bluuebunny/crossref_metadata_2025 huggingface dataset:
Seismic Inversion of Reservoir Porosity with Neural Network Technology-A Case Study in Central Iraq
Authors: Xu Chao , Chen Chunqiang , Deng Jixin , Yang Tao , Yang Hong , Bai Hua
Published: March 2022

Understanding the interwell distribution of the reservoir porosity is of great importance for well deployment to improve EOR. Seismic inversion with seismic and logging data is an efficient method to obtain the reservoir porosity. This study aims to demonstrate the spatial distribution of the reservoir porosity in an important formation in Central Iraq. 3D seismic attributes and logging data were combined to invert the reservoir porosity through neural network technology. The migrated 3D seismic volume, inverted P-wave impedance volume, seismic attributes and the logging data of 10 wells, were employed for training neural networks. Based on the training network, we generated the 3D porosity volume. To verify the accuracy of the inverted result, the inverted porosity were compared with those from the logging data of other 5 wells. Data slices were extracted with seismic horizons to show the lateral distribution of the reservoir porosity. The validation error shows the best multi-attribute pair is the pair of square root of P-wave impedance, quadrature trace, and instantaneous frequency. Neural network was trained with the three attribute pair. Analysis of the correlations between the predicted and the logging porosity showed the correlations from neural network training were higher than those achieved with multi-attribute regression. The porosity from the logging data of the 5 wells, which were not evolved in neural network training, coincided well with those from the inverted 3D porosity volume. That verified the accuracy of the inverted porosity volume from neural network inversion. Vertical sections and lateral slices of the inverted porosity volume were extracted to demonstrate the vertical and lateral distributions of the porosity, respectively. Data slices showed that the porosity were higher in the north and south area, and lower in the middle area. The study shows the porosity inverted from neural network technology is more reliable than that from muti-attribute regression. In addition, through this study, we demonstrate the porosity distribution in the project area. The new knowledge of the spatial distribution of reservoir porosity provides important guidance to the well deployment in the oilfield.
Using Data-Mining Crisp-DM Methodology to Predict Drilling Troubles In Real-time
Authors: Gharbi Salem , Al Majed Abdul Azeez , Abdulraheem Abdulazeez , Patil Shirish , Elkatatny Salaheldin
Published: March 2022

Drilling is considered one of the most challenging and costly operations in the oil and gas industry. Several initiatives were applied to reduce the cost and increase the effectiveness of drilling operations. One of the frequent difficulties that faces these operations is unexpected drilling troubles that take place and stops the operation, resulting in losing a lot of time and money, and could lead to safety issues culminating in a fatality situation. For that, the industry is in continues efforts to prevent drilling troubles. Part of these efforts is utilizing the artificial intelligence (AI) technologies to identify troubles in advance and prevent them before maturing to a serious situation. Multiple approaches were tried in the past. However, errors and significant deviations were observed when comparing the prediction results to the actual drilling data. This could be due to improper design of the artificial intelligent technology or inappropriate data processing. Therefore, searching for dynamic and adequate artificial intelligent technology and encapsulated data processing model is very essential.

This paper presents an effective data-mining methodology to determine the most efficient artificial intelligent technology and the applicable data processing techniques, to identify the early symptoms of drilling troubles in real-time. This methodology is CRISP-DM that stands for Cross Industry Standard Process for Data Mining. This methodology consists of the following phases: Business Understanding, Data Understanding, Data Preparation, Modeling, Evaluation and Deployment. During these phases, multiple data-quality techniques were applied to improve the reliability of the real-time data.

The developed model presented a significant improvement in identifying the drilling troubles in advance, compared to the current practice. Parameters such as hook-load and bit-depth, were studied. Actual data from several oil fields were used to develop and validate this smart model. This model provided the drilling engineers and operation crew with bigger window to mitigate the situation and resolve it, prevent the occurrence of several drilling troubles. In addition to significant time and cost savings, CRISP-DM provided the artificial intelligent experts and the drilling domain experts with a framework to exchange knowledge and increase the synergy between the two domains significantly, leading to a common and clear understanding, and long-term successful drilling and AI teams collaboration.

The novelty of this paper is the introduction of data-mining CRISP methodology for the first time in the prediction of drilling troubles. It enabled the development of a successful artificial intelligence model that outperformed other models in predicting drilling troubles.
First Successful ESP-DST Well Test in Heavy Oil Unconsolidated Sandstone in Caspian Sea
Authors: Dosmukhambetov Issatay , Taubayev Bakhytzhan , Yesbolov Ualikhan , Sadykov Aikhan , Shmalin Muratbek , Akbayev Beibit , Kaipov Yermek , Ramatullayev Samat , Kuvatov Daniyar , Amanbayev Olzhas , Khaziev Bulat
Published: March 2022

The Caspian offshore is a prolific area for hydrocarbon accumulation. Since it is an offshore, it is a challenging area in terms of strict environmental regulations and safety. At the early stage of the project it was clear, that formation properties of the exploration well require artificial lift assistance to produce during well testing. Therefore, designing proper DST string with ESP was crucial to the success of well testing.

