bluuebunny/crossref_metadata_2025 huggingface dataset:
Low Resistivity Reservoir Identification of Gumai Formation Using Weighted Scoring Method in West Benakat, South Sumatra Basin, Indonesia
Authors: Permana Aziz , Naiola Mateos , Siregar Daniel , Damuar Syaiful , Suseno Pambudi , Parsaulian Sakti , Siki Dirsya , Barustan Ilham
Published: September 2022

The mature oil field of West Benakat is located in the South Sumatra Basin, one of the most hydrocarbon prolific Indonesian tertiary back-arc basins in Indonesia. Since its discovery in 1933, West Benakat Field has been operating and producing oil for nearly nine decades from Talang Akar Formation (TAF) as the main sand reservoir target with good porosity and permeability. Recently, Talang Akar reservoirs have been depleted through massive development programs, whereas more than 290 wells have been drilled for exploration, production, and injection wells. Decreasing oil production pushes the company's need for an alternative method that can increase oil production through subsurface evaluation in West Benakat Field to find the upside potential besides Talang Akar. One of the best alternative ways focused on the low resistivity pay zone from Gumai Formation (GUF) and Air Benakat Formation (ABF). The qualitative analysis through several well log data in Gumai Formation confirms the potential of low resistivity shaly sand reservoirs, GUF-1, GUF-2, and GUF-3, with neutron-density crossover. However, Talang Akar sand has an average resistivity value equally above 10 ohms. The low resistivity reservoir in Gumai turbidite deep marine sand could be occurred because of high shale content, fine grain sand, and the presence of laminated conductive clay minerals, such as glauconite. However, a low resistivity reservoir was initially considered unattractive because many major reservoirs which contain hydrocarbon would have a high resistivity value. Generally, the conventional petrophysical approach for low resistivity reservoirs in Gumai or Air Benakat Sand could lead to bias and pessimistic interpretation, yet in some cases, rocks with low resistivity have the potential to become hydrocarbon reservoirs. This study discusses how to identify and evaluate low resistivity pay zones and the success story of proving the Gumai hydrocarbon potential in West Benakat Field, South Sumatra.
Continuous Monitoring of Drilling Mud Properties Through Novel Microwave Apparatus
Authors: Alvarez Jose Oliverio , Santra Ashok
Published: September 2022

During drilling operations, encountering highly pressurized brine zones or low-pressure zones can alter the amount of brine in an oil-based mud, also known as oil-brine-ratio (OBR). Thus, monitoring the OBR is an important measurement to determine any changes in the formation pressure.

A non-intrusive microwave drilling mud analyzer (MDMA) for real-time oil-brine-ratio measurements was designed, built, and tested on drilling muds performed. The MDMA uses a vector network analyzer to measure the reflection (S11) and transmission (S21) spectra of drilling muds. The initial design concept consisted of a pair of waveguides whose ends face each other and are placed on the inner surface of the pipe. The waveguides have a diameter similar to the main pipe and are filled with specific low loss materials with dielectric value near that of the fluid in the pipe. Based on the initial design, an optimized prototype was designed and built. The improved design increases bandwidth by adding tapered ridges to the original cylindrical waveguide and optimizes the feed details to maintain an impedance match to the feed connectors.

Results on drilling muds shows a high sensitivity to brine content, which can be inverted to have high accuracy OBR values. In addition, the MDMA showed also high sensitivity to water dilution and to an increase in solids content
Real-Time Well Performance Measurement Using Non-Intrusive Clamp-On Measurement Technique
Authors: Black Michael , Heinks Carsten , Cramer Ron
Published: September 2022

The ability to quantify well performance individually and real-time across most if not all wells in a given field is a capability that bridges the gap between production and reservoir management. Having real-time oil, gas and water flow measurements from each well distributed across a reservoir has the potential to enable significant improvements in data driven and scalable production/reservoir surveillance and optimization. Traditionally, test separators offer the ability to perform well testing but the process is discontinuous, relatively infrequent and labor intensive. Over the last few decades in-line multiphase meters (many using radioactive sources) were developed which offer the possibility of real-time measurement but have high installation and ownership costs.

To enable cost effective, continuous well/reservoir management with minimal/zero well tests, we have devised a new type of clamp-on non-radioactive multiphase measurement system for rapid installation on the flowlines of new wells, or retrofitted to existing and producing wells with zero intervention. We will present hydrocarbon flow loop results obtained with this system – field measurement campaigns are in progress and preliminary data shows good read across between field and flow loop measurements.

A clamp-on multiphase flowmeter measurement system based on a combination of electromagnetic acoustic transducer (EMAT) and guided ultrasonic waves was developed to continuously measure liquid flow, gas flow and water-liquid ratio. A multiphase flow loop was constructed to simulate well multiphase flow conditions. The results obtained from the multiphase flowmeter system and the simulated flow patterns were validated using a combination of flow loop reference sensors and optical measurement of the liquid flow patterns using a high-speed camera. In parallel with these activities, a field based measurement campaign has also been initiated using a ruggedized portable measurement system.

