was added to take into account that the components have different preferences for residing at a higher or a lower temperature. It was found necessary to modify the enthalpy term to account for the impact of fluid viscosity and concentration of aromatic components on the relative rate at which smaller and larger molecules move in a fluid column. With this modification, a good match was seen of the compositional variation in the five reservoirs initially analyzed. The method was successfully tested on three other reservoirs, not part of the initial analysis, one of which had a fluid column of 970 m.
Recent Enhancements for Coiled Tubing Descaling Treatments in Middle East
Authors: Alduaij Ahmed. N. , Al-Bensaad Zakareya , Espinosa Mauricio , Ahmed Danish , Dehingia Madhurjya
Published: September 2021

Successful coiled tubing (CT) descaling interventions require control of several key aspects, including fluid leakoff into the formation, proper surface solids handling, and controlled hydrogen sulfide (H2S) release at the surface. Successful treatment control is achieved by monitoring the surface and downhole parameters. The recently introduced pressure and fluid management system, crosslinked foam-based fluid, and a fluid mixing system for CT descaling treatments pose challenges that require enhancements to these elements for successful treatment.

The pressure and fluid management system was enhanced to include a new high-rate mud/gas separator to 1) increase gas/fluid separation capacity and avoid foam flowing to flare, 2) rig up the flare line with inclination to allow all water to be drained and prevent formation gas flowing to flare lines, and 3) increase retention time for better foam breaking and material settling. A liquid flowmeter was also added to improve influx and leakoff control by monitoring the volume of liquid injected and matching the volume of liquid returned on surface in addition to the level gauges on the return tanks of the pressure and fluid management system. The foamed-based fluid breaking system and H2S presence in returns were mitigated by removing crosslinker and introducing an H2S scavenger on returns whereas foam breaking was enhanced by additional breaker injection points on returns. Fluid mixing capabilities were enhanced by the introduction of an on-the-fly continuous mixing system that sped up and simplified the mixing process.

The mud/gas separator efficiently separated the gas from liquid, leading the gas to be burnt at flare and the liquid to be processed in the pressure and fluid management system. It further helped in preventing the liquid flowing to flare, which lessened the risk of flare shutdown and H2S ventilation.

The on-the-fly continuous mixing system provided a faster and more-efficient mixing process as an alternate to batch mixing. These system-controlled metering, mixing, and monitoring capabilities significantly reduced the crew and equipment footprint, leading to minimizing the health, safety, and environment (HSE) concerns and cost savings.

The fluid flowmeter allowed efficient choke and bottom-hole pressure control. Fluid flowmeter readings helped in choke and bottom-hole pressure reading adjustments based on amount of fluids pumped and matching the same amount of fluids returned at the surface. It prevented the fluid leakoff into the formation or influx of gas into the wellbore.

Additionally, this new process created better control of downhole differential pressure during the scale cleanup and transportation. This project integrated different technologies and techniques that can be utilized for descaling treatment enhancements. The recent enhancements to the CT descaling operation resulted in greater efficiency, cost savings, reduced formation damage, and safe operations.
Offshore CRI Well Performance Diagnostics and Fractured Domain Mapping Using Injection Data Analytics and Hydraulic Fracturing Simulation, Verified Through 4D Seismic and Wireline Logging
Authors: Marketz Franz , Brown David , Alyabiev Roman , Khudorozhkov Pavel , Sychov Oleg
Published: September 2021

The cuttings re-injection (CRI) well in the Astokh area of Piltun-Astokhskoye field offshore Sakhalin Russia is one of the longest operating drilling waste disposal wells in the oil and gas industry worldwide. The Astokh area has been developed as a waterflood and is operated by Sakhalin Energy, a joint venture between Gazprom, Shell, Mitsui, and Mitsubishi. The Astokh CRI well has been utilized for waste injection for over 16 years. About 300,000 m3 of waste has been disposed into the main injection zone of the CRI well. Monitoring and modelling the CRI process to understand the evolution of the disposal domain is paramount for safeguarding further disposal operations.