This paper describes unique combination of technologies and techniques that enabled a DST with ESP in combination with the Y tool, that provides capabilities to run thePLT below the pump. Also, one of the main challenges of well testing operation was to handle heavy oil fluid at surface. Being in environmentally sensitive area, designing a surface well testing equipment in a limited footprint, that enables efficient separation and disposal of heavy oil was very critical. Another challenge was unconsolidated formation with the high risk of sand production under drawdown, therefore downhole testing string and ESP pump supposed to withstand large quantity of solids during the production.

The key technology that enabled testing was a new generation of abrasion resistant ESP pumps, that are designed to handle extensive solids production. The heavy oil also posed a number of risks. The surface equipment was specifically designed to heat oil in the tanks and if required to mix with diesel before flaring operations.

Local regulation does not permit production during the night time and allows limited number of days for well testing. Therefore, well testing design must enable to acquire all necessary information within short period of test duration. The real-time data transmission and interpretation was a key to achieve main goal of the testing in exploration well - to accurately characterize the reservoir.

This was the first successful ESP-DST in Caspian Sea. Despite of many challenges, the technologies that were selected for well testing operation was proven to be reliable. This allowed Operator to untap previously not accessible hydrocarbon reserves.
Digital Lighthouse: A Scalable Model for Digital Transformation in Oil & Gas
Authors: Cadei Luca , Rossi Gianmarco , Lancia Lorenzo , Loffreno Danilo , Corneo Andrea , Milana Diletta , Montini Marco , Purlalli Elisabetta , Fier Piero , Carducci Francesco , Nizzolo Riccardo
Published: March 2022

Energy companies are latecomers to digitization with respect to other business, but new technologies like Big Data, Cloud infrastructure and Artificial Intelligence offer great opportunities.

Here we present an integrated approach to the digitalization of an O&G plant aiming to offer operator safety enhancement, production optimization and reduction of the environmental impact to maximize the asset value. This has been accomplished by complex and continuous work powered by the people who are the engine and the real target of the digital transformation process.

In the key study hereby presented, an all-round effort has been made to empower the operator's everyday work with digital and innovative tools supporting reservoir, maintenance, production and HSE workflow. Starting from a number of various legacy systems, a single integrated dashboard was built: The Integrated Operation Centre (IOC). IOC is now available on PC and smartphones to all site personnel both at the operational and managerial level.

New innovative systems were developed and deployed into IOC to capitalize on the data acquired during years of plant activities. Machine learning and advanced analytics solutions provide new daily insight on how to efficiently schedule maintenance operations and avoid off-specs and downtime on critical equipment, while complex production optimizers help technicians react to unexpected situations and maximize production.

Via IoT (Internet of Things) and portable devices, new tools and workflows were deployed onsite to ease the work and enhance the safety of workers with focus on usage of PPE and providing rapid information to locate workers during emergency situations.

People from both site and company headquarters ensured the success of the digital transformation by working together in an Agile Method during the development phase and by coaching in the roll-out phase. New professional roles, like data scientist and big data engineers, joined effort with experienced operators to ensure the success of this journey. This cooperation was at the basis of a comprehensive change management effort, which ensured a smooth and constant change in the way the personnel thinks, acts and reacts. This, we believe, is at the very heart of any fundamental transformation, being it digital or not.
Experimental Study on the Impact of Protective Packages, Iron, Oxygen and Stainless Steel on Polymer Stability
Authors: Al-Maamari Rashid S. , Souayeh Maissa , Al-Busaidi Intisar K. , Mansour Ahmed , Al-Riyami Omaira , Al-Mjeni Rifaat
Published: March 2022

Oxidative degradation of polymers is caused by combination of Fe2+ and O2 resulting in viscosity loss. During lab tests, synthetic brine without Fe2+ is commonly used. However, most lab and field set-ups are made of stainless steel (SS) which is a possible source of Fe. Therefore, this study investigates the impact of Fe2+ and O2 contents on polymer stability with/without contact of SS in presence/absence of protective packages (ITW and oxygen scavenger).

Polymer stability tests were conducted for 1 week at ambient temperature under different O2 concentrations. Four polymer systems were evaluated (without additives, with ITW, with oxygen scavenger and with ITW+oxygen scavenger). Samples were stored in SS and glass bottles. Different Fe2+ concentrations were added to the solutions in the glass bottles. The viscosity of the polymer solutions was measured at anaerobic conditions at different intervals.

