bluuebunny/crossref_metadata_2025 huggingface dataset:
Addressing Realtime Formation Evaluation Data Transmission Challenges with Microbubble and Hollow Glass Sphere Mud System - A Case Study from India
Authors: Pawandeep Bagga , Shubhada Khatri
Published: April 2024

Objectives/Scope

The paper outlines the obstacles encountered during the initial implementation of Hollow Glass Sphere (HGS) and Microbubble Mud Systems for formation evaluation data transmission while using mud pulse telemetry in Western Offshore India. The oil and gas operator encountered significant challenges when drilling and assessing formations in directional wells within these low-pressure and depleted reservoirs. HGS and Microbubble Mud Systems were employed to decrease the density of drilling fluids to prevent and address losses while drilling through a producing reservoir section with low pore pressures.

Methods, Procedures, Process

In an effort to address the issue of significant or complete loss of drilling fluid during operations in a low-pressure reservoir, a low-density mud system was introduced with a density ranging between 6.3 to 7.5 pounds per gallon (ppg). However, the inclusion of micro-bubbles or hollow glass spheres in the drilling mud resulted in poor compression, substantial distortion, and weakening of the mud pulse telemetry signal. As a result, the real-time logging-while-drilling (LWD) log lacked data density, diminishing its value to the client. To rectify this, an in-depth analysis was conducted, considering factors such as pump efficiency, flow rate, mud pulse telemetry principles, and pulser design, leading to the development of a novel technique aimed at delivering high-density formation evaluation LWD Data.

Results, Observations, Conclusions

Identifying the factors that posed limitations and implementing strategies to mitigate risks were pivotal actions taken to minimize the risk of data loss and ensure a continuous and uninterrupted stream of logging-while-drilling (LWD) data for real-time decision-making by the operator. This involved servicing the pulser, making changes to pulser design, and enhancing the accompanying software, resulting in the capability to transmit mud pulse data at rates of up to 20 BPS in place of 5 BPS initially. The modified configurations of the mud-pulse telemetry module proved highly valuable in delivering an uninterrupted LWD log with a sufficient data density, thus meeting the requirements of the operator’s subsurface team.

Novel/Additive Information

The paper ends with concluding the best practices which should be incorporated to deliver quality data. This pulser and telemetry system can be combined with any LWD services including NMR, formation pressures and electrical imaging while drilling.
Application of Wellbore Stability Improvement and Drilling Risk Reduction with Static Geomechanical-A Case Study from China
Authors: Cai Jingshun , Zhang Peiyu , Wen Ran , Li Jianhai , Zhang Xin , Lou Yumeng , Huang Xingning
Published: April 2024

Yi 202 block has experienced multiple phases of tectonic movement, resulting in extensive development of natural fractures in the region. Actual drilling indicates that the presence of these natural fractures poses great challenges to drilling operations. However, the wells in this area are ultra-deep, and many sets of complex and difficult-to-drill formations are encountered in top-down drilling, which brings significant challenges to the drilling engineering. Based on triaxial and shear experiments, transverse isotropy theory and weak surface criterion, and integrating the mechanical damage under stress unloading and hydration in drilling wells, a well wall stability model under the synergistic effect of stress unloading and hydration has been established, and an analysis of the factors influencing the stability of the well wall of the formation has been carried out. The study shows that stress unloading occurs after drilling. The greater the confining pressure and axial stress, the more significant the shale strength weakening caused by stress unloading, and the magnitude of stress unloading is positively correlated with the degree of mechanical strength weakening. The more developed the laminations are, the easier it is to damage along the laminations. When stress unloading occurs, the weak structural surface acts synergistically with stress unloading, and the higher the degree of shale strength weakening is, the worse the mechanical stability is and the higher the risk of well wall instability. External fluids are prone to intrude along the bedding and promote shale hydration, making the shale mechanically less stable and reducing the well wall's stability. The effect of stress unloading on shale formation collapse pressure mainly occurs in the pre-drilling stage, and the effect of hydration damage on well wall instability mainly occurs in the late drilling stage. Beddings, stress unloading, and hydration affect the well wall stability together. The shale well wall stability model under stress unloading-hydration synergistic effect considers the influence of the three comprehensively. The prediction results align with the drilling actuality with good reliability after the field application test.
Full Field Implementation of Physics-Based Analytical Model to Optimize Steamflood in Mukhaizna Heavy Oil Field in Oman
Authors: Al Qasabi Nasar , Al Asimi Mohammed , Al Mujaini Majid M , Le Duc , Gao Chao , Dornier David M
Published: April 2024

To optimize steamflood in Mukhaizna Field, Occidental developed connections-based simulation models that retains most of the steam flooding physics. These models address the issue of lengthy run time of traditional 3D reservoir models and resolve the predictability issues of fast physics-less AI/ML models. As these models are being used for full field optimization since 2020, ensuring models reliability and accuracy was a key consideration to optimally operate such large asset.