Results from this activity shall be presented, demonstrating adequate performance levels for production applications. Work to progress field measurements to establish system performance under live measurement conditions is ongoing.

The measurement technique described in this paper is a novel approach towards the assessment of well performance not previously implemented. Additionally, the system capability (zero intervention combined with the ability to retrofit) opens up opportunities towards data driven scalable production/reservoir optimization not available with previous technologies.
Feasibility Study of Recrosslinkable Preformed Particle Gels for Natural Gas Injection Profile Control
Authors: Al Brahim Ali , Eriyagama Yugandhara , Bai Baojun , Schuman Thomas
Published: September 2022

Recrosslinkable Preformed Particle Gel (RPPG), a novel preformed particle gel of which particles can bond together to form a strong bulk gel system after being placed inside the target formation, has been successfully applied to control conformance problems for water flooding projects. However, no research has been conducted about whether RPPG is feasible in improving gas flooding performance in mature reservoirs. The study presents a systematic evaluation of acrylamide (AM) and 2-acrylamide-2-methylpropane sulfonate acid (AMPS) based RPPG including phase stability under different gel-gas kinetics and plugging performance to natural gas and water. Different experimental apparatuses were designed to quantify and visualize the RPPG phase stability under static and dynamic gel-gas interactions. The RPPG phase stability was evaluated under a different range of injection pressure, gas exposure time and swelling ratio. Also, the RPPG stability was compared to the in-situ gel system HPAM/Cr (III) which has been applied in oilfields to control gas injection conformance. The RPPG plugging efficiency was evaluated using open fractured cores with different apertures. The results showed that the RPPG was stable under both static and dynamic gel-natural gas interactions and was stable when being exposed to an acidic environment with an insignificant total percentage weight loss (< 3%). Additionally, the strength of the RPPG was further improved with the longevity of the gas exposure. Furthermore, different from the in-situ gel system HPAM/Cr(III), which exhibited high degree of dehydration under natural gas and exhibited substantial syneresis under acidic conditions, the microstructure of the RPPG remained stable after the dynamic gas exposure. The results of the coreflooding experiments demonstrated that the RPPG had excellent plugging efficiency, which was closely related to the swelling ratio and the fracture aperture. This is the first study where a polymer gel system has been systematically assessed through varied testing methodologies using natural gas as opposed to other studies where Nitrogen was used to simulate natural gas behavior. The robustness of the RPPG system makes it a viable candidate for improving the gas flooding processes in mature reservoirs dominated by conformance problems such as void space conduits, fractures, and high permeability channels.
Erosion Resistant Sand Screen: Development and Deployment
Authors: Lazo Antonio , Davis Jeremy , Weirich John
Published: September 2022

A design optimized coated sand screen was developed that increases the erosion resistance of conventional sand screens. Computational fluid dynamics and laboratory testing were conducted to determine the design optimizations and a coating was developed through rigorous testing. The screen has now been deployed and adopted with success.
Success Using Quartz-Based Technology in Rigless Mechanical Integrity Tests in the DJ Basin
Authors: Howley Grace , Winegarden Jason , Petrie Paul , Michel Cody , Algadi Otman , Drevdal Kjell Erik , Rygg Vidar
Published: September 2022

When a well is shut in for an extended period, the mechanical integrity of the production casing must be verified periodically to ensure there are no leaks in the casing that could lead to potential fluid migration between the producing zone and other formations along the wellbore. Traditionally, these mechanical integrity tests involve moving in a workover rig, tripping production tubing out of the well, setting a mechanical bridge plug above the highest set of perforations, and then pressure testing the casing. This operation is very time- and labor-intensive, with significant safety exposure risks for personnel involved. This paper describes work performed on 83 wells in the DJ Basin where an alternative method, not requiring a workover rig, was used.

In this case, conventional cementing equipment was used to pump a Bingham-plastic nonconsolidating sealing material with a high-solid-volume fraction through the tubing to the perforations. This sealing material is a high-quality, quartz-based slurry using an engineered particle-size distribution (PSD) from <100 nm to 2 mm. The specific PSD of the solids in this slurry is designed to maintain pumpability and ensure near-zero permeability once the slurry is in place. The sealing material creates an impermeable barrier across the perforations, which enables the casing to be pressure tested. The operational simplicity of this material offers improvements to both operational efficiency and safety risks. This slurry also poses little to no risk to the environment from an accidental spill or exposure, as it is a purely natural, silica-based product.

