bluuebunny/crossref_metadata_2025 huggingface dataset:
Novel Mechanism Investigation during Development of Nanofluids to Improve Oil Recovery in Malaysian Oilfield
Authors: Hendraningrat Luky , Razali Norzafirah , Tewari Raj Deo
Published: February 2022

The nanoparticles are considered as an attractive emerging improved oil recovery technique in last decade due to its ability to propagate deeper into pore throat and displace unswept oil in the reservoir. Current understanding of its mechanisms in conventional oil has been observed so called disjoining pressure that involved wettability alteration, log-jamming, and viscosity effect. This paper presents recent investigation of new potential mechanism during development of nanofluids to improve oil recovery in Malaysian oilfield.

The new inhouse nanofluids was developed using acrylamide monomers that were grafted on the surface of silica-based nanoparticles. A minor concentration of surfactant was introduced into the formulation to observe synergistic effect. The nanoparticles were characterized under electron microscope. Compatibility and thermal stability tests were conducted using reservoir fluids at reservoir temperature. The rheology of fluids was measured during monitoring of stability. In term of wettability alteration, sequence fluid-fluid and rock-fluid tests were conducted includes dynamic interfacial tension (IFT) and optical contact angle (OCA) measurement.

The particle size was measured with size around 20 nm. Adding small concentration of additive showed good performance in term of compatibility, thermal stability, and wettability alteration through IFT reduction and OCA measurement. Nanofluids with additive provided excellent compatibility with reservoir fluids and stable at reservoir temperature over 60 days. Its viscosity was also more stable during observation period without creating micro-emulsion. The IFT reduced insignificantly from 2.6 to 1 mN/m and when introduced additive, the IFT reduction achieved 0.01 mN/m. This synergistic effect was observed during IFT measurement and called as fragmentation.

Our recent finding leads to provide new reference for displacement mechanism using next generation of nanofluids and offers further potential of nanoparticles with multiple mechanisms and rapid synergistic effects prior its application in in Malaysian oilfield.
Selection, Implementation and Monitoring of Corrosion Inhibitors for Downhole Chemical Treatment on Rod/Beam Pump Wells Bahrain Fields
Authors: Ouled Ameur Zied , AlThawadi Abdulla , Grbic Borislav
Published: February 2022

Corrosion is a naturally occurring phenomenon commonly defined as the destructive attack of a metal that results from a chemical or electrochemical reaction with its environment. The effect of corrosion in the oil and gas industry leads to economic loss, a loss of containment and associated impact on HSE and asset integrity. There are many technologies to bring the oil to the surface. Rod or Beam pumps are the most common form of artificial lift for oil wells in onshore oilfields. They are simple machines that have a long and well documented history in the industry and are economically inexpensive. Corrosion inhibitors are commonly used to mitigate electrochemical corrosion in the oilfield. When added in small quantities to an aggressive medium, these chemicals inhibit corrosion by changing the surface conditions of the metal surface. In downhole systems, the prevailing conditions may be very severe, resulting in high corrosion rates. Corrosion inhibitors can be applied downhole, however, the selection and application of a corrosion inhibitor for downhole is typically more challenging than for a surface application. The paper gives a brief view on the selection of the suitable corrosion inhibitor that meets the well condition. It will explain how to select the best application methods for downhole corrosion on Rod Wells. The paper also demonstrates how the downhole treatment for rod wells is carried out giving in depth details of the method that has been used. It will present the results of a downhole treatment case and make recommendations for a performance monitoring program to optimize a treatment program ensuring its success. Finally, the paper concludes with a case history of downhole corrosion inhibitor application from an onshore field in the Middle East with 550 producing wells, where downhole corrosion inhibitor was successfully applied to 165 wells, leading to a major reduction in tubing corrosion failures
Treatment of a Highly Sour Natural Gas Stream by Hybrid Membrane-Amine Process: Techno-Economic Assessment
Authors: Hamad Feras , Qahtani Mohammad , Ameen Ahmad , Vaidya Milind , Duval Sebastien , Bahamdan Ahamad , Oatibi Faisal
Published: February 2022

The sweetening of highly sour natural gas streams is challenging. This paper highlights the main findings of a techno-economic study comparing the traditional approach involving only amine (DGA) versus a hybrid membrane-amine treatment process.

The hybridized membrane-amine process has been compared to the benchmarked classical DGA amine process, being the abundant process for treatment of sour natural gas. The acid gas membrane unit is deployed upstream of the amine process to selectively bypass a substantial part of the acid gas load to the sulfur recovery unit (SRU), thus affecting a substantial reduction in the amine process size and requirements.