To gain more trust in these models, models input/output, historical match, applied constraints and recommended steam changes are validated with Reservoir Management Teams (RMTs) before field implementation. After implementation, actual steamflood performance is monitored on regular basis with the RMTs relative to model expectations considering assumed constrains. Predictability of the models were checked in the forms of blind tests and comparison of models prediction with actual field data on well level. Furthermore, to QC the reliability of these models, their outputs were validated with actual measurements and reservoir performance for the applicability be used in understanding reservoir dynamics in areas with no/limited data acquisitions.

With multiple optimizations and implementations, it was observed that these physics-based models managed to align steam allocation with available opportunities and constraints given the continuous improvement and dynamic challenges in the field. This resulted in observed increase in oil production rate in some areas, reduction in production decline rate in other areas, and increased overall steam efficiency. It was observed also that good handling of production constraints and limitations are essential factors in deciding steam distribution even if reservoir quality and flood efficiency are on the high side. Finally, having history matched physics-based models, enabled the use of model outputs in the day-to-day surveillance, understand subsurface wells connections, unlock hidden opportunities, and provided a reliable tool for optimum operating scenarios going forward.

This paper describes one of the largest full field application of physics-based closed-loop reservoir management system in steamflood projects, demonstrate the steps to ensure models reliability, present observed results and challenges, and share lessons learned.
A Data Driven Approach to Optimizing Gas Reservoir Management Through Machine Learning and Phase Behavior Analysis of Production Data
Authors: Bestman S. , M. Khatrawi F. , M. Almahdi R. , M. Dalbahy B.
Published: April 2024

The significance of reservoir management has been recognized by the Oil and Gas industry as a strategy for maximizing resource recovery while minimizing investment. Fowler et al (1996) identify reservoir management as a tool to manage risks while optimizing profitability. Fanchi (2018) points out that successful reservoir management requires an understanding of the reservoir structure, the distribution of fluids within the reservoir, drilling and maintaining wells which can produce fluids from the reservoir, transport and processing of produced fluids, refining and marketing the fluids, safely abandoning the reservoir when it can no longer produce, and mitigating the environmental impact of operations throughout the life cycle of the reservoir.

Wiggins et al (1990) underline the three primary components of reservoir management as: Knowledge about the entity being managedManagement environmentAvailable technology

Thakur (1996) highlights the increasing role of data in reservoir management activities along with the need for comprehensive, cost-effective surveillance with surveillance management programs and well-planned data-collection with data-collection management programs.
A Strain-Driven Model for Anisotropic Permeability Evolution of Shale and Coal Incorporating Creep Deformation, Anisotropic Internal Swelling/Shrinkage, and Gas Rarefaction Effects
Authors: Zeng Jie , Guo Jianchun , Liu Junchen , Zhang Tao , Zhao Zhihong , Liu Jishan , Chen Zhongwei
Published: April 2024

Permeability of shale and coal is a main controlling factor for gas migration and is sensitive to effective stress, sorption/desorption-induced internal swelling/shrinkage (swelling/shrinkage at fracture/pore surfaces), and gas rarefaction effects. The dependence of gas permeability on effective stress and rarefaction effects has been extensively studied. However, the impacts of anisotropic strains and their time-dependent evolution (creep deformation) on permeability variation were still not fully understood, which makes it difficult to accurately predict permeability evolution and simulate gas transport, especially for deep coal.

To fill this knowledge gap, a modified sugar-cube conceptual model that captures the structural anisotropy of coal and shale is used to develop a generic fully anisotropic strain-driven permeability model incorporating anisotropic creep deformation, directional internal matrix swelling/shrinkage, and gas rarefaction effects. The time-dependent creep deformation is described by the Nishihara quasi-static rheological model with elastic, viscoelastic, and visco-plastic strain elements. Unlike previous studies where anisotropic internal swelling/shrinkage is ignored or simulated by simply using three sets of independent Langmuir pressure and swelling strain constants, a mechanical-property-based swelling model is used to truly couple directional internal swelling/shrinkage strain with mechanical anisotropy according to the energy balance theory. The Beskok-Karniadakis model is employed to accurately characterize full-Knudsen-number-ranged gas rarefaction effects.

The proposed permeability model is verified against coal permeability measurement data. Analyses results indicate that the permeability evolution in each direction shows unique features depending on the anisotropic structure, directional internal swelling, and mechanical properties. The permeability reduction contributed by three-stage creep deformation can be larger than 90%. Internal swelling strain variation in all directions also exhibits a noticeable impact on the magnitude of permeability, which is more obvious at the third stage. The overall influence of the gas rarefaction phenomenon turns heavier as time increase due to the continuous narrowing of flow channel.