Viscosity results for polymer samples aged in glass bottles showed that ITW alone or in combination with oxygen scavenger is able to maintain polymer stability up to Fe2+ and O2 levels of 2.5 ppm and 1500 ppb, respectively. At atmospheric condition, these systems were found efficient as the maximum obtained viscosity loss was < 14%. While samples containing only oxygen scavenger maintained polymer stability up to Fe2+ and O2 levels of 2.5 ppm and 500 ppb, respectively, but experienced severe degradation when exposed to atmosphere. Similarly, blank samples experienced severe degradation after exposure to atmosphere and the stability was maintained up to Fe2+ and O2 levels of 0.5 ppm and 500 ppb, respectively.

Polymer solutions stored in SS cells experienced noticeable viscosity loss indicating that Fe is released from the SS and contribute to polymer degradation. The blank samples and samples containing oxygen scavenger were stable up to O2 level of 500 ppb. Addition of ITW into these polymer solutions boosted its viscosity stability up to O2 level of 1500 ppb. Exposing polymer samples containing either ITW or oxygen scavenger to atmosphere resulted in severe degradation of around 42% which is higher than the viscosity loss of the blank sample (28%). However, when both ITW and oxygen scavenger were added to the polymer solution and exposed to atmosphere, the viscosity loss was reduced to 26%.

This study showed that polymer stability in presence/absence of protective packages can be maintained at initial O2 level of 500 ppb. These findings are directly related to polymer stability during polymer preparation which needs to be considered in any polymer flood design. As protective packages might come handy for maintaining polymer stability in the reservoir, this study can aid in selection of the most feasible protective packages and water treatment requirements.
3D Enhanced Subsurface Data Visualization and Integration for Effective Horizontal Well Multi Transverse Fracture Development on a Clastic Tight Gas Field in Oman
Authors: Al-Suleimani Ahmed Abdullah , Chavez Juan Carlos , Abbass Hazim , Smaoui Radouan , Abassi Ahmed , El Hamal Bachir , Bachir Aissa , Poludasu Srichand , Yi Mi Chin , Attia Bilel , Ouenes Ahmed
Published: March 2022

Horizontal wells with multiple transverse fractures were defined as the key well architecture and completion strategy oriented to develop clastic tight gas accumulation otherwise impossible to be developed with vertical wells. However, a detailed evaluation during early deployment indicates the need for an integrated subsurface platform (ISP) covering geophysics, geology and geomechanics, to support well placement, well orientation and hydraulic fractured design.

Detailed subsurface characterization was used to build the ISP. Geomechanical logs estimated using the drilling data, as wells as, wireline logs are used to define engineered completion strategies. The ISP provide us with three dimensional properties maps capturing lithogical, petrophysical and geomechanical properties distribution, this allow the identification of the properties anisotropy coveing key variables including, elastic properties, in-situ stress variation, stress rotation across the field and stress anisotropy, thecombination of the predicted stimulated reservoir volume and the dynamic model, both part of the ISP, were used to access potential production forecast for selected well locations.

The ISP support the identification of geological sweet spot to definelanding zones and optimizing the hydraulic fracturing to improve the production performance. We will discuss how the geomechanical evaluation provides us the spatially varying stress magnitude and stress orientation and strain across the tight reservoir units. The use of the geological and geomechanical data within the ISP can be used to estimate geomechanical half lengths that are used to improve fracture design. We will also discuss how completion optimization and number of perforation clusters can be defined to maximize gas production based on a better understading of the special variation of petrophysical, geomechanical and lithological properties across reservoir units.

The described integrated subsurface platform can be used to help optimize horizontal well placement, well orientation and fracture completion design. It will be discussed the procedures and process of integration geophysical, geological and geomechanical reservoir properties into the ISP, as well as, how this was used to support the continuous development of these tight gas accumulation in Oman.
Reproducing Core Wettability in Laboratory Core Restorations and the Influence of Solvent Cleaning on Carbonate Wetting
Authors: Piñerez Torrijos Iván Darío , Puntervold Tina , Strand Skule , Hopkins Paul , Aslanidis Panagiotis , Yang Hae Sol , Sundby Kinn Magnus
Published: March 2022

With the current reservoir engineering technology, it is not possible to measure wettability at downhole conditions. Therefore, laboratory work is necessary to correctly assess this parameter. Countless efforts have been made by reservoir engineers to obtain decent estimates of reservoir wettability. However, in many cases this objective remains elusive. This means that the current special core analyses (SCAL) protocols have not overcome this hurdle, and new approaches must be tested.

In this work, the effects on wettability of two different sets of organic solvents are studied in carbonates, and a new cleaning and restoration protocol is tested to reproduce wettability in carbonate core samples. Two water-wet chalk core plugs were restored with the same initial formation water saturation (Swi=10%), and then were saturated and aged in crude oil to create an initial wetting. Spontaneous imbibition (SI) experiments confirmed the reproducibility of the restoration process used.