The silica-based slurry performed successfully, and the resulting mechanical integrity tests were equally successful. This paper explains the state regulations surrounding the mechanical integrity test, a comparison of the advantages seen with the alternative method, a detailed description of the job execution, and a summary of results observed in the cases where this alternate method was used.
Uncertainty and Sensitivity Analysis of Multi-Phase Flow in Fractured Rocks: A Pore-To-Field Scale Investigation
Authors: He Xupeng , Zhang Zhen , AlSinan Marwah , Li Yiteng , Kwak Hyung , Hoteit Hussein
Published: September 2022

Despite recent advancements in computational methods, it is still challenging to properly model fracture properties, such as relative permeability and hydraulic aperture, at the field scale. The challenge is in determining the most representative fracture properties, concluded from multi-scale data. In this study, we demonstrate how to capture fracture properties at the field scale from core-scale and pore-scale data through multi-scale uncertainty quantification, and assess how pore-scale processes can significantly impact the recovery factor. There are three components within our workflow: 1) performing high-resolution Navier-Stokes (NS) simulation at pore-scale to obtain hydraulic aperture of discrete single fractures, 2) embedding pore-scale parameters into core-scale for predicting field-scale objective, such as recovery factor, and 3) performing Monte Carlo simulations to determine the relationship effect of the pore-scale parameters to the field scale responding. At pore-scale, we start with four parameters that characterize the fractures: mean aperture, relative roughness, tortuosity, and the ratio of minimum to mean apertures. We then construct hydraulic aperture surrogates using an Artificial Neural Network (ANN). At the field scale, we deploy Long Short-Term Memory (LSTM) to capture the recovery factor at field-scale. The final results are the time-varying recovery factor and its sensitivity analysis. Monte Carlo simulation is performed on the final surrogate to produce the recovery factor value for various time-step. The result is beneficial for risk assessment and decision-making during the development of fractured reservoirs. Our method is the first to quantitatively estimate multi-scale parameters’ effect on recovery factors in two-phase flow in fractured media. This method also shows how we accommodate and deal with multi-scale parameters.
Well Control Considerations for CO2 Wells Based on Multiphase Flow Simulations
Authors: Zhou Lei , Anfinsen Bjoern-Tore , Hashemian Yahya , Yuan Zhaoguang , Mosti Inge
Published: September 2022

CCUS (Carbon Capture Utilization and Storage) is expected to be an important contributor to the ambition of reaching a net zero objective. Drilling and workover of wells to be used as CO2 injectors, pose a well control risk that needs to be properly understood and minimized.

The paper will address the significant differences between CO2 wells and traditional hydrocarbon wells. Due to differences in phase behavior, both well design and operational procedures would be impacted and needs to be revised. Traditional well control procedures are not necessarily applicable in CCUS wells without modifications.

A generic well was used to study the differences between a CO2 well and a hydrocarbon (methane) well with respect to design and procedural changes in case of a well control incident. A well control simulator capable of transient multiphase modeling of hydrocarbon and CO2 systems was used to evaluate the differences. Important operational and design limiting factors like volume, pressure and temperature responses, hydrate formation, phase transition as well as mitigation strategies and contingencies were evaluated. The model showed that with both SOBM and WBM, the CO2 influx entered the well in its supercritical form. Under static conditions, the CO2 remained in its supercritical form and showed no migration in SOBM, making its detection more challenging than for a methane influx. Driller's method was applied while simulating circulating the CO2 influx. For both mud types, the model showed greater liquid velocities compared to methane, which would reduce the time to react and put greater demands on surface equipment. The model also showed a greater drop in temperature than for a methane influx. Due to J-T cooling effect, the model shows that supercritical CO2 expansion near the surface can lead to significant temperature reduction, which in turn can lead to formation of hydrates and block the circulation. This effect also needs to be considered in the well design as the physical properties of the casings and surface pipes can be changed due to variation in temperature. Based on these results, measures to mitigate CO2 well control risks are discussed. This study will provide new knowledge regarding well control incidents related to CO2 wells. Improved understanding can be used to optimize operational procedures and potentially lead to new mitigation techniques.
Geological Neural Network Methodology for Automatic History Match; Real Case for Rubiales Field
Authors: Rodriguez-Torrado Ruben , Pumar-Jimenez Alberto , Ruiz-Mataran Pablo , Sarabian Mohammad , Togelius Julian , Toro Agudelo Leonardo , Rueda Alexander , Gallardo Enrique , Naranjo Ana Maria , Arango Sandro , Villasmil Jose Alberto
Published: September 2022

Full history match models in subsurface systems are challenging due to the large number of reservoir simulations required, and the need to preserve geological realism in matched models. This drawback increases significantly in big real fields due to the high heterogeneity of the geological models, the reservoir simulation computational time (which increases superlinearly). In this work, we propose a novel framework based on artificial intelligence to address these shortcomings. Our workflow is based on two main components: The first is the new combination of model order reduction techniques (e.g., principle component analysis (PCA), kernel-PCA (k-PCA)) and artificial intelligence for parameterizing complex three-dimensional (3D) geomodels, called "Geo-Net". Our new approach is able to create complex high dimensional heterogeneous reservoirs in seconds, providing better correspondence with the underlying geomodels, hard-data constraints and geological plausibility. The second component is a derivative-free optimization framework to complete the automatic history matching (AHM). This new approach allows us to perform local changes in the reservoir at the same time as we conserve geological plausibility. We have examined our methodology in a real field in Colombia. The Rubiales Oil Field is located in the Llanos Basin with original oil in place of around 6 billion barrels. The key finding here is that the Geo-Net is able to recreate the full geological workflow obtaining the same high order of statistics as traditional geo-statistical techniques. Nonetheless, our Geo-Net allows us to control the full process with a low-dimensional vector and reproduces the full geological workflow 10,000 times faster than commercial geo-statistical packages. Finally, the full optimization workflow has been applied to AHM. Results show an improvement with respect to best practice of traditional history match workflows.
The Reversible Relationship Between Choke Management and Liquid Yield Trends in Shale Reservoirs
Authors: Barzin Yalda , Walker Gregory
Published: September 2022