Due to its analytical feature, the proposed model is suitable for different permeability measurement conditions, including constant effective stress, constant confining pressure, and constant average pore pressure conditions. It can be easily incorporated into a more complex and realistic Multiphysics framework for field-scale simulation and well production prediction.
Developing an ESP Lifespan Predictive Model Using Artificial Intelligence: A Case Study On an Omani Oilfield
Authors: Al Sawafi Ali , Kazemi Alireza , Ganat Tarek , Al Saadi Faisal , Al Ghadani Adnan
Published: April 2024

The Electrical Submersible Pump (ESP) is the most effective and consistent artificial lift method for medium to high production rates. Although the capital cost of ESP is high, it pales in comparison to the production losses resulting from its failure. Recently, Machine Learning (ML) has gained significant attention in the oil and gas industry due to its predictive power. This paper aims to develop a ML model to predict ESP lifespan and identify the key features that influence its longevity. The study reviewed the failure history of more than 100 wells from an Omani oilfield, with 132 ESP failures attributed to sand and scale accumulation. The dataset includes 36 static features related to ESP design, installation, commissioning, failure, pull-out, and teardown. Three algorithms, namely Support Vector Regressor (SVR), Random Forest Regressor (RFR), and Extreme Gradient Boosting Regressor (XGBR), were selected. Hundreds of tests were performed on each algorithm to optimize the parameters and hyperparameters, based on mean absolute error, average residual, and determination coefficient. The study developed a model with two levels to predict the lifespan of ESP before installation and after the last valid well test. The model had a mean absolute error of 25 days and 8 days for the first and second levels, respectively, with a determination coefficient of 60% and 73%. The model showed that certain factors related to pump and motor design have the most significant impact on the longevity of the ESP before installation. Pump discharge pressure and flow rates of oil and water are crucial to monitor and control during its operational lifespan. The findings emphasize the importance of careful selection and design of ESP components to ensure a long-lasting lifespan. By scheduling ESP maintenance before failure, these findings can help mitigate capital costs, while preparing the necessary hoist, rig, and materials for ESP replacement can avoid deferred operational costs.
Effectiveness of Surfactant-Polymer Flooding at High-Temperature and High Salinity Reservoirs: Moderate-Low or Ultra-Low Ift?
Authors: Hou Jian , Huang Tianping , AlOtaibi Mohammed
Published: April 2024

To implement an effective chemical flooding process in enhanced oil recovery in a sustainable way, it requires a careful selection of surfactant-polymer (SP) formulation, regarding on the interfacial tension (IFT) with oil. Usually, a unltra-low IFT is preferred to achieve a low residual oil saturation and a high oil production rate. The question is how low of the IFT is enough for an effective oil production. Targeting at high temperature and high salinity carbonate reservoirs, this work deeply discussed the interfacial tension (IFT) factor on the effectiveness by injecting two SP formulations with similar viscosity but moderate-low and ultra-low IFT respectively.

The SP formulations BC-O1/PST-10 (zwitterionic surfactant / sulfonate polyacrylamide) and APA-H1/SPAM-A5 (zwitterionic surfactant / sulfonate polyacrylamide) were selected since their good compatibility with a high salinity brine with total dissolved solids of 57,670 ppm. The IFT measurements of both SP formulations were conducted using a spinning drop tensiometer (SVT20N, Dataphysics) at a temperature of 90 °C. The rheological properties were measured using a rheometer (Discovery HR-2, TA Instruments). And the injection of BC-O1/PST-10 and APA-H1/SPAM-A5 for oil displacements was performed in a homogeneous medium oil-wet microchannel slice at 90°C, following a water injection process. The incremental oil production rate was calculated from the microchannel images.

It was observed that the IFT values between oil and the SP solution composed of BC-O1/PST-10 and APA-H1/SPAM-A5 are in the moderate-low range (10-2 mN/m) and ultra-low range (10-3 mN/m), respectively. It also presented the viscosities of the polymer solutions are similar when polymer concentrations were at 2,000 ppm, which ensured a similar sweeping efficiency in the displacing process. The oil displacement experiments showed the incremental oil production rate of BC-O1/PST-10 injection (40%) was a little higher than APA-H1/SPAM-A5 injection (37%) though the IFT was a magnitude higher. This study presented that in oil-wet or mixed wet carbonate reservoirs, despite IFT factors, other influences such as surfactant-polymer interactions also play an important role. The moderate-low IFT could be sufficient for SP flooding in high salinity high temperature reservoirs.

This work intends to provide an effective SP flooding technique regarding the interfacial tension. In high salinity high temperature carbonate reservoirs, zwitterionic surfactants with a medium-low IFT for oil production could be a good choice. This gives more options to select green surfactants instead of pursuing lower IFT.
Assessment of Factors Controlling Low Salinity Water Flooding in Carbonates: An X-Ray Photoelectron Spectroscopy Insight
Authors: Souayeh M. , Al-Maamari R. S. , Kyaw H. H.
Published: April 2024

Low salinity water (LSW) flooding, as a wettability modifying agent, is observed as one of the viable technologies for improving oil recovery in carbonates, owing to its low cost, low carbon footprint and effectivity. However, the optimum salinity (i.e. dilution factor) and wettability state to trigger the low salinity effect remain subjects of conflicting views. Thus, the main objective of this study was to investigate the factors controlling the low salinity effect (LSE) quantitatively and qualitatively.