After spontaneous imbibition, the two cores were cleaned with different methods, the first core plug was subjected to a mild cleaning process (kerosene-heptane) and the second one was cleaned with a harsh method (toluene-methanol). It was found that the mildly cleaned chalk core was slightly water-wet, and the harshly cleaned core appeared to have changed to a more water-wet state. Therefore, the solvent pair, kerosene-heptane, preserved more polar components at the carbonate surface than the toluene-methanol pair, the latter, was more effective in solvating and removing polar components from the rock surface, showing increased capillary forces in the SI test with heptane.

The last stage of the study aimed to reproduce the first induced wettability, this was carried out in two cores after a mild cleaning process. It was possible to closely reproduce the initial wetting of these cores. This was accomplished by controlling the injected amount of mild cleaning solvents and crude oil during the second restoration process. These results represent a successful first phase of research towards wettability reproduction and improved reservoir wettability evaluation. Furthermore, it represents a solid and modern alternative to the traditional SCAL approach.
An Iterative Approach to Enhance Frac Design and Economics While Developing Tight Gas Reservoirs
Authors: Yilmaz Koray , Umul Burc , Madha Moosa
Published: March 2022

These are exciting times for unconventional resource development across North America. This success has proven to be a driver for the rest of the world to attempt to emulate the game-changing results found in the industry. As a consequence, improved horizontal drilling and hydraulic completion technology are currently being disseminated to the rest of the world, where operators are seeking to replicate the North American success in tight reservoirs and shale plays of interest. This being further fueled by higher gas prices than are awarded in North America.

This paper introduces a work-flow process to describe how tight gas-sand potential was discovered in the Mezardere Formation in the southern part of the in Thrace Basin in NW Turkey. The process began with the development of an improved understanding of geology and reservoir characterization followed by the application of North American drilling and completion technologies to commercially extract hydrocarbons from previously uneconomic resources.

Design of hydraulic fracturing, including pad volumes, proppant and gel concentrations, stage volumes and typical pressure profiles, production profiles and well design parameters are established. The content also presents how completion designs can be improved in a vertical well application in existing wellbores as a means to mitigate capital risk in a horizontal development plan.

The paper concludes by showing how the successful extraction of commercial gas production from heretofore uneconomic portions of the Thrace basin has the potential to change the energy future in Turkey via dramatically improved production results over previous conventional completions. When results were made public, the basin garnered attention from many large E&P Operators. The results proved that improved economic enhancement of deep basin unconventional resources as possible; thereby changing and accelerating development plans for this type of play.
Deterministic Approach Towards Well Intervention Candidate Selection & Quantification of Parameters in Esp & Jet Pump Wells
Authors: Varma Nakul , Koshatwar Yash , Kumar Manish , Savelyev Anatoly , Jha Aneesh , Kumari Rekha , Nagar Ankesh , Srivastav Preyas , Srivastav Pranay , Nekkanti Satish , Bohra Avinash , Veermani Sanjeev
Published: March 2022

This paper aims to describe a model created to determine various important parameters to monitor oil producer wells with different artificial lift types: Jet Pump (JP) and Electric Submersible Pump (ESP) of Mangala & Aishwarya fields. The fields contain medium gravity viscous crude (10-40cp) in high permeability (1-5 Darcy) sands. In order to overcome adverse mobility ratio and improve sweep efficiency, polymer flooding was adopted. As the Polymer flooding proceeded, polymer breakthrough in producer wells was observed. The major challenges faced in producer wells is polymer/scale depositions realized during well interventions. This issue has surfaced in field due to polymer breakthrough in oil producers and mixing of produced polymer concentration in well fluid with scales, wax or other bivalent ions. Major concerns due to polymer deposition included, fouling of artificial lift system, decrease of well uptime, jet pump (type of artificial lift) & ESP efficiency decrease.

ESP & Reverse jet pumping are the major artificial lifts for the field, where power fluid is pumped through annulus and production is taken through tubing. With continued jet Pump fouling due to Polymer, wax & scale agglomerate, well uptime decreased. During jet pump redressing, polymer deposition has been observed in the body X-over (reservoir liquid path), check valve assembly, throat and spacer nozzle to throat inside jet-pump. Thus, a necessity was felt to address the issue with a proactive approach. Continuous chemical dosing method was tried and proven successfully, but it was not cost effective. Hence empirical based modelling was required which can quantify these parameters to plan for well intervention & well clean-up jobs. The developed model is "intelligent" and determines various parameters like – Productivity index(PI) of jet pump well without having suction pressure data, jet pump nozzle loss coefficient, ESP pump efficiency (ESP wear), annulus deposition & debris deposition in tubing reducing effective ID of annulus & tubing respectively. The model calculates from every newly logged Multiphase flowmeter rates, water cut, Annulus pumping pressure & tubing head pressure (THP) events and determines its approach of marking the risk levels of a well. With continued JP/ESP fouling, tubing deposition & PI drop due to Polymer, wax & scale agglomerate, well uptime & production rate is decreased.
New Synergistic Surfactant Mixtures for Improving Oil Production in Carbonate Reservoirs
Authors: Xu Limin , Han Ming , Cao Dongqing , Fuseni Alhasan
Published: March 2022

The paper presents the development of new surfactant formulations composed of various low-cost and low-performance surfactants to make them high performance products for high temperature and high salinity carbonate reservoirs. The objective of this study is to optimize the surfactant chemistry by mixing different kinds of surfactants (ionic, nonionic, and amphoteric), which results in significant synergistic effects in interfacial properties to improve oil production at the given harsh conditions.