The membrane process separation efficiency has been manipulated at two levels: the performance factors (permeance and selectivity) and by deploying a two-stage configuration. The membrane process is designed to recover about 70% of acid gas load and bypass it to the SRU. This has substantially off-loaded the acid gas reaching the amine process. Consequently, the amine process size and requirements (amine circulation rate, electrical drive power, steam for amine regeneration) is proportionally reduced. The membrane process, however, results in increased hydrocarbons slippage into the feed of SRU. Therefore, manipulating the membrane process separation efficiency has a direct impact on the SRU size and operation. Financially, the membrane process has clear role in altering the contribution of the different elements of the capital investment cost (CAPEX) and the operating cost (OPEX). The two-stage membrane process is more appealing for the reduced hydrocarbons slippage, but more power is needed for inter-stage compression. Enhancing the membrane performance factors leads to a more economically attractive process than the amine stand-alone.
An Effective Solution for Unwanted Water Production Obtained from Water Coning Mechanism: Field Application
Authors: Al-Azmi Ali , Al-Qattan Hassan , Al-Dousari Mohamad , Al-Yaqout Thanyan , Matar Khaled , Chawla Sapna , Gaur Rishika , Alwazzan Abdulatif , Khandelwal Nakul
Published: February 2022

Undesired water or gas production has been an issue for decades within the petroleum industry. Cases of unwanted water production from water coning mechanisms are increasing and becoming a frequent challenge. This paper presents the implementation of a unique water shut-off system to effectively reduce or eliminate water production and maximize the life of the well. These systems are conformance polymer sealants (CPS), an organically crosslinked polymer that is thermally activated to adequately seal the targeted interval, and a particulate-CPS (P-CPS) that combines the CPS system with non-cementitious particulates that provide leak-off control to help ensure shallow reservoir penetration of the sealant.

This unique technique involves the utilization of a rig to remove the electric submersible pump (ESP) and temporarily seal existing perforations. New perforations are then placed above the water-oil contact (WOC) to squeeze CPS and P-CPS systems. Both systems are then bullheaded into the well (spotted at a desired location in the wellbore), allowing easy, economic placement. CPS is a low-viscosity fluid system (20 to 30 cp), which enables easy injection deep into the matrix of the formation before the system undergoes the phase change from liquid to a 3D gel structure. Such deep penetration of CPS prevents water from traveling upwards when the target intervals are re-perforated, while P-CPS properly seals the current perforations above WOC. Finally, the ESP is re-installed, and the well is put back on production.

This paper presents the results obtained from ten case histories in Kuwait. A salient case is the successful use of the CPS and P-CPS systems, resulting in reducing water cut by 100% and increasing oil production by 2362 BOPD (752%).

The prospect of extending the effectiveness of this solution over an extended period of time and allowing the production from the existing flowing intervals, as opposed to that of the traditional operations, make this method a valuable alternative.
New Logging Technique for Direct Measurement of Relative Permeability
Authors: Adam Robert , Felix-Servin Jesus , Wang Wei , Deffenbaugh Max
Published: February 2022

A measurement system capable of in-situ measurements of formation permeability is described. The measurement method relies upon imaging the distribution of magnetic permeability doped fluid injected into a wellbore system through mutual inductance measurements between pairs of coils, and relating the change in distribution of this fluid over time to a direct measurement of formation phase permeability. Analysis of the mutual inductance measurement method shows a unique response to distributions of magnetic permeability for various coil spacings, and insensitivity to other confounding electrical parameters. The response of the mutual inductance measurement to several magnetic permeability distributions is shown, demonstrating the feasibility of the measurement technique to image the subsurface formation magnetic permeability distribution and provide in-situ measurements of formation phase permeability.
Leakage Detection in Subsea Flow Lines
Authors: Ileagu Martin Obinna , Ofong Ikechi , Godson Osueke , Victor Uchechukwu Opara
Published: February 2022

With hydrocarbon targets becoming more inaccessible and further away from the marketplace, the need for operative fault monitoring process for continuous pipeline operation is attracting renewed attention. Dependable evacuation process is essential in managing the volatile hydrocarbon products demand-supply drivers. Pipeline remains the most robust method for full and/or partial transportation of fluids from source to the market/processing place and its reliability is integral to achieving this objective. This study examines the phenomena of a new leakage detection technique in subsea pipelines. The numerical modeling of transient pipe flow based on method of characteristics is initiated by closing the pipe downstream valve. The time history of pressure fluctuation measured as a downstream boundary condition showed that when compared with equal magnitude and spaced pressure signals of the leak free pipeline, damaged pipeline will have changing sinusoidal patterned pressure signals due to the presence of leaky nodes.
A Decision Tree Framework for Tracking CO2 Fronts in Carbonate Reservoirs from Deep Measurements Data
Authors: Abu Alsaud Sara , Katterbauer Klemens , Alqasim Abdulaziz , Marsala Alberto
Published: February 2022

One of the main challenges in tracking CO2 fronts in carbonate reservoirs is the geological and petrophysical heterogeneity and complexity. This obstacle led to uncertainties in the decision-making and tracking processes. In current practices, empirical petrophysical formulas are utilized to model CO2 fronts in carbonate formations. These formulas has shown tremendous results and advancements in addressing such complexity and they are the stepping-stone to petrophysical modeling. However, the challenge is continuously augmented as the data grow.