Series of interfacial tension (IFT) measurements, contact angle (CA) analysis on calcite surfaces, and, spontaneous imbibition tests in Indiana limestone outcrops were carried out at 75°C. The experiments were performed using synthetic formation water (FW) having high salinity (196 g/L), which was diluted by various factors: 2 times (97.9 g/L), 4 times (49 g/L), 10 times (19.6 g/L), 20 times (9.8 g/L) and 100 times (1.96 g/L), and crude oil sample obtained from the targeted carbonate reservoir. Furthermore, surface composition of calcite surfaces before and after wettability modification were analyzed using X-ray photoelectron spectroscopy (XPS).

The measured IFT between formation water and crude oil was equal to 9 mN/m and it reduced to ∼6 mN/m upon decreasing the salinity. Such IFT reduction could contribute to the recovery mechanism. CA results showed that the wettability of the calcite surfaces was altered from an initial oil-wet state towards an intermediate-wet state, upon reducing the salinity from 196 to 19.6 g/L. Further reduction of salinity resulted in no wettability alteration and the calcite surfaces remained oil-wet. It was found that the positive effect of increasing rock dissolution, by decreasing salinity, in reducing oil-wetness is opposed with the negative role of sulfate in shifting the wettability towards oil-wet due to the resultant increase of the pH of LSW solution. The oil recoveries by spontaneous imbibition were in perfect agreement with CA results, as maximum oil recovery (∼50 %) was obtained for the LSW system (19.6 g/L) that shifted the wettability from oil-wet towards intermediate-wet. From XPS analysis, it was observed that the atomic percentage of C−C/C−H peaks reduced after treatment with LSW suggesting the calcite was slightly dissociated during treatment. In addition, calcium dissociation was more dominant than carbon after treating with 1.96 g/L, while for the case of 19.6 g/L, carbon dissociation was more dominant.

The findings of this study provide a deeper understanding of the factors influencing the LSE in carbonates by coupling the change in surface composition with wettability alteration. It is interesting to state that although none of the LSW solutions used in this study could alter the surface wettability towards a water-wet state, some of the intermediate-wet systems were able to efficiently increase oil recovery by spontaneous imbibition.
EOR of Sour Oil Field Through CO2 Miscible Gas Injection: De-Bottlenecking Challenges for Surface Facilities
Authors: Al Lawati M. R. , Dhahli A.
Published: April 2024

The cluster of fields under the scope of the study are located in South of Oman. Most of the fields are located within a salt basin. The fields were discovered in different periods and all are under production. The study was focused on the largest two fields in the area that are currently under Miscible Gas Injection (MGI) as means of Enhanced Oil Recovery (EOR). Both of the fields have been under MGI for over 10 years, with sour gas produced from the two fields, among other fields, is re-injected into the reservoir. A small fraction of the produced sour gas is treated and exported as sales gas to a nearby pipelines. The sales gas is mostly used for power generation.

The re-injected gas used for MGI consists of a significant gas bubbles that is currently used for EOR purposes. If the current EOR scheme continues, the gas bubble cannot be commercialized until most of the oil reserves are produced.

The objective of the study was to assess the feasibility of Carbon Dioxide (CO2) utilization for EOR of the oil fields through additional oil miscibility by replacing sour natural gas injection with acid gas injection (i.e. CO2 injection). The study also intended to quantify the amount of natural gas that can be displaced with CO2 injection, and the overall economics of the project.
New Insight into the Synergism Between Engineered Water and Nonionic Surfactants for Improving Spontaneous Imbibition in Oil-Wet Carbonates
Authors: Souayeh M. , Al-Maamari R. S. , Aoudia M.
Published: April 2024

Altering the wettability of rock matrix to water-wet has been recognized as an effective approach to enhance oil recovery from fractured carbonate reservoirs. This can be achieved using various techniques, including but not limited to, water salinity/composition modification (engineered water) and surfactants injection. This study features an experimental evaluation of engineered-water-surfactant (EWS) performance in wettability alteration of oil-wet carbonate having high salinity formation water (196 g/L) and moderate temperature (75 °C), representative of an actual Omani carbonate reservoir.

Two commercially available polyethoxylated nonionic surfactants were used in this study. The surfactants were mixed to obtain an average ethylene oxide (EO) units equals to 12 (C13EO12). The surfactant solutions were prepared at concentration of 0.3 wt. % using diluted formation water (100 fold) and spiked with either 50 or 100 mmole/L of Mg2+ and Ca2+. The crude oil was acquired from the targeted reservoir. The experimental workflow included the following measurements: cloud point, interfacial tension (IFT) against crude oil, contact angle (CA) on calcite surfaces, and, spontaneous imbibition in Indiana limestone outcrops.