This paper builds on the observed strong correlation between liquid yield (Condensate Gas Ratio) profiles and choke management in the gas condensate wells, described in URTeC 3722999.

The study has included production profiles of over a hundred wells (initial CGR ranging from 50 to 250 STB/MMscf) operated across both the Eagle Ford and Duvernay.

The condensate yield has been observed to change depending on the choke strategy when the well is operated above the phase envelope. While a stable choke size promotes a stable CGR value, a drawdown strategy that includes rapid choke ramp-ups has a corresponding variation in CGR even above the saturation point.

What is explored in this paper is that the change in CGR is reversible, where a reduction in choke size will cause the system to restore to a higher CGR without damage to the well. A more conventional system would expect that a reduction in CGR results in liquid dropping out and potentially causing relative permeability issues (condensate banking). The reversibility is consistent with the adsorbed gas hypothesis (SPE 185045), where the change in CGR is attributed to contribution of desorped dry gas, rather than liquid drop out.

The second part of the paper investigates the relationship between small changes in choke and the corresponding change in liquid yield. The initial work had been looking at plots of logarithmic scaled axis for liquid yield and linear scale on choke, but closer examination has shown that the trend is more of a linear response. If the underlying mechanism is adsorbed gas, then the trend would be expected to have at least a qualitative response to a proxy for adsorbed gas such as TOC.
Pilot-Scale Experimental Study of Gas Migration in Wellbores
Authors: Rao Sai Sashankh , Samdani Ganesh Arunkumar , Penny Glenn , Wu Qian , Wileman Angel B. , Beck Griffin C. , Bhagwat Swanand M. , Gupta V. Paul
Published: September 2022

Gas migration velocity impacts the planning of pressurized mud cap drilling (PMCD) as it plays a pivotal role in the selection of fluid volumes and logistics. A pilot-scale experimental investigation of gas migration under downhole conditions (up to 3,600 psi, 240°F) in water, oils, and low-density drilling fluids is presented. While bubble-rise phenomena have been studied at near atmospheric pressures, the experimental setup and measurement method for high-temperature, high-pressure gas migration is rare. Experiments were performed using three test apparatuses: two separate pressurized lengths of 3-inch pipe, one 10-ft long and the other 18-ft long, as well as a unique high-pressure, high-temperature rotating test section (RTS). The RTS is 10-ft long, having a 6 inch × 4 inch eccentric annular geometry with the inner pipe capable of rotation. The inclination of all test sections can be varied. Gas was injected from the bottom through either a 1/8-inch diameter pressurized-injection port or a liquid-gas swap mechanism i.e. zero-velocity injection. Gas migration was recorded using a camera system or gamma-ray densitometers (GRDs). Some of the key results and insights from the testing are: (1) the gas migration rate and bubble length decrease with an increase in pressure, (2) the gas migration rate is higher in inclined vs. vertical sections, (3) bubble breakup occurs as pressure increases and interfacial tension decreases, (4) the inclination of the fluid column delays bubble breakup, and (5) high viscosity hinders bubble breakup. A key observation from the testing was that Taylor bubbles that may form during the initial phase of gas entering the annulus are likely to break up under downhole conditions of high pressure, low interfacial tension, and typical field mud viscosities, resulting in much lower gas migration rates during PMCD than the commonly used industry correlations. Another observation was that the practical length limitation of the test articles prevents us from observing the full evolution of gas bubble breakup. The results seen here are in line with our previous simulation work (Samdani et al., 2021, 2022).
Novel Mixed Wettability Coating: Application in Microfluidics Fabrication
Authors: AlOmier Abdullah , Sugar Antonia , Cha Dongkyu , Ayirala Subhash , Alotaibi Mohammed , Yousef Ali , Hoteit Hussein
Published: September 2022