The optimal mixing surfactant ratios were determined according to the brine-surfactant compatibility, microemulsion phase behavior, and the interfacial tension (IFT) between oil and surfactant solutions in high salinity brine and at 90˚C. Comprehensive performance of the surfactants was evaluated, including adsorption of the surfactants onto the carbonate rocks and the long-term stability at 95˚C. The coreflooding displacement experiments were performed using carbonate core plugs at 95˚C to evaluate the potential of the optimal mixing surfactants in improving oil production.

Three formulations composed of two types of low-cost surfactants were developed in this study. The mixing surfactants were chosen based on moderate electrostatic interaction among the surfactants. It appeared the synergistic effect between the mixing surfactants was enhanced with increasing temperature. Although the IFT of the individual surfactants with crude oil was in the range of 100mN/m, a significant IFT reduction in the magnitude of 10−2 - 10−3 mN/m was observed by mixing the surfactants. A salinity scan showed that the IFT values maintained a value of 10−2 mN/m in a wide salinity range, which demonstrated the robustness of the surfactants mixtures. In microemulsion phase behavior studies, these mixed surfactant solutions in the presence of crude oil exhibited Winsor Type III emulsions. The static adsorptions of the mixed surfactants were lower than the individual surfactant adsorption. All this indicated the feasibility of these formulations for their applications in the harsh reservoir conditions. The results of coreflooding displacement tests demonstrated significant oil production improvement beyond water flooding.

This work provides an efficient way to get surfactant formulations by mixing low-performance and low cost surfactants to obtain high performance in improving oil production under the harsh conditions.
Experimental Assessment of the Viability of High Temperature Steam Foam Applications
Authors: Jones Sian , Bos Robert , Lastovka Vaclav , Farajzadeh Rouhi , Riyami Mohammed
Published: March 2022

The efficiency of oil processes depends on the product of volumetric sweep and microscopic sweep. In oil recovery by steam injection the microscopic sweep is generally good; however, obtaining a good volumetric sweep can be challenging. This is caused by low density and viscosity of the injected steam combined with the reservoir heterogeneity, in particular existence of thief zone. Consequently, the steam utilization factor measured by steam-to-oil ratio (SOR, kg steam/bbl of oil) for many steam-flooding projects becomes poor. All these issues can be addressed by a successful application of steam foam technology.

In steam foam applications, steam (plus a non-condensing gas) is injected simulateneously with a surfactant solution. Under the favorable injection conditions a foam is formed inside the reservoir leading to significant reduction of steam mobility and can eventually improve sweep efficiency.

In the literature many successful steam foam pilots have been reported. However, most of these applications are at relatively shallow reservoirs with low pressures and thus low temperatures. In our paper we investigate if steam foam can also be effectively used for applications at high steam temperatures, significantly exceeding 200°C.

To test the viability of steam foam technology at high temperatures, we have tested the stability of multiple surfactants at reservoir conditions. For those surfactants that showed good stability, core flood tests have been carried out to test the ability to form foam and to assess the resulting foam strength. Steam foam tests have also been carried out at temperature up to 240°C.
Well Performance Analysis in Shale/Tight Gas Reservoirs: Case Study Review
Authors: Haghshenas Alireza , Hamedpour Mohammad
Published: March 2022

In recent years, the shale and tight reservoirs have emerged as one of the top resource plays for securing the world energy demand. Because of extremely low permeability nature of tight reservoirs, the advanced drilling and completion techniques are required to adjust economic production from these reservoirs. The current industrial practice is to drill long horizontal wells with multi-stage hydraulic fractures. The goal of multi-fractured horizontal well is to create a larger contacted area between the well and tight rock and in turn, make it easier for the fluid to flow toward the producing well. However, as development proceeds, the analysis of the data and accurate forecasting of the well performance is still facing challenges. In fact, as more data become available, it is becoming more clear that the conventional reservoir engineering may no longer be accurately valid to analyse the production data of shale reservoirs.

As a traditional evaluation process, the early-time production rate (IP) is used as a proxy for ranking the well performance and estimating the ultimate recovery (EUR) and, therefore, forecasting the economic viability of individual wells. However, as it is shown in this paper that the IP analyse is not the most accurate measurement and sometimes can be indeed a misleading parameter in shale/tight wells evaluation. Alternatively, more advanced reservoir engineering tools and parameters are required to interpret the performance of the well and forecast the production of shale reservoirs.