Results revealed that increasing the concentration of either Mg2+ or Ca2+ had a minor effect on the cloud point temperature (≤2 °C), despite the increase in salinity. On the other hand, increasing divalent ions concentrations further reduced the IFT by 1 order of magnitude and reduced the IFT equilibrium time. However, the minimum IFT value obtained was 0.06 mN/m, which still falls within the range of Winsor Type-I. From CA measurements it was found that low salinity nonionic surfactant was able to alter the wettability from oil-wet to weak water-wet state. Spiking the surfactant solution with 50 mmole/L of divalent ions proved to be more effective than 100 mmole/L as the latter concentration showed a negligible impact on the CA. A strong water-wet state (27°) was achieved after treatment with surfactant solution spiked with 50 mmole/L of Mg2+. Unexpectedly, the system that yielded strong water-wet state resulted in the lowest oil recovery by spontaneous imbibition (37 %). While, the remaining EWS systems were able to substantially improve oil recovery (69 - 74 %) compared with the reference low salinity surfactant system (51 %). One interesting finding; the additional oil recovery is inversely related to the difference between the cloud point of the EWS system and the testing temperature.

The findings of this study clearly indicate that strong water-wet state does not always result in high oil recovery from carbonates. The role of divalent ions in boosting the solubility along with the interfacial activity of nonionic surfactants is promising; it provides a new insight and a new approach for EWS implementation to obtain optimum synergism that leads to higher oil recovery.
Utilizing a Design of Experiment Approach in Reservoir Simulation for Pattern Balancing and Optimizing a Polymer Flood
Authors: Grover K , Saadi J Al , Farsi M Al , Shetty S , Villar J , Doroudi A
Published: April 2024

Improving the efficiency of polymer flood or enhancing the incremental barrel of oil per pound of polymer injected is one of the most important factors for a successful polymer project. In almost all the active polymer floods, total polymer injection and liquid processing capacity is limited with the original design. Utilizing polymer to its fullest extent is therefore imperative for effective reservoir management in a polymer flood.

A full-field polymer flood is made up of several patterns, and consequently polymer flood efficiency depends on pattern efficiency. The scope for optimizing patterns include identifying priority for Optimizing injection/production rates.Optimizing polymer concentration.

The key reservoir-level factors that affect a polymer flood are geology, voidage replacement, and in situ polymer viscosity and should be given due consideration in reservoir management. The paper outlines a novel way based on a straightforward simulation model for optimizing polymer flood.

Base case reservoir simulation model is used to represent the fulfilled polymer flood, capturing geology and polymer rheology and overall flow behavior. Then, a design of experiment is created with individual pattern's injection rate and concentration as primary variables. The objective function is defined to maximize sweep efficiency, oil recovery and polymer flood efficiency for short term interval. More than 1000 experiments were created and run to identify sensitivity of individual patterns. Further using Sobol and Morris analysis, relative ranking of patterns is done for all patterns with reference to individual and global objective function. To further ascertain impact on ultimate recovery, cases with identified pattern changes have been ran till end of field life and compared with the base case.
Experimental Evaluation of Treated Produced Water for Improved Oil Recovery in Carbonates
Authors: Hoecherl M. , Alshammari S. , Saleh S. H. , Ayirala S. C. , Yousef A.
Published: April 2024

This study comprises an experimental investigation and comparison of different brine compositions for waterflooding applications in carbonate reservoirs. In particular, a novel zero liquid discharge (ZLD) brine, which is obtained from produced water treatment and features no significant salinity, is benchmarked against conventional high salinity injection water. Such a study is essential to promote produced water reuse in waterflooding projects and achieve improved oil recovery.

A detailed characterization of interfacial properties as well as static and dynamic oil recovery tests were conducted using high salinity injection and treated produced water. To understand electrostatic interactions between interfaces, zeta-potentials of oil/brine emulsions and calcite nanoparticle/brine suspensions were measured at 25°C and 70°C. Furthermore, oil-brine interfacial tension (IFT) and contact angle measurements were carried out at reservoir conditions (70°C and 2200 psi). The contact angles of captive oil bubbles were examined on aged reservoir rock and crystalline calcite. Incremental hydrocarbon recovery was studied through a multi-stage Amott cell experiment and a high-pressure, high-temperature (HPHT) core flood at 70°C.

The zeta-potential results indicate a generally negative effective charge at both the oil/brine and the calcite/brine interfaces. Additionally, an electric double layer (EDL) collapse with increasing salinity and temperature is observed for both interfaces. The reduction in zeta-potential magnitude is accompanied by a decrease in electrostatic repulsion between the two interfaces, promoting oil-wet behavior. This observation is confirmed by the contact angle results, which display a wettability transition from a water-wet state for ZLD treated produced water to an oil-wet state for high-salinity injection water. The incremental recovery from spontaneous imbibition also showed this wettability trend. ZLD water resulted in an oil recovery increment equal to the recovery by high salinity water imbibition. Finally, the core flood revealed the full potential of ZLD treated water, yielding an incremental oil recovery of 4-5% after high salinity water injection in a carbonate core.