Microfluidics is an emerging technology that has gained attention by the industry for its capabilities to investigate and visualize fundamental recovery mechanisms at the pore scale in a microdevice, mimicking, to some extent, the actual rock pore-network. While current technologies are capable of building micromodels that are either water-wet or oil-wet, a technique to achieve a representative mixed-wet property is still unreached. In this work, we introduce a novel surface coating capability using thin film deposition to fabricate surfaces with selective wettability, oil-wet and water-wet, an effort to mimic actual mixed-wet rock. This unique approach enables the generation of hydrophobic surfaces in selected regions by altering the hydrophilic surface property of silicon substrate at the microscale. A selective wettability control mask and Perfluorodecyltrichlorosilane (FDTS) hydrophobic coating using molecular vapor deposition (MVD) were used for surface wetting properties alteration. Surface measurements, including contact angle measurements, X-ray photoelectron spectroscopy (XPS), and Transmission Electron Spectroscopy (TEM) imagining, were performed to evaluate the thin-film composition and morphology. By altering the wetting state of the substrate by the coated film, a selective mixed wettability surface was achieved. This technique has the potential to be utilized in microfluidic device developments. Tuning the wetting state of the substrate to mimic the mixed-wet characteristics of reservoir rocks, such as carbonates and shales, can enhance our understanding of complex fluid behaviors in porous media and provide a crucial contribution to many subsurface petroleum engineering applications such as enhanced oil recovery (EOR) and CO2 storage.
Impact of Microannulus on the Heat Exchange at the Bottomhole
Authors: Santos Livio , Dahi Taleghani Arash
Published: September 2022

Every injection and production operation are accompanied by heat transfer between the wellbore fluids and the formation. Often these fluids are only circulated inside the wellbore. However, the presence of microannulus, besides compromising wellbore integrity, could have a negative impact on the rate of heat transfer to and from the formation. Thermal conductivity could be critical in CO2 sequestration, thermal EOR and specially closed-loop geothermal wells. This study aims to evaluate the impact of microannulus on the heat exchange rate at the bottomhole by combining numerical results and field measurements. We propose to identify presence of microannulus by analyzing distributed temperature sensing (DTS) measurements acquired at different times from EOR and closed-loop geothermal wells. In a DTS system, temperatures are recorded continuously along an optical sensor cable placed in the wellbore. The analysis is combined with numerical simulations considering different operational conditions to estimate the severity of the microannulus. In extreme cases, the presence of microannulus was found to decrease the bottomhole temperature in 2.5%. The results also highlight the importance of proper cementing design to ensure wellbore integrity and avoid heat loss.
Lithology Identification Through X-Ray Fluorescence (XRF) Analyses on Drill Cuttings While Drilling, in Santos Basin
Authors: Vidal C. S. R. Soares de Oliveira Filipe , Tepedino Martins Gomes Ricardo , Dias Roriz Carlos Eduardo , Milani Simões Silva Krishna , Correa de Toledo Rafael
Published: September 2022

The present research propouses a methodology using XRF analysis on drill cuttings samples, obtained during well drilling, for characterizing pre-salt reservoir formations in the Santos Basin, southeast of Brazil in order to identify composition variations in carbonates, clay zones and potential igneous rocks.

In this study 16 off-set wells were analyzed where XRF analysis was performed on drill cuttings samples. Aftwerwards the results were compared with lithogeochemical and gamma-ray spectral logs, determining the consistency of the data. The lithological interpretations were based on macroscopic (sidewall core samples - SWC) and microscopic (thin section) descriptions and geochemical analyses from SWC samples. This permitted us to comprehend the variations observed in the carbonate reservoir and to identify possible igneous rocks.

From the results, a pattern of responses could be established for the XRF method for each lithology within the Pre-salt section, using the major elements (Mg, Ca, Si, k, Fe and Al) and some minor elements and trace elements (Sr, Rb, Y, Zr, Ti, Nb, Ga). The variations of the major elements were best observed in radar and bar charts, that use only the major elements, which enabled the separation of the lithological section into six main sets: limestones, dolomitic carbonates, silicified carbonates, carbonates with magnesian clay, siliciclastic rocks (shale/siltstone/sandstone) and basic igneous rocks (basalt/diabase). For quality control, still during drilling, comparative analysis by three approaches was proposed: a) the systematic comparison of the proportion of elements composing the same mineral, such as Ca and Sr, K and Rb, and Al and Ga; b) the comparison of XRF data with XRD data; and c) comparison with calcimetry data in a cutting sample. Furthermore, in order to support the interpretations, four crossplots (Ca × Si; K.Rb × Al.Zr; Rb × Sr; Zr × Fe) and one crossover (Rb × Sr) were generated aiming to individualize the six lithological types described, as well as diagrams from the literature to identify the igneous rock type.

The use of XRF on cuttings to determine lithologies during the drilling of petroleum wells is new in the literature, as well as the proposed quality control, being useful for the characterization of complex reservoirs such as Santos Basin pre-salt, being a methodology already used since 2018 by Petrobras.
Experimental and Modeling Study of CO2 EOR and CO2 Storage in Heavy Oil Reservoirs
Authors: Wang Wuchao , Liu Huiqing , Dong Xiaohu , Chen Zhangxin , Yang Farong , Li Yu , Guo Yunfei , Wang Zhipeng , Tian Yunfei , Lu Ning , Xu Wenjing , Jiang Xiuchao
Published: September 2022

This study focuses on unveiling the interaction between injected CO2 and heavy oil through adequate phase behavior analyses. Moreover, the potential of CO2 EOR and CO2 storage were evaluated through injection scheme optimization and sensitivity analysis.