The disposal domain can be described as a complex system of multiple hydraulic and natural fractures due to injection under fracturing conditions. CRI domain evaluation includes analysis of historical injection pressures to identify the reasons of continuous injection pressure increase with increasing cumulative waste volumes disposed, to confirm domain containment, and to predict remaining domain capacity. Transient pressure analysis has revealed that the fracture closure pressure, driven by pore pressure increase and the accumulation of injected solid-phase waste, is the key parameter affecting injection pressures. Injection intensity, periods of shut-in, large overflushes, and solids-free liquids injections with corresponding solids and stresses redistribution are the other factors that affecting the pressure trends. CRI domain mapping was carried out with history-matched time-lapse 3D hydraulic fracture models. Injection pressure history matching results reveal the fracture geometry evolution during well life. The distribution of the injected liquid phase in the sand layers was modeled with a 3D dynamic reservoir sector model, matched with injection pressures and with formation pressure data in two offset wells, located at a distance of 1 and 2 kilometers, respectively. A matched model was then used to assure fracture containment for future waste disposal and to estimate remaining domain capacity.

High-precision temperature and spectral noise logs were acquired in seawater injection and shut-in modes. The log-derived fracture height confirmed the domain size predicted by the matched model. 4D seismic data processing revealed that dimensions of Geomechanically Altered Rock Volume (GARV) were also in the same range as predicted by the model p.

The integration of CRI domain evaluation with matched 3D hydraulic fracture models, well logs and 4D seismic demonstrated that injection pressure data collected during every injection cycle may be sufficient to characterize disposal domain evolution and to estimate domain capacity.
Quantification of Temperature-Dependent Sorption Kinetics in Shale Gas Reservoirs: Experiment and Theory
Authors: Yang Yun , Liu Shimin
Published: September 2021

A critical component of natural gas in organic-rich shales is adsorbed gas within organic matter. Quantification of adsorbed gas is essential for reliable estimates of gas-in-place in shale reservoirs. However, conventional high-pressure adsorption measurements for coal on the volumetric method are prone to error when applied to characterize sorption kinetics in shale-gas systems due to limited adsorption capacity and finer pores of shale matrix. An innovated laboratory apparatus and measurement procedures have been developed for accurate determination of the relatively small amount of adsorbed gas in the Marcellus shale sample.

The custom-built volumetric apparatus is a differential unit composed of two identical single-sided units (one blank and one adsorption side) connected with a differential pressure transducer. The scale of the differential pressure transducer is ± 50 psi, a hundred-fold smaller than the absolute pressure transducer measuring to 5000 psi, leading to a significant increase in the accuracy of adsorption measurement. Methane adsorption isotherms on Marcellus shale are measured at 303, 313, 323 and 333 K with pressure up to 3000 psi. A fugacity-based Dubinin-Astakhov (D-A) isotherm is implemented to correct for the non-ideality and predict the temperature-dependence of supercritical gas sorption.

The Marcellus shale studied displays generally linear correlations between adsorption capacity and pressure over the range of temperature and pressure investigated, indicating the presence of a solute gas component. It is noted that the condensed phase gas storage exists as the adsorbed gas on shale surface and dissolved gas in kerogen, where the solute gas amount is proportional to the partial pressure of that gas above the solution. To our best understanding, it is the first time to observe the contribution of dissolved gas to total gas storage. With adsorption potential being modeled by a temperature dependence expression, the D-A isotherm can successfully describe supercritical gas sorption for shale at multiple temperatures. Adsorption capacity remarkably decreases with temperature attributed to the isosteric heat of adsorption. Lastly, the wide applicability of the proposed fugacity-based D-A model is also tested for literature adsorption data on Woodford, Barnett, and Devonian shale. Overall, the fugacity-based D-A isotherm provides precise representations of the temperature-dependent gas adsorption on shales investigated in this work. The application of the proposed adsorption model allows predicting adsorption data at multiple temperatures based on the adsorption data collected at a single temperature. This study lays the foundation for accurate evaluation of gas storage in shale.
Measurements During Drilling Through an Innovative Microchip Technology to Determine Accurate Wellbore Properties for Efficient Drilling Operations
Authors: Zhu Zuyang , Zhao Jinhai , Mulunjkar Amol , Rached Rached , Gramajo Eduardo , Li Fengbo , Wang Zhifa , Shi Zhaorui , Zhang Wei , Zhao Weishu
Published: September 2021

The measurement of the drilling parameters such as temperature and pressure helps mitigate drilling-related issues and optimize drilling operations on a cost-effective basis. Multiple technologies can measure these parameters; however, the current tools suffer from low bandwidth, associated high cost, and limited measurement locations near the drill bit.