This work has demonstrated, for the first time, the potential of treated produced water for improved oil recovery in carbonates. Consistent trends were obtained from zeta potentials, contact angles, spontaneous imbibition, and core floods to confirm the wettability alteration capability of treated produced water to achieve incremental oil recovery. These findings would eventually promote produced water recycling/reuse and environmental sustainability in waterflooding projects.
Azimuthal Geosteering: New Opportunities Revealed by Advances in Ultra-Deep Resistivity Technologies
Authors: Elkhamry A. , Fouda M. , Al-Zawad A. , Al-Maimani A.
Published: April 2024

Ultra-deep electromagnetic (EM) technology has been used for over a decade for well placement operations. As the measurement primarily responds to resistivity variations around the wellbore, it has been used to map lithological boundaries and fluids enabling geosteering the well path in real time to the desired formations. Traditionally a multi-layer 1D geological model is constructed by inversion algorithms utilizing five measurement components of the EM signal. Recent advances in tool designs and computational capabilities enabled the utilization of the full nine EM measurement components to construct a full 3D model around the wellbore, hence enabling new opportunities in reservoir visualization, well placement decisions and fluid mapping in real time. This paper presents some real-life opportunities of azimuthal geosteering revealed by the ultra-deep resistivity 3D inversion.

Advancements in logging-while-drilling (LWD) tool designs including tilted EM transmitter and receiver antennas enabled the acquisition of all nine components of the EM field around an EM tool. Advanced algorithms and real-time transmission systems have been introduced allowing the visualization of the 3D resistivity volume around the wellbore in real time, providing insight into formation and fluid changes in all directions. Well placement decisions can now target optimal zones as defined by their resistivity in any direction around the wellbore and not only in the vertical plane as defined by 1D inversions. New operational workflows including intensive pre-well planning and collision avoidance monitoring have also been enhanced, accounting for any additional risks that could result from real-time azimuthal well path adjustments.

Ultra-deep resistivity 3D inversion was successfully used on several geosteering wells crossing multiple formations. Advanced computational methods were utilized in real time, which enabled several real time decisions to be made. The visualization of the resistivity volume around the wellbore revealed variations in all directions around the wellbore, uncovering more complex structures of the subsurface geology. New opportunities were enabled to include "turning" instructions into well placement decisions to maximize reservoir contact and improve petrophysical properties of the drilled interval. In addition, enhanced operational workflows ensured drilling and well collision risks were avoided.

This paper presents an integrated approach to utilize a newly developed 3D ultra-deep resistivity inversion technique to adjust well paths in all directions placing wells in the best reservoir properties.
Applying Particle Swarm Optimisation Technique to Calculate Rod Torque Limits for Wells and Preventing Impending PCP Rod Failures
Authors: Rodrigues J.
Published: April 2024

Most of the producing oil wells require some form of artificial lift for pumping production fluids to the surface (Bates, Cosad et al. 2004). The Progressing cavity pump (PCP) is considered as one of the most robust types of artificial lift method. About 10 to 15 percent of almost one million wells worldwide produce oil with the help of PCPs. PCPs are very efficient and can handle a range of viscosities, gas-liquid ratios, and solids production. Over the years, one of the most pressing concern of operators using PCPs in their Oil-fields have been, high workover costs and subsequent failures. If the operators do not take care of the PCP installation and take care of the PCP whilst start up, then the PCP efficiency gradually declines over time and the PCP fails at some point of time. This can be attributed to High Torque, Pump Deterioration, Parting of the Rods and other such failures. Due to the failure the financial costs are substantial accompanied by lost production, workover rig costs, replacement costs and intervention costs. To reduce failures operators are investing in real-time surveillance systems to monitor PCP performance using downhole measurements and raise alarms in case of abnormal events such as tripping's or failures. This is done by monitoring various parameters and then action is taken based on the operator's ability to discern the impending failure based on some signature trends. However, more often than usual at this stage it is already too late to do anything that could save the pump or the whole PCP system. Thus, it is important to move from a reactive to a proactive approach. This paper offers such an approach. Specifically, a analytical solution is proposed to proactively calculate and suggest a Torque value within which the PCP should work to deliver the required deliverability from the reservoir. statistical techniques for dimensionality. This analytical solution combines engineering principles with mathematical models to detect a suitable torque long before the PCP crosses this value in an actual well startup scenario. Supervisory control and data acquisition (SCADA) systems and data historians bring about an increased value by optimizing the work procedure or Workflow. Particle swarm optimization (PSO) is one such technique that can be used in conjunction with the workflow to monitor an important parameter such as Rod torque to enable the production engineer to calculate the most suitable hydraulic torque limit for the oil and gas well where a PCP (Progressive cavity pump) is installed. Thus, if a situation arises where the Torque limit is not calculated correctly, this implementation of this analytical solution which is implemented in Python programming language can prevent the wrong Torque value from being calculated and result in saving the PCP pump.
Innovative Near-Online Flow Assurance Tool for Pipeline Historical Performance Analysis
Authors: Natta A. , Tiozzo A. , Montini M. , Hester K. C. , Di Lullo A. G.
Published: April 2024

This paper introduces an innovative in-house developed near-online flow assurance simulation concept for continuous monitoring of pipeline performance, such as deposition of solids. The tool can be retrofitted to the analysis of brown fields without specific requirements for the installation of customized instrumentation hardware. In addition to detailing the tool, a field application case is discussed to provide insight on the pipeline historical performance.