Experimentally, the PVT experiments including CO2/heavy oil systems have been carried out to measure oil swelling, solubility, viscosity reduction, and density variation. The MMP of the heavy oil-CO2 mixture has been determined to provide the reference pressure for core displacements. CO2 injection experiments were conducted to examine the performance of CO2 enhanced recovery under different pressure. Different injection schemes were experimentally simulated including water flood, injection water followed by CO2 flooding, and injection water followed by CO2-WAG (water alternating CO2 flooding). Based on these studies, the sensitivity analysis was run on the validated model to examine the effects of different parameters including gas injection rate, CO2 slug size, and CO2-WAG cycle number on the heavy oil recovery and CO2 storage efficiency.

As the saturation pressure of the heavy oil-CO2 mixture increases, the solubility of CO2 in heavy oil, the swelling, and the viscosity reduction increase at reservoir temperature (60°C). Although CO2 displacement efficiency and CO2 storage efficiency increase with increasing injection pressure, the increase in these two factors become significantly slower as pressure exceeds the MMP (30 MPa). Injection water followed by CO2-WAG increased oil recovery more than water flood or injection water followed by CO2 flooding. Only considering the influence of single factor conditions, the higher the injection CO2 rate, CO2 slug size, or WAG cycles number, the higher the cumulative oil production. However, based on comprehensive consideration of oil displacement rate, CO2 storage efficiency, CO2 cumulative storage, and cumulative WOR (water-oil ratio), reasonable injection CO2 rate, CO2 slug size, and WAG cycles number were finally optimized and screened out as 30,000 m3/day, 0.5 PV, and 5, respectively.

The outcomes of this work provide valuable information for designing a suitable CO2 flooding strategy in heavy oil reservoir engineering applications. It also could bring significant economic and environmental benefits by improving oil recovery and reducing CO2 emissions.
Middle East Giant Carbonate Field: Integrated Water Injection Optimization Workflow
Authors: Del Fraro Stefano , Renna Simona , Tfaili Hana , Mariotti Pamela , Tarantini Vincenzo , Tanganelli Francesco , Salvi Valeria
Published: September 2022

A proper reservoir management is mandatory to optimize the water injection strategy through time, since the injected fluids tend to flush the same preferential paths, leading to a significant reduction of the incremental swept oil.

This paper shows the results of an integrated workflow applied to a giant brown field with complex geology. The proposed workflow is based on a semi-automated process to optimize water injection, embodying the improvement and assessment of the 3D model.

An integrated Production Data Analysis (iPDA), initially available, allowed to understand the main fluid dynamics of the reservoir, which were integrated in the 3D model since the earliest setup. Streamlines methodology was then used to compare the 3D model with the iPDA outputs in terms of subsurface dynamics, guiding the reservoir model history match process. Finally, streamlines traced on the validated model allowed to optimize water injection strategy for the forecast simulations using a semi-automatic process. It relies upon an iterative loop of rates redistribution among all active injectors, based on their own oil displacement efficiency calculated using dedicated software.

The mentioned workflow was applied on Beta formation of Alpha field, which is a mid-Cenomanian carbonate giant oilfield in the Middle East region with more than sixty years of production and about five hundred drilled wells, characterized by karstic behavior. In this very challenging context, streamlines simulation technique, mostly used during the HM phase, resulted in an increase of 3D model reliability and representativeness of the main evidence from iPDA. This led to generate more robust forecast scenarios.

In particular, the proposed workflow allowed to optimize the water injection strategy, adequately redistributing the overall available injection rate between all the injectors, promoting the most efficient ones, and reducing the inefficient. This approach resulted in a definitively appreciable oil reserves potential gain, consisting in the plateau extension of about one year from the forecast 3D simulations.

The economic value of this result can be better appreciated if we consider that it is associated only to the re-distribution of the injection rate, without any additional capex.
Limiting Deteriorative Impacts of Oil-Based Mud Residuals on Cement Bonding
Authors: Tabatabaei Maryam , Santos Livio , Al Hassan Ali Ahmed , Dahi Taleghani Arash
Published: September 2022

Successful cementing relies on an effective removal of oil-based muds (OBMs) specially from rock and casing surfaces. However, most OBMs are heavily absorbed onto the mineral surfaces as well as casing, deteriorating the interfacial bonding of cement to these surfaces. We present a novel cement additive made from treated surface-modified graphite nanoplatelets (GNPs) to minimize the impact of mud residuals on the bonding strengths of cement. Experimental results show that after spacer flushing for the cases of limestone and sandstone cores, treated GNPs not only limit the impact of mud residuals at the interfaces, but also, raise the bonding strength beyond that corresponding to water saturated cores.
Geological Characterization of Lower Devonian Reservoirs in Reggane Basin, Algeria
Authors: Djezzar Sofiane , Boualam Aldjia , Ouadi Habib , Laalam Aimen , Mouedden Nadia , Merzoug Ahmed , Chemmakh Abderraouf
Published: September 2022