This reduced accuracy and transmission rate while drilling can be improved using intelligent microchip tracers and micro-memory balls. These tools can measure the temperature and pressure across an entire wellbore. The proposed tracers include a microprocessor-based circuit board equipped with sensors, a communication antenna, and a rechargeable battery, all protected from the harsh downhole environment through a robust composite material.

The advanced microchip tracers and micro-memory ball technologies were tested in the field and provided innovative measurement platforms. The field tests were conducted in various environments, including oil and gas wells, deviated wells, multiple hole sizes, varied fluid densities, and different BHA (Bottom Hole Assembly) geometries. During the operation procedures, the tracers travel in the drilling strings through the drill bit and return to the surface across the annulus. The data is then exported from the tracers for a quasi-real-time analysis. The results showed high success rates, four out of six microchips were successfully retrieved, and the data was made available for immediate analysis.

This paper explains the challenges faced during the logging and interpretation of the data needed to define the wellbore characteristics for efficient drilling processes. The developed time-stepping algorithm correlates the measurement timestamp with the calculated depth. Lastly, the report summarizes the highlights of the tracers in terms of density, release mechanism, and collection method.
Stress Path Analysis of the Depleted Middle Miocene Clastic Reservoirs in the Badri Field, Gulf of Suez Rift Basin, Egypt
Authors: Radwan Ahmed E. , Sen Souvik
Published: September 2021

The purpose of this study is to evaluate the reservoir geomechanics and stress path values of the depleted Miocene sandstone reservoirs of the Badri field, Gulf of Suez Basin, in order to understand the production-induced normal faulting potential in these depleted reservoirs. We interpreted the magnitudes of pore pressure (PP), vertical stress (Sv), and minimum horizontal stress (Shmin) of the syn-rift and post-rift sedimentary sequences encountered in the studied field, as well as we validated the geomechanical characteristics with subsurface measurements (i.e. leak-off test (LOT), and modular dynamic tests) (MDT). Stress path (ΔPP/ΔShmin) was modeled considering a pore pressure-horizontal stress coupling in an uniaxial compaction environment. Due to prolonged production, The Middle Miocene Hammam Faraun (HF) and Kareem reservoirs have been depleted by 950-1000 PSI and 1070-1200 PSI, respectively, with current 0.27-0.30 PSI/feet PP gradients as interpreted from initial and latest downhole measurements. Following the poroelastic approach, reduction in Shmin is assessed and reservoir stress paths values of 0.54 and 0.59 are inferred in the HF and Kareem sandstones, respectively. As a result, the current rate of depletion for both Miocene reservoirs indicates that reservoir conditions are stable in terms of production-induced normal faulting. Although future production years should be paid more attention. Accelerated depletion rate could have compelled the reservoirs stress path values to the critical level, resulting in depletion-induced reservoir instability. The operator could benefit from stress path analysis in future planning of infill well drilling and production rate optimization without causing reservoir damage or instability.
The Experience of Drilling TAML-3 Well with Mutistage Fracturing on the Low Permeability Deposits of the West Siberia
Authors: Brednev Philipp , Elesin Mikhail , Berezovskiy Yuri , Metelkin Denis , Volkov Georgy , Firsin Maksim , Mukminov Iskander
Published: September 2021

This article deals with the issues related to development of petroleum resources of Western Siberia and looks at one of the most promising development targets – reservoirs of the Achimov Formation. In particular, it discusses geological features of the Achimov rocks, and the difficulties faced by oil companies in development of the Achimov reservoirs due to their low economic viability if traditional approaches to well construction are applied. To make development of such reservoirs economical, new and non-trivial solutions need to be looked for. One of the most promising of them is considered to be multi-hole wells the construction of which allows oil companies to improve the Capex to cumulative production ratio. At the pre-FEED stage the project, geological, hydrodynamic and geomechanical models of the reservoir were built, the most efficient borehole parameters and trajectories were defined, and the optimal hydraulic frac design, number of stages and parameters were selected.

The article describes specifics of the work carried out when preparing for pilot tests of the technology, such as:requirements for defining the well profile and selecting the optimal lifting capacity of the drilling rig,selection of a suitable complexity level for the double-hole well design among those considered which meets the drilling requirements,performance of bench tests to confirm operability of the TAML-3 equipment.