We present an innovative artificial intelligence framework to estimate CO2 fronts in carbonate reservoirs based on deep measurement data such as electromagnetics surveys and acoustic impedance, together with porosity profiles. The framework processes the deep data and then sets it as training data. Afterward, the framework uses a decision tree model, specifically a regression tree, to estimate the CO2 saturation front map based on the training data. The framework tests four types of regression trees in which each tree has a different minimum leaf size.

The framework was tested on synthetic deep measurement data such as electromagnetic surveys, acoustic impedance, and porosity profiles. Expert processing was also included in the processing stage to remove illogical measurements in the training data. The proposed artificial intelligence framework is applied to the training data set. The decision tree framework produces four types of regression trees with different minimum leaf sizes. These different trees are classified as ultra-fine, fine, medium, and coarse. Overall, all regression trees showed a high resemblance to the original CO2 front. However, the tree with the smallest minimum leaf size, which is the ultra-fine tree, has the highest accuracy and certainty. As for the computational time, the coarse tree is considered to be the fastest.

This framework represents an innovative approach to track CO2 fronts by combining deep measurement data such as electromagnetic surveys, acoustic impedance, and porosity profiles with an artificial intelligence framework. Also, the framework is aimed to improve inter-well saturation mapping for CO2 sequestration application. The approach is data-driven, and it takes into account the existing data-scarce petrophysical model challenges.
Connection Between Wettability and NMR-Detected Isotherms
Authors: Kwak Hyung , Gao Jun , An Yao , Kasule Muhammad , Doyle Patrick , Kleinhammes Alfred , Wu Yue
Published: February 2022

Reservoir wettability is a parameter of crucial importance for oil recovery1. However, its definition and its measurement are quite complex. For a flat surface, wettability is directly related to the contact angle of a water droplet on a surface controlled by the hydrophilicity of the surface. For an arbitrary surface, the contact angle, however, does not only depend on the hydrophilicity of the surface but also depends on the surface roughness at various length scales. Therefore, wetting is a macroscopic property that is only directly related to the hydrophilicity of the surface if the surface is flat and smooth. The hydrophilicity of the surface is a microscopic property that determined the surface interactions with water and hydrocarbons and plays a crucial role in oil production and recovery. The unknown surface roughness of internal surfaces of rock porous media makes wettability definition and measurement of such internal surfaces extremely challenging. Identifying a wettability index of porous media surfaces with broad applicability is a primary objective in oil and gas industry.

Here we demonstrate an NMR-detected isotherm technique for measuring surface wettability of porous media. This technique is not only related directly to the traditional measure of wettability using macroscopic contact angles, it is also directly related to the microscopic surface property of hydrophilicity. It is shown that NMR-detected isotherms of both water and isopropanol (IPA) are needed to obtain the wettability index. Through systematic studies of quartz glass beads and quartz slides that are hydrophilic- or hydrophobic-modified, we established a quantitative relationship between the NMR isotherm-based wettability index and the traditional measure of wettability using contact angle. Therefore, the proposed wettability index derived from NMR isotherms provides a clear link to both macroscopic and microscopic properties of internal surfaces of porous media and can be a reliable measure of interactions between water and hydrocarbon with internal surfaces of rock porous media, as evidenced by preliminary studies of rock samples.
The Effect of Tube Curvature on Temperature Separation Efficiency of Ranque-Hilsch Vortex Tube
Authors: Khan Shahzaib Yousuf , Allauddin Usman , Hasani Syed Muhammad Fakhir , Khan Rashid , Arsalan Muhammad
Published: February 2022