This study uses production data analysis to estimate the productivity trend of shale wells in the reservoir of interest. Our dataset is limited to a restricted geographic area with presumably consistent geological properties such as porosity, water saturation, pressure, and temperature. With limited variation in reservoir properties, the flow trend of the well becomes a good metric for completion efficiency.

The production data from a few typical shale gas wells are provided and the well performance is evaluated using rate transient analysis tools. The long-term production forecast of the wells is then estimated using empirical models. The results of this study would help operators/investors to better understand the challenges they may face with as well as possible opportunities in shale reservoirs. This study would also help operators to decide about the best completion approach to achieve optimal production within a shale region.
Water Injectivity Decline in an Omani Oil Field: Possible Causes and Mitigation
Authors: Al-Shabibi Ibtisam , Naser Jamil , Al-Maamari Rashid S. , Karimi Mahvash , Al-Salmi Ahmed , Al-Qassabi Hajir
Published: March 2022

Treated oilfield produced water is injected into reservoirs to increase the depleted reservoir pressure and enhance oil recovery. The main challenges in this process are injectivity decline and high tubing head pressure (THP) which is most often caused by the deterioration in the reservoir permeability.

This investigation focuses on identifying root causes behind injectivity decline in a sandstone reservoir in Oman. Acid stimulation has been applied to improve the reservoir permeability, but it turned out to be non-feasible due to frequency of such interventions and high associated costs. Several factors, such as injection water quality and reservoir mineralogy, can adversely affect the reservoir permeability and cause injectivity decline. Various approaches to tackle this problem have been adopted in this study including; water analysis, scale modeling, formation damage simulation and core flooding experiments.

The scale modeling results showed compatibility between formation and injection water where the scaling potential for both barium sulphate (BaSO4) and calcium carbonate (CaCO3) scales were unlikely to form at reservoir conditions. Injection water analysis showed that, in some cases total suspended solids and oil content exceeded the recommended limit, which might contribute to reservoir permeability decline. XRD analysis of the reservoir core samples revealed that fines and expansive clays are the main components. The core flooding experiments demonstrated that reservoir pore throats get plugged due to two main factors; the suspended solid particles present in the injected water and swelling clays present in reservoir core samples. The formation damage simulator showed that fines migration and clay swelling are the two main possible formation damage mechanisms. To enhance the water injectivity process, the use of a clay swelling inhibitor along with a filtration system to remove suspended particles in the injected water are recommended for the reservoir studied.
Nimr Polymer Project: the Results of Multi-Well Trial in the Medium-Heavy Oil Reservoir with Strong Bottom Aquifer
Authors: Mjeni Rifaat , Gharbi Mohammed , Lawati Sakeena , Dickson Sara-Jane , Ismaili Abdul Rahman , Hashmi Mohammed , Amri Ibrahim , Belushi Khalid , Farajzadeh Rouhi , Glasbergen Gerard , Karpan Volodimir , Anand Adi , De Kruijf Sander , Lomans Bart , Wever Diego
Published: March 2022

Efficient production of heavy oil from the reservoirs with strong bottom aquifer has proven to be a challenge. While providing enough energy to produce the field under the primary depletion, the strong bottom aquifer in combination with unfavorable oil/water mobility contrast leads to rapid development of water coning thereby limiting oil recovery. Drilling of long horizontal producing wells in the upper part of the oil column maximizes the distance from the aquifer and allows relatively high production rates. This slows down the water cone development and increases primary recovery. Even with further optimization of the primary production, the recovery factor remains relatively low and consequently application of Enhanced Oil Recovery (EOR) techniques is required to increase the recovery.

Сrude oil from Nimr-E field is medium-heavy with the viscosity of 250-700cP under reservoir conditions. The field has been developed with mostly horizontal producing wells with relatively short inter-well distance. Due to strong bottom aquifer the reservoir pressure is maintained at the initial level despite the production under primary depletion. To increase the recovery factor polymer flooding was selected with expectation to increase the recovery by 5-10%. A field trial was conducted to understand the influence of polymer injection on oil recovery and address major uncertainties identified as key enablers for the full-field project. The pilot surveillance program, the surface facilities and the subsurface configurations were specifically designed to meet these objectives.