Further, the article describes results of drilling, completing and commissioning the first double-hole well at the Vyngayakhskoye field, discusses the issues faced when using the completion equipment at the TAML-3 level, and the lessons learned from this project. It also presents results of putting the double-hole well on-stream and compares its production characteristics with those of single-hole horizontal wells drilled within the same well cluster.

The experience gained has shown that building the discussed type of wells is technically feasible, and there is a wide potential for improving efficiency of this work through respective organizational and technical measures.

The conclusion to this article describes Gazprom Neft long-term plans to build several new wells of this design, and the technology development options such as increasing the length of horizontal segments for both holes and using high-rate multi-stage hydraulic fracturing.
Application of Multiple Diagnostic Plots to Identify End of Linear Flow in Unconventional Reservoirs
Authors: Pratikno Helmi , Lee W. John , Torres Cesario K.
Published: September 2021

This paper presents a method to identify switch time from end of linear flow (telf) to transition or boundary-dominated flow (BDF) by utilizing multiple diagnostic plots including a Modified Fetkovich type curve (Eleiott et al. 2019). In this study, we analyzed publicly available production data to analyze transient linear flow behavior and boundary-dominated flow from multiple unconventional reservoirs.

This method applies a log-log plot of rate versus time combined with a log-log plot of rate versus material balance time (MBT). In addition to log-log plots, a specialized plot of rate versus square root of time is used to confirm telf. A plot of MBT versus actual time, t, is provided to convert material balance time to actual time, and vice versa. The Modified Fetkovich type curve is used to estimate decline parameters and reservoir properties. Applications of this method using monthly production data from Bakken and Permian Shale areas are presented in this work.

Utilizing public data, our comprehensive review of approximately 800 multi-staged fractured horizontal wells (MFHW) from North American unconventional reservoirs found many of them exhibiting linear flow production characteristics. To identify end of linear flow, a log-log plot of rate versus time alone is not sufficient, especially when a well is not operated in a consistent manner. This paper shows using additional diagnostic plots such as rate versus MBT and specialized plots can assist interpreters to better identify end of linear flow. With the end of linear flow determined for these wells, the interpreter can use the telf to forecast future production and estimate reservoir properties using the modified type curve.

These diagnostic plots can be added to existing production analysis tools so that engineers can analyze changes in flow regimes in a timely manner, have better understanding of how to forecast their wells, and reduce the uncertainty in estimated ultimate recoveries related to decline parameters.
Experience of Using Continuous Production Surveillance Techniques in Multilateral Wells
Authors: Husein Nadir , Upadhye Vishwajit , Novikov Igor Leonidovich , Drobot Albina Viktorovna , Bolshakov Viacheslav Valeryevich , Buyanov Anton Vitalyevich , Doronin Vladimir Alekseevich
Published: September 2021

This paper deals with the case of using the production surveillance inflow tracer-based method in one of multi-lateral wells located in West Siberia.

Tracer systems were placed in the well during the well construction by horizontal side tracking, and multi-stage hydraulic fracturing (MSHF) was performed, with the parent borehole remaining in operation. This technology allows developing the reservoir drainage area with a lateral hole and bringing the oil reserves remaining in the parent borehole into production, which results in an increased well productivity and improved oil recovery rate.

Tracer systems are placed into the parent borehole within a downhole sub installed into the well completion. Polymer-coated proppant pack was injected during multi-stage hydraulic fracturing to deliver the tracers to the side track lateral.

Dynamic production profiling was done to aid into more efficient development of complex and heterogeneous reservoirs and improve of the productive reservoir sweep ratio during the construction of multilateral wells, which enabled us to address several key problems:

Providing tools for waterflood diagnostics in multilateral wells and finding an easy water shut- off method for a certain interval Assessing the efficiency of multi-stage hydraulic fracturing and elaborating the optimal treatment design Selecting the optimal mode of the multilateral well operation to prevent premature flooding in one or more laterals Evaluating whether well construction was performed efficiently, and a higher production was achieved by side tracking.