Vortex tube that splits a single compressed gas stream into two separate hot and cold streams had been successfully used for spot cooling, and refrigeration. Significant temperature gradient exists between hot and cold stream ends that could be utilized for power generation using thermo-electric generators. Distance between hot and cold ends could be vital for small inaccessible down-hole well locations which may require the use of curved vortex tubes. Efficiency of vortex tube depends on temperature difference between hot and cold ends. In this work, effects of tube curvature on temperature separation efficiency are investigated through numerical simulations. Numerical models of straight and curved vortex tubes are developed in a commercial computational fluid dynamics package Ansys-fluent®. For the curved tube, multiple curvature angles are used to analyze the effects of curvature on velocity and temperature fields inside the vortex tube. The standard κ − ε turbulence model is used to model three-dimensional turbulence. The cold stream mass fraction is varied by controlling hot exit pressure. The numerical results for 110° curved vortex tube are validated through published experimental data and are found to be in good agreement. It is found that the curvature has affirmative results on temperature separation efficiency as compared to straight tube. This is mainly due to the energy separation phenomenon governed by the multi-circulation loop extension and multiple vortex formation in curved vortex tubes. Curvature angles of 180° and 270° have similar effects on the vortex tube where the maximum ΔTc obtained is 15.7 K which is about 5.3% higher than the straight vortex tube. The temperature separation ΔThc values for curved tubes are comparable with straight tube, the maximum being 25.2 K for the 150° curved vortex tube which is about 0.8 per higher than the straight tube. The temperature separation efficiency for curved vortex tubes with curvature angles larger than 150° is found to be higher than straigt tube, the maximum value being 8.7% for the 270° curved tube. A profound investigation of the effects of curvature on energy separation phenomenon in a vortex tube had been lacking and this research attempts to fill that gap. This novel work is expected to provide insight into the energy separation mechanisms in vortex tubes and lead the way to their use in thermo-electric power generation.
Application of Phenolic Resin Crosslinked Polymer Gel in Fractured-Vuggy Carbonate Reservoir with High Temperature and High Salinity
Authors: Wu Weipeng , Hou Jirui , Qu Ming , Wu Wenming , Zhang Wei , Wen Yuchen , Liang Tuo , Xiao Lixiao
Published: February 2022

As a special unconventional reservoir, the high temperature and high salinity of fracture-vuggy carbonate reservoirs has been confining the advance of EOR technology. Take water plugging as an example, the majority of plugging agents currently do not have temperature and salt resistance at the same time. Therefore, a novel Phenolic Resin Crosslinked Polymer Gel (NPRG) which has excellent resistant to high temperature (140°) and ultra-high salinity (240000mg/L) reservoirs is going to be developed. In this paper, methenamine, hydroquinone, thiourea, cobalt chloride hexahydrate (CCH) are synthesized by certain mass ratio. Besides, rotational rheometer, SEM were used for characterization before and after gelation, plugging performance of gel was measured using cubic fractured core. The research found that, CCH can provide more crosslink points for the 3D mesh structure of bulk gel system. Therefore, the period of dehydration of gel microstructure was extended. The initial viscosity was 77.1mpa·s when this bulk gel system achieved its optimal concentration ratio, besides, the dehydration rate of this bulk gel system is only 5% within 30 days and its strength can be stabilized at H-I level within 150 days. The NPRG also has a satisfactory shear resistance performance and a better erosion resistance. Additionally, result of core flooding experiment showed that NPRG achieve a plugging rate of 90% and has little damage to the substrate. Finally, the success of laboratory experiments and pilot tests indicates that NPRG has certain application potential in fracture-vuggy carbonate reservoirs where fractures are dominantly developed.
Cost Engineering Software: Value Based Management of Oil and Gas Assets in All Investment Process Stages
Authors: Pashkevich Lev , Gordeeva Daria , Skudar Oleg , Kashafutdinova Aliya , Lyasovich Denis , Ulyaschenko Vladislav
Published: February 2022

This paper gives an overview of Gazprom Neft's strategic goals and describes how industry benchmarking helps in achieving them. In particular, we offer a general description of Gazprom Neft's cost management processes with a detailed focus on two of them: baseline cost and reserve estimate, and project cost monitoring and control. The digital landscape of cost engineering is also described, which is represented by three interrelated cost estimation tools, and a software product that allows you to manage capital expenditures at subsequent stages — to monitor and control the cost of the project. The cost engineering software products are unique solutions for the industry, and their features are described in this paper.
Project Gradient - A Tool for Comparative Analysis and Potential Search
Authors: Bazyleva Nafisa , Mozhchil Artem , Pashkevich Lev , Yanina Irina , Skudar Oleg , Pislegin Mikhail , Gerasimov Fedor , Kozlovskii Pavel
Published: February 2022

Annotation

The new strategy of our Company is aimed at increasing efficiency in the growth of reserves and production of hydrocarbons by maximizing the created value of each barrel in any scenario of the development of the outside world. The company aims to become a benchmark for players in the Russian and global industry in the field of safety, efficiency and manufacturability by 2030 - a global industry benchmark.

Now being adopted capacity-based performance management is a set of management processes (planning, organization of implementation, control and analysis) that allow enterprise management to determine goals in the field of improving the efficiency of production and business processes and manage their achievement. This approach is based on a comparison of performance indicators by areas of activity with the best results achieved within the Company and by world leaders in the industry, with further development and implementation of measures aimed at reducing gaps.

A tool is needed to search for directions with great potential and to correctly assess the potential. The task of the tool is to find a benchmark, assess the potential in each area (metric) and help production units with the search for activities that will allow this potential to be realized.