In the Reggane basin, the most promising petroleum system is represented by the Lower Devonian, Cambro-Ordovician, and Carboniferous reservoirs. Most of the traps are linked to structures with very complex geometry, generally leaning on reverse faults, under superficial detachment levels. The generation of hydrocarbons took place, in the Paleozoic during the burial period (Upper Devonian-Carboniferous) and probably during the overheating of the Jurassic. The basin architecture is the outcome of a superposition of several tectonic phases from the Caledonian to the Hercynian tectonic events. The main reservoirs are in the North-East part of the basin, namely the Lower Devonian, Ordovician, and Carboniferous. The Gedinnian and the Siegenian are the main reservoirs of the Lower Devonian sequence, with the Emsian as a secondary reservoir. The Carboniferous and Ordovician reservoirs became targets after the discovery of dry gas in the Kahlouche and Anzeglouf areas. The main gas fields in the Reggane basin are Hassi-M’dakane, Feidjet-El-Had, Kahal-Tabalbala, Djebel-Hirane, Kahlouche, Tiouliline, Reggane, Azrafil, and Anzeglouf. The current geometry of the Reggane basin is marked by two major structural axes, resulting from a complex tectonic history. Reggane basin is elongated NW – SE, relatively asymmetric. The southern flank of the basin is characterized by a hallow dip plunging towards the North and affected by rare reverse faults. On the other hand, the northern flank is affected by many faults and folds. These faults arrangement of the various faults that have affected this basin can be broken down into two main sets: NW - SE set: this direction is very important; it all appears along the northern edge of the basin and presents a comparable direction to the Ougarta ridge. A set of submeridian directions: concentrated in the SE part of the basin (eastern periclinal closure constituting the transition zone between the Reggane basin and the Azzel Matti slab). This fault sets form an extension of the major submeridian accidents in the Hoggar shield. Two other directions of less represented the E-W faults forming an accident relay along the edge of the basin with the Ougarta ridge and the NE - SW faults. This study will help to define the quality and extension of the Lower Devonian sandstone reservoirs in the northern part of the Reggane basin, the construction of favorable zone maps for exploration with risk-weighted reservoir spaces, identification, and evaluation of "Tight Gas Reservoir", and trap analysis and petroleum potential the Reggane basin.
Diffusional and Electrical Tortuosity in Unconventional Shale Reservoirs
Authors: Odiachi Judah , Cruz Felipe , Tinni Ali
Published: September 2022

Tortuosity is a porous medium property which measures the interconnectedness and sinuosity of the pore space. It is important in order to understand advective, diffusive transport and electric current flow in low porosity low permeability reservoirs such as unconventional shale reservoirs. However, experimental values of diffusional and electrical tortuosity of shales are scarce in the literature. To improve the understanding of diffusive transport and electrical flow in unconventional shale reservoirs, we have conducted the independent measurements of diffusional and electrical tortuosities of 12 shale samples from Utica, Bakken, Wolfcamp and Eagle Ford formations and 3 sandstones as control samples.

For the purpose of this study, the samples were characterized by measurements of total organic carbon (TOC), mineralogy, and total porosity. Diffusional tortuosity was measured by immersing brine saturated samples into D2O to allow the diffusion of D2O into the samples. The rates at which D2O diffused into the samples were measured with 12 MHz NMR measurements. The combination of the effective diffusion coefficient of D2O and the bulk diffusion coefficient of D2O were used to compute the diffusional tortuosity.

To measure electrical tortuosity, the samples were resaturated with 2.5% KCl brine prior to immersion into 6% KCl brine. The measurements of the samples’ resistivities as function of time after the immersion into the 6% KCl brine were used to compute ionic diffusion coefficients. Electrical tortuosity was calculated using the bulk ionic diffusion coefficient and the ionic diffusion coefficients of the samples.

The results show that diffusional and electrical tortuosity have similar values. These tortuosities vary between 1.7 and 5.8 for shale samples while they have values between 1.4 and 3.9 for sandstones. We also observed that TOC exerts a primary control on the tortuosity of shales.
Optimizing Drill Bit Design Iteration with a New Sensor System Developed for Large-Scale Deployment and Automated Analysis of Drilling Dysfunctions
Authors: Schen Aaron , Graham Ryan , Engel Braden
Published: September 2022

A drill bit dynamics sensor system has been developed with a new approach that enables economical, widespread use of downhole data to improve bit design. The system emphasizes ease of deployment and minimal manpower requirements for data interpretation. The goal was to develop a system appropriate for deployment on a new scale to the bit industry. The system consists of a small in-bit sensor coupled with an automated software system that provides direct design guidance targeted at drill bit specialists. This paper aims to detail the design considerations used to develop this system and provide an example application of the technology from field testing.
Unconventional Najmah Reservoir Formation Evaluation in West Kuwait Using an Innovative-Integrated Approach for Productivity and Potential
Authors: Fawzy Mahmoud , Al-Morakhi Rasha , Quttainah Riyad , Kalawina Mahmoud , Balliet Ron , Swidan Zakaria
Published: September 2022