Currently, the proposed first-of-its-kind solution enables the operator to obtain a set of data that can help not only significantly improve the wells productivity and increase the oil recovery rate, but also lead to a considerable economic savings in capital expenditure.
Cost-Effective Chemical EOR for Heterogenous Carbonate Reservoirs Using a Ketone-Surfactant System
Authors: Alghunaim Etaf , Uzun Ozan , Kazemi Hossein , Sarg J. Frederick
Published: September 2021

The complexity, high cost, and potential environmental concerns of chemical enhanced oil recovery (EOR) methods have diminished their field applications considerably. However, considering the significant incremental oil recoveries that can be obtained from these methods encourage researchers to explore ways to reduce both complexity, cost, and environmental concerns of such systems. This is especially important in carbonate formations, where after waterflooding, much of the oil remains trapped in complex reservoir pores—especially if the reservoir contains an interconnected fracture network of flow channels within the bulk rock matrix.

In this paper, we present an experimental assessment of several simple chemical EOR waterflooding systems comprising of small concentrations of a low cost, low molecular weight ketone and a non-ionic surfactant in association with low-salinity brine. The experiments were conducted in carbonate cores from a Permian Basin San Andres Formation. Four different oil displacement scenarios were investigated using San Andres carbonate cores from the Central Vacuum Field in New Mexico. This included 1) low-salinity brine, 2) low-salinity brine with a surfactant, 3) low-salinity brine with a ketone, and 4) low-salinity brine with a combined ketone-surfactant system. Static imbibition experiments were conducted using a spontaneous imbibition apparatus in addition to the use of a high-speed centrifuge to saturate the cores to irreducible brine saturation.

Adding a 1% concentration of 3-pentanone and a 1% non-ionic surfactant to a low-salinity brine yielded oil recoveries of 44% from the 3-pentanone system, compared to 11.4% from low-salinity brine only. The oil recovery is enhanced by a single mechanism or synergy of several mechanisms that includes interfacial tension (IFT) reduction by surfactant, capillary imbibition, favorable wettability alteration by ketone, and osmotic low-salinity brine imbibition. The IFT decreased to 1.79 mN/m upon addition of non-ionic surfactant to low-salinity brine, and it reduced to 2.96 mN/m in a mixture of 3-pentanone and non-ionic surfactant in low-salinity brine. Furthermore, ketone improved the core wettability by reducing the contact angle to 43.9° from 50.7° in the low-salinity brine experiment. In addition, the low-salinity brine systems caused mineral dissolution, which created an alkali environment confirmed by an increase in the brine pH. We believe the increase in pH increased the hydrophilic character of the pores; thus, increasing oil recovery.
Relating Acoustic Anisotropy to Kerogen Content in Unconventional Formations - A Case Study in A Kerogen-Rich Unconventional Carbonate
Authors: Gordin Yair , Bradley Thomas , Rosenberg Yoav O. , Canning Anat , Hatzor Yossef H. , Vinegar Harold J.
Published: September 2021

The mechanical and petrophysical behavior of organic-rich carbonates (ORC) is affected significantly by burial diagenesis and the thermal maturation of their organic matter. Therefore, establishing Rock Physics (RP) relations and appropriate models can be valuable in delineating the spatial distribution of key rock properties such as the total organic carbon (TOC), porosity, water saturation, and thermal maturity in the petroleum system. These key rock properties are of most importance to evaluate during hydrocarbon exploration and production operations when establishing a detailed subsurface model is critical. High-resolution reservoir models are typically based on the inversion of seismic data to calculate the seismic layer properties such as P- and S-wave impedances (or velocities), density, Poisson's ratio, Vp/Vs ratio, etc. If velocity anisotropy data are also available, then another layer of data can be used as input for the subsurface model leading to a better understanding of the geological section. The challenge is to establish reliable geostatistical relations between these seismic layer measurements and petrophysical/geomechanical properties using well logs and laboratory measurements.

In this study, we developed RP models to predict the organic richness (TOC of 1-15 wt%), porosity (7-35 %), water saturation, and thermal maturity (Tmax of 420-435⁰C) of the organic-rich carbonate sections using well logs and laboratory core measurements derived from the Ness 5 well drilled in the Golan Basin (950-1350 m). The RP models are based primarily on the modified lower Hashin-Shtrikman bounds (MLHS) and Gassmann's fluid substitution equations. These organic-rich carbonate sections are unique in their relatively low burial diagenetic stage characterized by a wide range of porosity which decreases with depth, and thermal maturation which increases with depth (from immature up to the oil window). As confirmation of the method, the levels of organic content and maturity were confirmed using Rock-Eval pyrolysis data.