The developed tool will consist of modules in accordance with the stages of deep technical benchmarking by processes and cost items by assets and industry, including: Automated collection of current metricsIdentification of reference metricsAssessment of potentialIdentification of levers and hypotheses generatingMonitoring of the declared technical metrics achievement

As a result of the Gradient project, it is expected: Improving the quality of the formation of hypotheses about potential due to a targeted search for levers of its implementation.Expansion of the collection and analysis perimeter of data on gas and gas condensate assets.Creation of a unified cost decomposition methodology and OPEX database for the entire company with the ability to anonymously dataview for all assets.Improving the projects and business efficiency cases through competent identification and application of best practices at the conceptual design stage.Improved quality and speed of decision making through advanced analytics and modeling.The dissemination of the platform based on anonymous data will allow all companies in the industry to regularly conduct internal analysis and look for development potential.
Mitigation of Geomechanical Risks for Long Term CO2 Geological Storage
Authors: Tan Chee Phuat , Ali Siti Syareena , Yakup M Hamzi , Mustafa M Azlan , Chidambaram Prasanna , Mazeli Abdul Hakim , Hanifah M Azri
Published: February 2022

Carbon dioxide (CO2) capture and geological storage is one of the best alternative methods of produced CO2 disposal rather than venting it into the atmosphere. However, there are numerous geomechanical challenges and risks associated with CO2 injection and geological storage that are required to be addressed. The key challenges include delineating the geological seal barrier and maintaining the seal integrity throughout the injection operation and storage life.

The assessment of geomechanical-related challenges and risks to manage CO2 containment and mitigate leakage risks require a coupled geomechanical study that needs to be conducted as part of feasibility evaluation of injecting and storing CO2 in a field. In the geomechanics-dynamic coupled modelling, at selected stress steps the reservoir model passed data including pressure, CO2 concentration within the plume, water saturation and temperature to the geomechanical model. Changes in stresses, rock mechanical and rock petrophysical properties based on laboratory CO2-rock interaction test data, displacements, strains and deformations were computed by the geomechanical model using the data from the reservoir model. Updated petrophysical properties such as permeability and porosity were passed by geomechanical model back to the reservoir model and used in the next dynamic simulation step.

The coupled geomechanical modelling assessed CO2 leakage risk associated with fault re-activation, failure of cap rock, CO2-rock interaction, and cooling of injected CO2 on caprock and reservoir rock. Axial loading on completions due to reservoir compaction could cause buckling collapse and/or cement failure. Fault re-activation was based on induced fault plastic shear strain throughout the injection programme which may pose risk of CO2 leakage. The evaluation of induced plastic shear strain and failure state of caprock, effect of CO2 interaction and cooling on the caprock and reservoir rock integrity, and compaction and associated subsidence were also evaluated. Recommendations from geomechanical perspective can subsequently be developed from the results and findings for the CO2 injection programme and storage operation.
Sustainable and Eco-Friendly Drilling Fluid Additives Development
Authors: Ramasamy Jothibasu , Arfaj Mohammad. K.
Published: February 2022

Drilling fluid is an inseparable component of drilling oil and gas wells and circulated from the day of spudding to the day of completing a well. Drilling fluid consists of a variety of chemicals to provide various properties to drilling fluid such as viscosity, fluid loss control, emulsion stability, lubricity, etc. Developing chemicals that are eco-friendly and sustainable to provide the above-mentioned properties to drilling fluid is a significant step forward taken towards sustainability and reducing carbon footprint besides suitability for aquifers and offshore environments. Several fatty acid-based products play a crucial role in drilling fluids additives development as fatty acids offer eco-friendly and bio-degradable properties. Triglycerides present in vegetable oil is a potential source of fatty acids and their derivatives. Used cooking oil (UCO) provides a perpetual and sustainable source of raw material for various types of eco-friendly additives development. Used cooking oil is subjected to simple chemical modification of base hydrolysis process and mixture of fatty acids have been obtained after completing a sequence of clean-up process of reaction mixture. The fatty acids obtained are eco-friendly, bio-degradable and non-toxic. Due to technical, economic and environmental benefits, we have conducted several research projects to develop various chemicals from used cooking oil for oil and gas field applications. Fatty acid-based products mainly used in drilling fluids as lubricants to reduce torque and drag for water-based mud. In case of oil-based mud systems, fatty acid derived products are used as emulsifiers, wetting agents and rheology modifiers. However, these products have been either mixture of fatty acids and their derivatives or only derivatives of fatty acids. In our study, we have used the mixture of fatty acids obtained from chemical conversion of UCO for applications as lubricant for water-based mud and emulsifier and rheology modifier for invert emulsion oil-based mud systems. This paper describes the chemicals process for converting used cooking oil to fatty acids by base hydrolysis reaction in the first section. Application of synthesized fatty acids for water-based and oil-based mud formulation as lubricants, emulsifiers and rheology modifiers have been discussed in the second part of the paper.
Multi-Purpose Wellhead
Authors: Garcia Javier
Published: February 2022

The conventional oil drilling process includes the drilling of a well, a reservoir having pressure and a mixture of oil/gas/water flowing out of the ground. Eventually as a well gets older and the reservoir pressured reduces, some form of artificial lift becomes necessary. For wells producing a significant amount of gas, either gas lift or a related method (plunger lift for example) tends to be the sensible solution. Ultimately, once the reservoir pressure and production levels have depleted substantially, rod pumping becomes relevant.