The paper presents field data of polymer injection trial in Nimr field and focuses on the performance results and principal operational challenges. The injection of polymer resulted in the incremental oil production that was assessed using field data and simulations. A significant increase of initial oil production and clear watercut reversal due to polymer injection was observed and incremental recovery reached approximately 7% of the initial oil in place. Injectivity issues encountered in the pilot wells were mitigated by the techniques and chemicals developed to solve the issues. The results prove the subsurface and operational success of polymer field trial that leads the way to a commercial development.
Velocity Strings in Sultanate of Oman Gas Fields; A Case Study
Authors: Janusz Norbert
Published: March 2022

Petroleum Development Oman operates large amount of gas wells in Sultanate of Oman. Due to the liquid loading occurring in these ageing assets, PDO has already installed 110+ Velocity String completions in the various gas fields across the concession area. In the 2015–2019 period, 39 wells in the Saih Rawl field were retrofitted with Velocity Strings. This paper presents the integrated and standardized approach to Velocity String candidate selection and compares the production performance post-installation against the forecast.
Evaluation of Organic Acids Implementation in Stimulating Tight Gas Reservoirs: A Case Study on Sarah Sandstone Formation
Authors: Elsheikh Ellewa Ahmed , Moawad Taha , Alnetaifi Ali , AlQuraishi Abdulrahman , Almutawea Yusuf
Published: March 2022

Sandstone formations are yet stimulated with mud acid when matrix acidizing is most competent. In terms of high-pressure high-temperature (HP-HT) conditions, the corrosive impact of hydrochloric (HCl) acid prompted the need to explore other alternatives to mud acid. This study examines the efficiency of organic acids in stimulating Sarah sandstone, a tight gas formation of potential.

Two Berea cores were first exploited to investigate the optimum and most efficient injected acid volume. The mineralogy of Sarah formation was identified using X-ray diffraction (XRD) aided by Scanning Electron Microscopy (SEM). Formation mineralogy led to the selection of acetic-HF and oxalic-HF as proper acids for stimulation experiments. Bentonite water-base mud was used to alter the permeability of three fresh Sarah sandstone core samples. The organic-HF acids were used to stimulate two core samples, while mud acid was tested in the third core for comparison. Energy-dispersive X-ray spectrometer (EDX) and SEM were utilized to study the impact of acids on porous media.

Experiments conducted in Berea core samples led to the execution of five pore volumes (PV) of preflush and one PV of main treatment as the optimum volume during the acidizing trials. XRD and SEM identified pore-filling clay minerals causing the low permeability of Sarah formation. Furthermore, the water-base mud injected decreased the permeability further by 80%. Oxalic-HF and acetic-HF mixtures recovered the initial permeability of core samples by 46% and 35% respectively. SEM-EDX results showed how organic acids have partially unblocked the pathways of the structural pores leading to permeability enhancement.

This research not only recommends the use of oxalic-HF acid for acidizing Sarah sandstone formation but also spotlights the ability of organic acids employment as preflush in hydraulic fracturing operations.
On the Importance of Reservoir Rock Mineralogy on Design and Performance of Surfactant-Based EOR Processes
Authors: Guillon Valentin , Delamaide Eric , Rousseau David , Morvan Mikel
Published: March 2022

Chemical EOR processes based on surfactants are highly constrained by chemicals losses due to retention in porous media. Surfactant adsorption is usually considered as the main retention mechanism. It can lead to a decrease in process efficiency and to an increase in costs. Among the factors impacting surfactant adsorption – namely reservoir rock mineralogy, brine composition and chemicals types — mineralogy is known to be prominent with an impact that is hard to predict and should be dealt with. This paper presents a comprehensive review on the importance of reservoir rock mineralogy on laboratory design and performance evaluation of surfactant-based EOR processes, using several field cases as illustrations.

First, the main effects of the various factors quoted above on surfactant adsorption will be presented. Then a summary of the mitigation strategies that can be applied on field, based on either brines treatments, chemical selection or specific injections processes, will be presented.

Four representative cases studies of Surfactant-Polymer process design and evaluation at the lab scale on different mineralogies and conditions will be discussed. Each of them exhibits specific hurdles and requires solutions to mitigate mineralogy impact on designed process. Oil recovery corefloods on reservoir rock were conducted with surfactant in effluent and oil production measurements. Mineralogy analysis were also conducted using XRD, SEM and NMR experiments.

The first case focuses on a low clay – low temperature sandstone, an apparently simple case which nonetheless shows a very high and unexpected surfactant adsorption due to a very particular clay repartition. The second case focuses on a high clay — high temperature sandstone: this expectedly difficult case was mitigated by the use of adsorption inhibitors, leading to a good oil recovery and a low adsorption. The third case focuses on an unconsolidated – low clay sandstone containing heavy oil which shows a pronounced sensitivity to fine mobilization by surfactant-polymer process. The selected solution was an adapted brine treatment. The last case focuses on a high temperature carbonate which classically shows high adsorptions. A combined process using brine treatment and adsorption inhibitor resulted in particularly low surfactant adsorption of 60 μg/g.