Following the RP analysis, horizontal (HTI) and vertical (VTI) S-wave velocity anisotropy were analyzed using cross-dipole shear well logs (based on Stoneley waves response). It was found that anisotropy, in addition to the RP analysis, can assist in delineating the organic-rich sections, microfractures, and changes in gas saturation due to thermal maturation. Specifically, increasing thermal maturation enhances VTI and azimuthal HTI S-wave velocity anisotropies, in the ductile and brittle sections, respectively. The observed relationships are quite robust based on the high-quality laboratory and log data. However, our conclusions may be limited to the early stages of maturation and burial diagenesis, as at higher maturation and diagenesis the changes in physical properties can vary significantly.
Novel Density-Based Autonomous Inflow Control Device Using Artificial Gravity
Authors: Greci Stephen , Fripp Michael , McChesney Ryan , El Mallawany Ibrahim
Published: September 2021

A new class of Autonomous Inflow Control Devices, AICDs, has been developed which balances production flow and restricts unwanted production fluids, even when there is no viscosity difference in the produced fluids. This novel AICD senses the density difference between oil and water and uses artificial gravity to amplify the buoyancy forces while eliminating the need for downhole orientation in the completion.

AICDs have effectively reduced water production and increased oil recovery since their introduction in the early 2010s. During initial production, AICDs balance the flow across the production zone. In later production, AICDs automatically restrict the rate from zones producing water. Commercially available AICDs primarily operate by sensing the viscosity difference between oil and water. In very-light oil reservoirs, such as in parts of the Middle East, there is no significant viscosity difference. Previous density-based AICDs have been rejected because buoyancy forces are often overwhelmed by fluid forces and because they needed to be oriented with respect to Earth's gravity.

Density-AICDs use floats that are buoyant in water and sink in oil to control fluid production. The key to the new density-AICD is that that the floats are housed in a spinning centrifugal rotor. This spinning density selector creates centripetal forces that multiply the buoyancy force thereby magnifying the difference between oil and water. The magnified buoyancy forces are stronger than fluid friction forces and are sufficient to overcome suction forces on the valve seats. The centripetal acceleration creates an artificial gravity that is much larger than Earth's gravity, eliminating the need to orient the density-AICD downhole. The density selector is spun by the production fluid so that larger centripetal forces are created in response to a larger drawdown. The result is a density-AICD that will operate in real-world conditions, especially in the light oil formations of the Middle East.

The performance of this novel density-AICD has been measured in flow loop testing and demonstrated in computer modeling. The flow loop testing achieved substantial water restriction and continued oil flow using oil and water with identical viscosities.
Modified Method of Characteristics for Generating EOR Oil Recovery Curves
Authors: Agger Christian , Sørensen Henrik
Published: September 2021

The paper describes a fast and approximate 1D simulation algorithm for calculating the percent recovery that can be obtained from an oil reservoir if gas injection is carried out at a pressure lower than the minimum miscibility pressure. The algorithm is based on the Method of Characteristics. While a conventional 1D reservoir simulation of a gas injection scenario may take minutes or even hours, the proposed algorithm allows a full evaluation of the recovery to be completed within seconds. To make the method numerically robust, a number of approximations were needed. The result is an extremely fast algorithm that not only provides a good estimate of the recovery obtained by gas injection, but also gives a good visualization of how the gas displaces the oil.
The Impact of Kerogen Structure on Shale Permeability: Coupled Molecular Diffusion and Geomechanical Behavior Study
Authors: Afagwu Clement Chekwube , Al-Afnan Saad Fahaid , Mahmoud Mohamed
Published: September 2021