Each production method requires a specific surface piping and valving arrangement to allow for the wellbore fluids to flow with minimum restriction as well as fluid injection as applicable. Following safety and operational protocols established by each operator, the surface arrangement should be inclusive of multiple barriers to shut down production should the need arise. Redundancy becomes a necessity to ensure compliance with safety regulations while protecting the assets.

Adapting the wellhead stack to the production method requires major interventions with the associated cost and deferred production. Logistic and planning can be critical for smooth modification of the wellhead stack especially when several wells are involved.

In this context, a universal piece of equipment engineered for compatibility with all production stages of the well can add value to the operation by eliminating wellhead stack modifications and minimizing deferred production through the well life cycle.
An Efficient Technology and Solution Well Operation by Maintain Well Integrity in Offshore Field
Authors: Saleppang Kila Edyos Wyndu , Firmansyah Dadang
Published: February 2022

The point of well integrity is how to produce hydrocarbon from the source (well) to surface safely. The main goal of this paper is to keep well in operation due to gas supply and demand in the field, identify tubing/ annulus communication, mitigate any excessive annulus pressure, and corrective action of tubing casing leaks refer to industrial code and Well Integrity Management System (WIMS).

One of the wells in "P" platform, namely "W" well has found a leak between production tubing and production casing ("A" annulus) and no any excessive presure from "B" & "C" annulus in this case. There is no way to shut-in the well due to gas supply and demand in our field and the well must be operate safely by conduct annulus pressure monitoring, pressure limit calculation, regular bleed-off program, and modify surface facilities.

Pressure limit is calculated by determine MAASP and MOASP to ensure working pressure and bleed-off program are managed. Annulus pressure bleed-down program is one of mitigation action to manage excessive pressure in annulus. We have provided technical recommendation, specify mitigate engineering solution to reduce risks, and modify surface facilities to keep wells in operation. Based on jobs result, we have done to operate all wells safely with efficient technology, deliver fluid from 3 ½" production tubing to surface facilities, perform cost optimization, and minimize production loss. We have also performed to manage and maintain annulus casing pressure successfully related to well integrity implementation. Furthermore, In this case, there is no serious hazard during these conditions in offshore field.

The paper will share success story, method, and detail procedure to keep well operation by maintain annulus casing pressure in offshore field. We have done this method by efficient technology/ solution with lower operating & construction cost and there is no production loss during operation. We confidence this method can be applied successfully not only for our field, but also other business/ operating units which has similar conditions.
Evaluating the Impact of Rock Hardness and Roughness on Acid Fracturing Conductivity
Authors: Hassan Amjed , Tariq Zeeshan , Al-Abdrabalnabi Ridha , Saleh Aljawad Murtada , Mahmoud Mohamed
Published: February 2022

Different techniques are used to increase the hydrocarbon production from carbonate reservoirs; the common approach is applying acid fracturing. Channels and rough fracture surfaces can be created due to the acid injection at high pressure. The rock properties and mineralogy will have a significant impact on the treatment performance. This paper presents the impact of rock hardness and roughness on the fracture conductivity during HCl and GLDA chelating agent as acid fracturing fluids. Silurian dolomite, Indiana limestone, and Austin chalk were used in this work. Smooth initial fracture surfaces were created by cutting the rock samples into two parts. Six coreflooding experiments were conducted by injecting the acid fluids into the carbonate samples. The rock strength and the surface roughness were measured using Brinell hardness tester and Kruss high-resolution surface analyzer respectively. The results showed that the fracture conductivity was controlled by the type of injected fluids and the rock hardness and roughness. Strong acids such as HCl can produce higher conductivity compared to chelating agent solutions, due to the higher created surface roughness. Significant increases were observed in the fracture conductivity for chalk and limestone rocks when treated with GLDA, while a slight increase was achieved for the dolomite conductivity. Overall, this work can help in improving the performance of acid fracturing treatments by providing a better section for the acid type based on the rock hardness and roughness.
Rheological Optimization of CO2 Foamed Chelating Stimulation Fluids at High-Pressure, High-Temperature, and Salinity
Authors: BinGhanim Ahmed , Al-Darweesh Jawad , Aljawad Murtada S. , Zhou Xianmin , Kamal Muhammad S. , AlYousif Zuhair , Mahmoud Mohamed
Published: February 2022

Foamed acidic fluids have been utilized in the industry for enhanced oil recovery and fracturing applications due to their various advantages. Flowback enhancement, recovery of treatment fluids, and reduction of overall water consumption per operation are examples of these advantages. This study examines the utilization of a chelating agent, L-glutamic acid-N, N-diacetic acid (GLDA) in N2 and CO2 foamed fluids, which enhances the stability of foamed acidic fluids, lowers corrosion tendency, and is environmentally friendly.