Mineralogy is shown to be a key factor that controls surfactant adsorption in chemical EOR processes. Using representative mineralogy in the lab feasibility studies is therefore mandatory to design relevant Surfactant-Polymer processes. This review demonstrates that efficient strategies can be developed to mitigate the impact of mineralogy on SP chemical EOR processes in a wide range of challenging conditions.
Chemical Enhanced Oil Recovery and the Dilemma of More and Cleaner Energy
Authors: Farajzadeh Rouhi , Eftekhari Ali Akbar , Kahrobaei Siavash , Mjeni Rifaat , Boersma Diederik , Bruining Hans
Published: March 2022

We develop a method based on concept of exergy-return on exergy-investment (ERoEI) to determine the energy efficiency and CO2 footprint of polymer and surfactant enhanced oil recovery (EOR). This integrated approach considers main surface and subsurface elements of the chemical EOR methods. The main energy investment in oil recovery by water injection is mainly related to circulation of water with respect to exergy of the oil produced. At large water cuts of >90%, more than 70% of the total invested energy is spent on pumping the fluids. Consequently, production of barrels of oil is associated with large amounts of CO2 emission for mature oil fields with large water cuts. Our analysis shows that injection of polymer increases the energy efficiency of the oil recovery system. Because of additional oil (exergy gain) and less water circulation (exergy investment), the project-time averaged energy invested (and consequently CO2 emitted) to produce one barrel of oil from polymer flooding is less than that of the water flooding at large water cuts. We conclude that polymer injection into reservoirs with high water cut can be a solution for two major challenges of the transition period: (1) meet the global energy demand via an increase in oil recovery and (2) reduce the CO2 footprint of oil production (more and cleaner oil). For surfactant-polymer EOR, the extent of improvement in energy efficiency depends on the incremental gain and the simplicity of the formulations.
Drilling Optimization in the Low-Resistive, Thin-Layer Reservoirs of Northern Oman
Authors: Awadalla Muhannad , Vasquez Bautista Ramiro Oswaldo , El Hawy Ahmed , Beche Amina , Elkarim Ahmed , Al Ghaithi Ghaida , Al Maktomi Assad , Sanchez Gonzalez Vanessa Carolina , Al Rashdi Hussain , Al Nummani Hafidh , Al-Khalil Hashemi , Omairi Shatha
Published: March 2022

Ultralow-resistivity reservoirs, common in Oman, are frequently encountered when drilling wells at the flank of an infill field with nearby oil/water contacts (OWC) in a reservoir sweet spot window of 1 to 2- m true stratigraphycal thickness (TST). An integrated solution developed to better position the wells in this type of reservoir has resulted in successful cases on net-to-gross (NTG), which exceeded expectations in terms of wells production and well deliveries.

Integrating resistivity propagation curves response with directional resistivity curves (distance- to- boundary curves) response allows for optimizing well placement and assists in determining the best approach of well objective during drilling. Once drilling the lateral section began, a careful evaluation of the distance-to-boundary service tool inversion and directional measurements were performed in addition to conventional resistivity curves evaluation. This procedure ensured accurate placement of the well; thereby, avoiding water contact.

Drilling optimization in long lateral sections has been carried out by optimizing bottom hole assembly (BHA) design, bit selection, and drilling parameters, taking geo-mechanics and geological uncertainty factors into consideration.
Hard Rock Horizontal Drilling—Using Mechanical Specific Energy, Downhole Vibrations Analysis, and Well Design to Optimize Performance
Authors: Heidari Varnamkhasti Mohammad Reza , Al Hinaai Qasim , Patil Ravindra , Al Lawati Ali Baqir , Al Ghasani Rashid , Vasquez Bautista Ramiro Oswaldo
Published: March 2022

This paper presents a deep horizontal drilling campaign with the goal of eliminating several inefficiencies restricting the drilling performance, including downhole drilling bit or tool failures. The operator and the service company identified the inefficiencies by using engineering methods to overcome the challenges. Since 2013, the operator had been drilling horizontal wells with 600 to 1000 m of lateral targeting deep gas sandstone multilayer reservoirs with 15 to 35 kpsi unconfined compressive strength. The focus in the campaign will be from the kickoff point in the 8 3/8-in. section to the total depth (TD) of the well. Well-1 performance was greatly affected by the issues related to the wellbore instability in the build section, which dictated a change in the well program from the original fat to slim design. Later, other challenges and drilling inefficiencies resulted from this change, causing Well-6 design to be switched back to the original fat design to improve wellbore stability by having proper mud weight and other mud properties, bit and drive systems selection, as well as the drilling practices. Mechanical specific energy (MSE) is an industry recognized optimization tool to evaluate the drilling efficiency (Teale 1965) but it does not identify the sources of the inefficiencies (Chen 2019). The MSE, in addition to the downhole high-resolution drilling dynamics data, have been used to identify not only the drilling dysfunctions but also to help find the sources. This method supports the decisions for a change in the well design, bit, or the drilling practices, which in turn reduces the total number of runs and the downhole tool failures or damages.

The improvements in drilling the horizontal wells since the campaign began are significant; i.e., Well-1 was drilled in approximately 165 days in 2014 while Well-6 was drilled in 49 days in 2017, which was 39 days ahead of the well plan with the majority improvements occurring in the last section. Well-6 is considered to be the most efficient Barik formation horizontal well drilled in Oman to date.