The advancements in production technologies have unlocked tremendous reserves of natural gas in shale formations. The ability to describe shale matrix dynamics during the production span is, however, at infancy stages. The complex mineralogy and the multiscale nature of shales require transport models beyond the classical Darcian framework. Shales primarily consist of clays, quartz, calcite, and some fragments of organic matters known as kerogen. The latter can be envisioned as naturally occurring nanoporous media where diffusion is believed to be the predominant transport mechanism. Moreover, kerogen exhibits different geo-mechanical behavior than typical clastic sedimentary rocks. Hence, kerogen responds to changes in the stress field differently during the production span and ultimately influences the transport. It is our aim in this paper to delineate the transport and geo-mechanical aspects of kerogen through molecular-based assessments. Realistic kerogen structures at some ranges of density were recreated on a computational platform for thorough investigations. The structures were analyzed for porosity, pore size distribution, and mechanical properties such as bulk modulus, shear modulus, Young's modulus, and Poisson ratio. The adsorption alongside self-diffusion calculations were performed on the configurations. Moreover, the assessment of diffusivity was linked to pore compressibility to address the impact of effective stress changes on the transport throughout typical production span. An effective diffusion model for kerogen was proposed, validated with molecular simulation data in the literature, and compared with the MD diffusion data of this study. The results revealed critical dependency of pore size distribution, and porosity on the effective stress, which severely alters the diffusive permeability. This work provides a novel methodology for linking kerogen microscale intricacies to some fundamental transport and mechanical properties to better describe the transport of natural gas from kerogen.
First Complete Digital Drilling Package Deployment for Risks Reduction and Performance Optimization: Africa Offshore Case History
Authors: Ferrara Paolo , Mutidieri Luigi , Magni Gianluca , Farina Daniele , Dal Forno Luca , Ricci Maccarini Giorgio , Battaglia Francesco , Ricci Giovanni
Published: September 2021

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 four years, as part of its digital transformation process, Eni 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 a 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 drilling operations non-productive time (NPT) prediction, performance advanced analytics and real time simulations. This last simulation tool was deployed for the first time in late 2020 on some wells 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 with headquarter (HQ), geographical units and field locations, with the definition of a strong data management infrastructure. This paper describes Eni'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 Offshore field case history is 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 is highlighted.

Next development steps will target an even higher level of integration of all available digital tools to have a single diagnostic approach based on univocal dashboards and in-house data server infrastructures.
Fluid Identification Derived from Non-Electric Measurements and Reservoir Characterization of Tight Carbonate in Sichuan Basin, China
Authors: Zhao Zuo AN , Wang Yue , Lai Qiang , Li Kai Xuan , Zhao Xian Ran , Wu Jin Long , Zhao Hai Peng , Yu Dai Guo
Published: September 2021

Natural gas production in the Sichuan Basin reached 30 billion m3 in 2020, but the gap between this and the production goal of 50 billion m3 in 2025 requires further exploration. The complex mineralogy and low porosity in tight carbonate reservoirs lower the accuracy of formation water saturation calculation from Archie's equation, which brings uncertainties to the reservoir characterization. It is, therefore, necessary to incorporate other methods as supplements to methods based on resistivities.

This paper outlines a method that incorporates wireline induced gamma spectroscopy, nuclear magnetic resonance (NMR), array dielectric, and borehole images. Spectroscopy is not only utilized to estimate the mineralogy of the reservoir, but it also provides non-electric measurements, such as chlorine concentration and thermal neutron capture cross-section (sigma). The amount of chlorine in the formation is proportional to the water volume in the reservoir, thus formation water saturation. Sigma is also an indicator of the formation water saturation. It enables formation water saturation calculation without resistivities.

Case studies are presented from carbonate reservoirs in the Sichuan Basin, China. A robust and comprehensive petrophysical description of mineralogy, porosity, pore geometry, free fluid volume, rock type, and formation water saturation is presented. Calculation of formation water saturation from chlorine and sigma proves to be successful in both water-based mud and oil-based mud environments. The depth of investigation (DOI) of chlorine from spectroscopy is about 8 to 10 in. for 90% of the signal. The various DOI of different measurements must be considered when performing the fluid identification. Bound fluid saturation could reach more than 50% in tight carbonate reservoirs. Formation water saturation is not the only factor that determines the fluid type. Free fluid saturation from NMR must be incorporated. Finally, a robust methodology integrating formation water saturation derived from dielectric and spectroscopy, and free fluid saturation derived from NMR shows great advantage in fluid identification in tight carbonate reservoirs.

This paper discusses a novel combination of wireline logging tools for the fluid identification of tight carbonate reservoir in Sichuan Basin. It lowers the uncertainty in the estimation of formation water saturation when application of resistivities is limited in oil-based mud environments. The gas zones identified by the new method have promising gas productions. The workflow can also be applied to other tight carbonate plays in China.