The tool is based on a dynamic multiphase flow simulator and relies on the presence of a Digital Oil Field (DOF) system. The field data are acquired by the tool directly from the remote DOF database and used as input to automatically generate, run, and post-process various simulations representing stable production conditions of the field. The tool can perform periodical runs and the results obtained populate a historical database of the pipeline performance for further analyses.

The near-online flow assurance tool has been applied to investigate the potential wax deposition in two subsea multiphase pipelines. Starting from the second year after the field start-up, due to the reservoir depletion, the temperature at riser base had fallen below the wax appearance temperature (WAT). Laboratory analyses confirmed the potential for wax deposition under current and past operating conditions and the use of wax inhibitor at the wellhead was recommended. However, there was uncertainty regarding the inhibitor effectiveness since pigging activities have been conducted unfrequently and on a discontinuous basis. Therefore, it became essential to monitor the pressure drop trend of the pipelines over time as a non-invasive wax detection technique.

The analysis has been conducted over a seven-year period since the first start-up of the field. Given that the discrepancy of simulation data from field data turned out to be within the simulation's uncertainty range and it does not change throughout the whole timespan of the analysis, the tool has proven the effectiveness of the injected wax inhibitor.

A traditional flow assurance analysis workflow would have required large time-consuming manual input for the case-study presented, since a substantial number of field data has been processed. This renders the traditional approach impractical. The near-online tool has proven to be capable and robust for different flow assurance applications by reducing the time effort and the error probability linked to manual input. In future, other pipeline studies will benefit from the definition of the presented workflow.
Improved Water Management Through the Usage of Sulfonated Polymers
Authors: Al-Murayri M. T. , Kamal D. , de Kruijf A. , Imqam A. , Andrianov A. , Liu E. , Al-Rawahi S.
Published: April 2024

Oil and gas production uses large volumes of water for injection during polymer flooding and hydraulic fracturing operations. The same operations generate large volumes of wastewater, of which produced formation water and flowback water make up the dominant volumes. The availability of fresh water is a growing challenge in many regions of the world and major oil companies take these challenges seriously and recognize their need to preserve fresh water. They report operations in water-scarce areas in their annual sustainability reports and they strive to reduce and ideally eliminate freshwater intake for their operations by increasing recycling capacity. Reusing high salinity water for hydraulic fracturing and polymer flooding applications is a challenge as high salinity water negatively impacts the economics and success rate of these treatments as the apparent viscosity of standard HPAM is affected by the high salinity. Desalination of these high salinity water sources can be executed by thermal desalination techniques which are not cost effective at these large water volumes. Altering the HPAM polymer by adding ATBS or AMPS monomer instead will enhance the viscosity and stability of the polymer solutions at high salinity. These sulfonated polymers showed excellent performance in using saline water in hydraulic fracturing operations, where friction reduction during injection and proppant carrying capacity are the main requirements. When using the right fraction of ATBS/AMPS monomers in the polymer, high salinity (even combined with high temperature) reservoirs can be flooded with sulfonated polymer solutions to obtain increased recovery as indicated by a field case.
Enhancing LNG Production Efficiency by Mitigating Warm Ships Loading Challenges
Authors: Al Kalbani Mohammed
Published: April 2024

Oman Liquefied Natural Gas (OLNG) terminal faces persistent hurdles in maintaining high production rates during warm ship loading, a challenge magnified by the risk of over-pressurization in the fuel gas system. This scenario, occurring once a month on average, poses environmental threats due to potential unplanned flaring, hindering LNG throughput. Crucial to these operations are panel operators who strive to curtail flaring while sustaining production and environmental integrity.

This paper unveils a strategic framework addressing the multifaceted challenges encountered during warm ship accommodation. These initiatives not only boost operational and energy efficiency but also elevate operational excellence and asset performance within the LNG terminal.

One pivotal measure introduced additional activities in the Ship Activity Schedule, fostering collaborative efforts between Ship Officers, the Marine Department, and Operations Department. This collaboration streamlined risk management during Ship Tank Cool Down, offering better control over the fuel gas system and reducing flaring incidents, contributing significantly to operational excellence.

Another critical initiative mandated the presence of a Marine Pilot during Cool Down Operations, ensuring prompt interventions and minimizing over-pressurization risks while enhancing operational efficiency.