A modified high pressure and high temperature (HPHT) foam rheometer, and foam analyzer at ambient conditions, are used to test the acidic foamed fluids prepared in produced water using N2 and CO2. A screened out Alkyl diamine derivative surfactant has been tested at 212-300 °F and 1000 psi with and without GLDA. The effect of corrosion inhibitor addition on viscosity and foam quality is also investigated. Viscosity and foam quality measurements were done at increasing shear rates from 500 1/s up to 2000 1/s.

Results showed that GLDA enhances the foamed fluid viscosity and stability. Resulted viscosities were in the range of 5 cP at higher shear rates to 25 cP in the lower shear rates region. Viscosity, in general, is lowered by higher shear rates, but foam quality is not affected. Fluid systems with a corrosion inhibitor also resulted in lower viscosities. The most stable and relatively higher viscosity values resulted from the 1 wt.% surfactant concentration with the addition of 15 wt.% GLDA and no corrosion inhibitor. Ambient conditions foam analyzer results showed higher foam height and half-life values of 182.8 mm and 16.5 minutes respectively when foaimg using N2 compared to 77.4 mm and 2.16 minutes when foamed with CO2. The addition of corrosion inhibitor showed significant negative impact in all cases, but least on the half-life of the CO2 foamed fluid. The rheology study provided did not consider the addition of thickeners which could be further investigated.

This study covers the novel utilization of a chelating agent as an additive in CO2 and N2 acidic foamed fluids at harsh conditions. Furthermore, the fluid systems tested can be investigated and utilized as reliable stimulation fluid systems at temperatures up to 300 °F.
A Novel Foamed Acid System Stabilized by Composite Material for Fracturing Applications
Authors: Alarawi Abeer , Al Harbi Bader , Busaleh Ahmed
Published: February 2022

Carbonate reservoirs hold 60% of the world's oil and 40% of the gas. Therefore, developing high-impact and innovative technologies for well stimulation, such as foamed acid fracturing fluids, is essential for restoring well productivity and enhancing commercial productivity for carbonate reservoirs. Acid fracturing treatment is associated with reactivity control, fluid loss control, and conductivity generation challenges. For overcoming some drawbacks associated with conventional acid fracturing, foamed acid fluid is applied to enhance retardation, reduce water consumption, improve acid diversion, remove water or emulsion blocks, and improve conductivity generation. In this study, a unique foamed acid system stabilized by composite material was studied to develop fracturing fluid at 275-350 °F. In addition, the foam stability, rheology, and morphology characteristics were investigated using several characterization tools at 275-350 °F.

The composite material comprises nanosheet (NS), and surfactant (SURF) were added to either a pure-acid or acid system that contains several additives for developing stable NS/SURF-based foamed acid fluid. To evaluate foam rheological properties and thermal stability at dynamic conditions, foam loop rheometer experiments were conducted at 275-350 °F, 1050 psi, and 70 % N2 quality. A high-resolution optical microscope was also utilized to observe foam texture morphology and further assess foam stability. In addition, foam-decaying time was observed by determining the foam-half-life-time (foam volume altering as a function of time).

The static and dynamic results illustrated that foamed acid fluid stability and thermal adaptability were improved after adding composite material at 275-350 °F. The viscosity of foamed acid increased by double and its viscosity was higher than 45 cP at a shear rate of 300 S-1 and 350 °F. In addition, the foam-structure of NS/SURF-based foamed acid displayed a small hexagonal bubbles size, which positively affected the stability of foam to reach up to three hours at 300 °F. In contrast, the stability of pure foamed acid was one hour. This result is attributed to the adsorption of composite material at the liquid-gas interface layer that enhances the mechanical strength of the foam-layer (lamellae film) and provides a more robust barrier between the gas bubbles and liquid phase, resulting in delaying the coalescence of the bubbles. The developed NS/SURF-based foamed acid possesses several advantages over the conventional acid fracturing fluids: long stability, adequate viscosity (obtained without adding gelling agent), low water consumption, and high efficiency at 275-350 °F.
Estimation of Pressure-Dependent Permeability Modulus of Tight Sand Reservoir from Multiple Pressure Build-Ups and Its Impact on Production Forecast
Authors: Hammawa Hassan , Aleid Ahmed S. , Alsoqair Heba N. , Alfaraj Jana T.
Published: February 2022