Abduliyah field is one of the major fields in the West Kuwait asset where the Najmah shale (Kerogen unit) is present. The Najmah shale is a high Kerogen content, calcareous mudstone and is considered the main source rock for shallower depth oil reservoirs in Kuwait, due to the shortage of data especially core data at reservoir condition there is enormous uncertainty in the determination of the unconditional reservoir properties that need to be evaluated to confirm both economic and operational success. An integrated logging approach was implemented using pressurized sidewall rotary coring, magnetic resonance, borehole image logs, conventional logs, and core analysis to assess the Najmah storage volume, and quantify the potential hydrocarbon fluids in place and provide a time and cost-efficient method of reservoir evaluation.
2D Surface Roughness Quantification for Enhanced Petrophysical Applications
Authors: Singer Gabriela , Ma Shouxiang Mark , Chen Songhua , Eid Mahmoud
Published: September 2022

Surface roughness is an essential rock parameter affecting petrophysical properties that are surface sensitive such as characterization of pore structure and wettability. For instance, Wenzel's contact angle formula for rough surfaces requires knowledge of the surface roughness, and surface roughness is expected to speed up aging of cores in crude oil for wettability restoration. In addition, proper quantification of surface roughness is critical for obtaining representative, roughness-independent, pore sizes for applications such as prediction of permeability and interpretation of capillary pressure curves.

Intuitively, a surface is better characterized in 2D than in 1D. This 2D study is a continuation and enhancement of the previous 1D work, recently published in the SPE Journal (Ma et al., 2021). In this current paper, a comprehensive investigation of 1D versus 2D surface roughness measurements is conducted to evaluate and cross validate the two approaches. In this study, surface roughness is measured on 26 carbonate rock samples by laser scanning confocal microscopy (LSCM), where both the 1D absolute increment surface roughness, Sr, as well as 2D interfacial area ratio of surface roughness, Sdr, are reported. As expected, results indicate that surface roughness characterized by 2D Sdr has a greater dynamic range than the 1D Sr measurement, i.e., the 2D Sdr provides a more representative characterization of surface roughness.

A detailed account of methodologies, assumptions, limitations, validation and applications of the 1D and 2D surface roughness characterization is documented in this paper. To extract the roughness features present on rock grain surfaces, effects of de-spiking and filter length, used to eliminate pore size effects, are investigated. For specific applications of surface roughness corrected pore size estimation from nuclear magnetic resonance (NMR) measurements, differences in length-scales of surface roughness are compared between LSCM measurement and that derived from NMR diffusion-T2 plus BET surface area. The surface roughness-corrected NMR pore-size distribution is also validated against the pore-size distribution obtained from measurement of micro-CT scanning.
Rotating 6 Axis Survey Measurement and it's Effect on True Vertical Depth Accuracy, a Study of Sag Correction and Misalignment While Drilling
Authors: Lowdon Ross , Brands Sjoerd , ElGizawy Mahmoud , Rawlins Sheldon
Published: September 2022

Definitive dynamic 6 axis surveys provide continuous MWD quality measurement while drilling. This poses a challenge in terms of misalignment (relative to the borehole) correction when compared to traditional static survey measurements where misalignments are well understood and can be easily compensated for. The increased frequency of surveys allows for the possibility of significant systematic TVD errors if a static misalignment (SAG) error is applied unilaterally to the definitive dynamic surveys.

This paper outlines how we can measure misalignment in definitive dynamic surveys, what the magnitude of those misalignments are and their impact on a wells TVD.

The misalignment of Definitive Dynamic Survey measurement with respect to the borehole is a complex problem, as the BHA is under dynamic load and rotation as measurements are being made. As such a dynamic BHA model needed to be developed where the input parameters to the drillstring (such as RPM, Weight on Bit, and mud properties) and the downhole movement data available from the MWD and Rotary steerable tools are combined to recreate down hole conditions. The BHA which was run is then modelled dynamically to establish what borehole misalignment is present. This information is then evaluated to see what localized and summed effect this misalignment has on the inclination derived in the Definitive Dynamic Survey and therefor the impact on TVD and lateral well placement.

The results of this study will establish the validity of mis-alignment corrections to be applied to definitive dynamic surveys, it will also allow for further insight into BHA behavior to be made and improved dynamic models to be developed due the new Realtime surveying density that is possible with taking surveys every 20 seconds while drilling.

The original theory of random misalignment will be tested with high density downhole data to build a more complete picture of the BHA motion with insights into borehole quality and true well placement becoming possible. This could fundamentally improve TVD errors, with a dramatic reduction in the residual error for SAG corrections having a particular impact on long high angle sections of a given wellbore.

Definitive dynamic surveys are novel in that definitive surveys are taken while drilling rather when stationary. The analysis of these high-density surveys provides new insights into borehole quality and geometric well placement. Adding in downhole shock and vibration data with surface information it is possible to see how the BHA is behaving in the borehole and resolve the issue of borehole misalignment and ultimately tool accuracy.