Technical guidelines underwent optimization, aligning with contemporary processes and technology, enhancing performance standards, asset efficiency, and operational excellence.

Internal tools, including the Fuel Gas Balance Dashboard, provide comprehensive visualizations of system performance, identifying optimization opportunities and enhancing energy efficiency, further amplifying operational excellence and asset performance.

A comprehensive Fuel Gas System Surveillance Tool enables in-depth performance analysis, driving continuous improvement and directly impacting asset efficiency.

The implementation of these strategic measures and tools at OLNG has effectively managed warm ship loading challenges, significantly reducing unplanned flaring, preserving the environment, and maintaining high production rates. This blueprint serves as a guiding reference for LNG terminals facing similar challenges, emphasizing the significance of proactive measures and collaboration in ensuring efficient operations, minimal environmental impact, and optimized energy utilization and asset performance.
Unveiling Success From Cyclic Steam Injections for Heavy Oil Recovery in India and the Orinoco Oil Belt
Authors: Rodríguez J. R. , Naranjo P. A. León , Molina J. W. , Molina J. D. , Molina F. , Matute A. K.
Published: April 2024

This study highlights the successful implementation of the cyclic steam injection process in a heavy oil field in India and in numerical reservoir simulation studies in the Orinoco Oil Belt. It focuses on optimizing key variables such as steam quality, reservoir energy transfer, well-productivity enhancement, and environmental impact. The methodology incorporates an innovative, comprehensive high-quality steam generation system, producing steam qualities ranging from 95% to 99%. In the Orinoco Oil Belt, the efficiency of injecting high-quality steam was evaluated within an extra-heavy oil formation situated at a depth of 3010 feet and under a pressure of 1100 psi. Numerical results from the Orinoco Oil Belt demonstrate a substantial impact of high-quality steam, achieving a 400% increase in oil extraction rates and an additional 28% increase in accumulated oil compared to conventional methods. This innovative system requires 8% less fuel for equivalent energy generation and leads to a 7.7% reduction in non-condensable gas production. These findings served as the foundation for designing a cyclic steam stimulation (CSS) pilot test in India. In preparation for the pilot test in India, a meticulously designed steam generation system with superheaters and cyclone separators was developed. This system demonstrates its capability by generating steam with qualities ranging from 95% to 99%, utilizing LPG as fuel. Facing challenges such as average reservoir depths of 3700 feet, low permeabilities (1000-2000 mD), oil viscosity of 20000 cP@140°F, and a pressure of 1650 psi, the execution of cyclic thermal stimulation involved 7 wells subjected to injection pressures between 1500 and 2100 psi, and temperatures of 300°C, maintaining steam flow rates from 3.0 to 4.0 tons per hour. Following thermal stimulation, oil production rates showed an overwhelmingly positive outcome with an average increase of 420%. The innovations and best practices presented in this study will facilitate the adoption of efficient thermal processes, ensuring a higher recovery factor, reduced water, and fuel consumption, and minimizing environmental impact. Operationally, non-productive periods were reduced to less than 2%, achieving steam generation with a quality exceeding 90%.
Rejuvenate The Production: A Success Story of Old Wells Revival Using Chemical Diversion
Authors: Raisi Omar Al , Kurniadi Stevanus Dwi , Mowad Benjamin , Lawati Yousuf , Hassan Karim , Salmi Fathiya , Hegazy Ahmed Elsayed
Published: April 2024

Operators are challenged to deliver gas in an ever-changing gas demand market. During periods of low commodity pricing, capitol spend on appraisal or new projects can be heavily reduced. To deliver in this type of environment, operators utilize cost-effective solutions using existing resources. One industry example is the revival of gas production by stimulating mature wells in the Saih Nihayda field in the Sultanate of Oman.

Gas wells in the Saih Nihayda field are typically completed with a combination of perforation in the sections with good rock quality and hydraulic fracturing in the tighter rock layers. As the field matures beyond its first decade, there remains a significant quantity of under stimulated wells in the field. Wells that currently produce below economic gas rates offer a substantial hydraulic fracturing opportunity. Candidate selection is key to unlocking these untapped reserves. Candidate criteria include reservoir properties, remaining gas in place, completion limitations, and well intervention requirements.

Depletion and lengthy perforation intervals present challenges in these wells. The ideal hydraulic fracturing technique would be able to effectively stimulate more than 100 m of clustered perforations and flow back almost immediately after fracturing operations. The fracture growth must be able to cover the entire perforation interval utilizing chemical diversion techniques and material. To validate the proppant placement distribution of the entire treatment, radioactive tracer is pumped and logged during and after pumping. In Saih Nihayda field, wells stimulated using these methods produced above expectations and met economic flow rates.

A fit-for-purpose workflow for candidate selection criteria and the process for stimulating sandstone gas wells in Middle East brownfields was developed. A unique diversion technique and strategies for long perforation intervals in depleted gas reservoirs is introduced, with results confirmed using surveillance techniques.