During hydraulic fracturing process of the Permian Basin in North America, the cluster spacing has been shortened to 3m, and stress shadow can no longer be ignored. Many scholars have studied the influence of stress shadows to optimize cluster spacing. For reservoirs with natural fractures, how to activate more natural fractures through hydraulic fracturing has become the purpose. However, few scholars have studied changes in the activation law of natural fractures under stress shadow conditions. This paper establishes stress change value around single fracture according to Sneddon formula, and calculates the maximum and minimum principal stress according to plane principal stress calculation formula. Considering attenuation of net pressure, stress field of multiple fractures is established, and influence of various factors on stress re-orientation is studied. Finally, considering attenuation of net pressure with distance, according to discriminant formulas of tension & shear activation, the proportion of natural fractures that are easily activated is calculated. By designing orthogonal experiments, the influence of different factors on the proportion of activated natural fractures was studied. The stress increase in the direction of the minimum principal stress is much greater than the increase in the direction of the maximum principal stress. The stress increases in the direction of the maximum principal stress at the tip of the hydraulic fracture. The tip position between hydraulic fractures is "neutralized" due to the superposition of shear stress. Stress-fracture angle and the in-situ stress difference are the common main influencing factors for both tensile and shear activation, but the net pressure has little effect on the tensile activation of natural fracture. The fracture spacing has little effect on the activation of natural fractures. When formulating the fracturing scheme, we should pay more attention to the net pressure rather than the fracture spacing.This article provides a fast calculation method for the activation state of natural fractures considering the stress shadow, which provides a reference index for activating more natural fractures and increasing the production of a single well.
Application of Machine Learning in Wet Gas Measurement Predictions
Authors: Sidaoui Ziad , Alsunbul Yasmeen , Abbad Mustapha
Published: February 2022

The Venturi tube, a classic single-phase flow meter, proved to be a reliable and accurate wet gas flow meter, but it requires correction. The presence of liquid content increases the measured differential pressure across the Venturi tube and causes over-reading (OR). Developing novel methods to correct the Venturi tube readings has become a target in the oil & gas industry to quantify production from individual wells. This work is proposing a new approach to overcome the OR challenge using machine learning (ML) models.

The ML model to predict OR was developed using the random forest (RF) technique. Initially, synthetic dataset of producing wells were generated. A variation on the type of gasses and liquids were studied including nitrogen and benzene, argon and water, natural gas and water and natural gas and decan. The input parameters consist of fluid properties and fluid conditions. The fluid properties are including gas and liquid phases. The target for these inputs is to predict the OR. The results were then evaluated based on root-mean-square error (RMSE), and the fitness of the model was assessed by the coefficient of determination R2.

The ML model showed high accuracy results for the OR prediction of the testing data of R2=0.997 and RMSE of 0.7%. The developed model was then applied to a new set of data of air and water for further validation. This validation resulted in R2= 0.998 and RMSE of 0.5%. This shows that the RF technique is capable of predicting the OR in wet gas when the aforementioned input parameters are used. The uniqueness of this ML model is that the inputs are all measurable in the field. Once the OR is predicted, the "real" gas mass flow rate can be calculated directly.

The novelty of this work lies in providing a robust method to calculate the "real" gas mass flow rate real-time which ultimately diminishes the need to use published correlations derived from experimental conditions that are not necessarily representative of the oil field conditions.
Quantifying Wettability Index Using NMR T2 Distributions of Water Phases Extracted with Non-Negative Matrix Factorization
Authors: Li Baoyan , Kesserwan Hasan
Published: February 2022

The wettability of formation is a critically important factor for optimizing the hydrocarbon reservoir production. It is a complicated and challenging issue to quantify the wettability of rock at in-situ conditions. Because of its importance, various methods have been developed to quantify the rock wettability. However, each method has its strength and limitations. This paper presents a new wettability quantification method based on featured T2 distributions of water.

We define a new wettability index to quantify the wettability using NMR T2 distributions of water in wetting and non-wetting phases. We apply the principal component analysis (PCA) method to determine the number of components of the T2 distributions inverted from NMR measurements at different pore pressures. The non-negative matrix factorization is conducted on the matrix of T2 distributions with the determined number of components. A window technique is applied to extract NMR T2 distributions of water in different phases to quantify the rock wettability with the newly defined wettability index.

NMR measurements were conducted on sandstone samples of variant wettability to validate this proposed method. The samples were prepared at different saturation conditions that were achieved using core flooding techniques. The NMR measurements acquired at different saturated conditions of core plug samples were inverted to obtain T2 distributions, whose peak amplitudes and positions indicate sensitivities to saturations and wettability. The wettability indices for the flooded cores were computed in the new wettability quantification method and compared with those from the Amott-Harvey method.

The validation and comparison results show that: Compared with the Amott-Harvey method, the newly defined wettability index can be used to more effectively quantify the altered wettability of a surfactant flooded coreThe PCA identifies that fluid displacement processes (water displacing oil or oil displacing water) result in the shape changes of the T2 distributions inverted from NMR T2 measurements for flooded core plug samples.The non-negative matrix factorization can be applied to extract the feature components of T2 distributions of a flooded core, which are related to the wettability of the core.The T2 distributions of the mobile waters in water-wet pores and oil-wet pores can be extracted from identified components of T2 distributions.