bluuebunny/crossref_metadata_2025 huggingface dataset:
Technical Advancement of Carbonate Acid Stimulation Injection
Authors: Alkandari Dana K. , AlTheferi Ghaneima M. , Almutawaa Hawra'a M. , Almutairi Maryam , Alhindi Nora , Al-Rashid Sherifa M. , Al-Bazzaz Waleed H.
Published: October 2019

Formation damage is the impairment of permeability of rocks inside a petroleum reservoir. This occurs during drilling, production, stimulation and enhanced oil recovery operations, by various mechanisms such as chemical, mechanical, biological and thermal. Near wellbore formation damages have a great impact on productivity of the damaged formation. Acidizing is a stimulation method to remove the effect of near wellbore damage through reacting with damaging materials or the formation rocks (carbonate or sandstone rocks) to restore or improve permeability around the wellbore. Several experiments are conducted to study the effect of temperature and acid concentration combined on the efficiency of matrix acidizing. Three different concentrations scenarios of hydrochloric acid (3%, 15%, and 28%) and 4 different temperatures scenarios (25 °C, 35 °C, 70 °C, and 100 °C) were tested to investigate pore-enlargement success effect on permeability. The purpose of this experiment is to introduce the concept of optimized temperature augmented with optimized acid concentration in carbonate matrix acidulation. Morphology of pore geometry and area measurement software is used. New Advancement in imaging that captured pore area enlargement as big-data necessarily for artificial intelligence modeling. Captured pores before treatment and captured pores after thermal-HCL acid treatment have demonstrated that image processing of the actual acidized rock data can select the optimized recipe concentration of acid that will increase permeability, hence recovery. The results show that matrix acidizing is an effective method to improve permeability and enhance production, as it demonstrates that using less acid concentration with the optimized temperature can result in a favorable and satisfying outcomes.
Application of Hydro Jetting Technology to Expedite Tank Maintenance Duration with Enhanced HSSE Performance
Authors: Al-Wahaidah Mohammad Sulaiman , Dharan Ganga Prasad
Published: October 2019

Storage tanks (Crude Oil/Oil water/Brackish water) in Kuwait oil Company are lined with fiberglass lining over the bottom plate for internal corrosion protection and to minimize the problem of exterior corrosion by providing enough strength to bridge small perforations.

Storage tanks undergo major survey &maintenance activities on regular intervals and during maintenance period the fiberglass lining on tank bottom plate need to be removed to inspect and assess the condition of bottom plate. The removal of lining used to be carried out by manual method in which contract personnel enter the tank and remove the lining by continuous hammering, using hammer and chisel.

Manual removal method has the difficulties like the activity takes longer duration (2-4 months), high number of workers (15-25) working inside the tank, health and safety issues like working in a difficult posture like crouch down low and doing hammering leading to fatigue, exposure to hammering noise, grit blasting dust and fibre glass dust affecting the health of the workers, probability of injury due to hammer blows and flying fibre glass chips. In addition, after the manual removal of lining we have to carry out grit blasting of the surface for inspection and many times the tank bottom surface was found having mechanical damages due to the hammer and chisel blows.

Hydro jetting technology was introduced recently to remove the finer glass lining and found having many benefits like duration reduced to one third, reduced number of workers (3-4 personnel) required during execution (leading to considerable reduction in man hours), elimination of all the health/safety hazards as that of manual method, the tank surface was ready for inspection after the hydro jetting (unlike manual method where grit blasting was required after the lining removal) and no damages observed on tank bottom surface.
Extending Global Mobility Programs Throughout the K-Group
Authors: van Wieringen Joke
Published: October 2019

Studies by leading organizations highlight the importance of increasing internal talent mobility. Giving talented employees the experience of working in different countries and across diverse roles is a growing trend in developing their capabilities and skills.

This paper describes how Kuwait Petroleum International (KPI), an international subsidiary of Kuwait Petroleum Corporation (KPC), is drawing on its long and successful experience in this area to develop proposals for extending these programs to other subsidiary companies in the K-Group (K-companies).

To achieve its objective to become a global integrated oil and gas leader, KPC needs talented leaders with the agility, flexibility and understanding that is developed through mobility. Such experience is especially important for Kuwaiti nationals, who may have limited exposure to working abroad.

Sponsored by KPI, a Work Group has been set up with representatives from across the K-Group to develop mobility proposals for the K-Companies. It has established that global mobility is not feasible on a mass scale and that a diversification program, to provide experience of working in different roles and companies, needs to be developed alongside a global mobility program.

The Work Group has undertaken extensive research to determine best practice in mobility and has analyzed the K-Companies’ 2040 strategic objectives to understand the skills and capabilities required to support their complex activities. It has proposed future targets, based on the historic number of employees in each company with global mobility experience.

It recommends focusing global mobility programs on Juniors and Young Professionals, who have the greatest number of career years left to maximize the return on investment.

The paper describes the different types of global mobility assignments and how a new graduate program for Young Professionals, incorporating global mobility and diversification, will be developed. It also looks at the monitoring required to support participants and ensure that the programs remain aligned with business objectives.

Strong foundations are in place to launch the mobility programs and detailed discussions will be conducted with the K-Companies to refine the proposed directions and targets.

The vision is that, within five years, global mobility and diversification will be fully embedded throughout the K-Group and closely aligned with business objectives.
A Data-Driven Model for Rapid Evaluation of Miscible CO2-WAG Flooding in Heterogeneous Clastic Reservoirs
Authors: Jaber Ahmed Khalil , Alhuraishawy Ali K. , AL-Bazzaz Waleed Hussien
Published: October 2019

The compositional flow simulation model was frequently used to evaluate the miscible water alternating CO2 flooding (CO2-WAG). The uncertainty and sensitivity analysis have to be conducted to examine the parameters mostly affecting the performance of the process. Accordingly, multiple simulation runs require to be constructed which is a time-consuming procedure and finally increase the computational cost. This paper presents a simplistic approach to assess the miscible CO2-WAG flooding in an Iraqi oilfield through developing a statistical proxy model. The Central Composite Design (CCD) was employed to build the proxy model to determine the incremental oil recovery (ΔFOE) as a function of seven reservoir and operating parameters (permeability, porosity, ratio of vertical to horizontal permeability, cyclic length, bottom hole pressure, ratio of CO2 slug size to water slug size, and CO2 slug size). In total, 81 compositional simulation runs were conducted at field-scale to establish the proxy model. The validity of the model was investigated based on statistical tools; the Root Mean Squared Error (RMSE), R-squared statistic and the adjusted R-squared statistic of 0.0095, 0.9723 and 0.9507 confirmed the reliability of the model. The most influential and the optimum values of the parameters that lead to the higher ΔFOE during miscible CO2-WAG process were identified through proxy modeling analysis. The developed model was created based on the Nahr Umr reservoir in Subba oilfield and can be applied to roughly estimate the ΔFOE during the miscible CO2-WAG process at the same geological conditions as Nahr Umr reservoir.
Data Driven Predictive Modelling Assists in Proactive Water Cut Management in a North Kuwait Heavy Oilfield
Authors: Kharghoria Arun , Alshammari Abdulrahman , Gonzalez Santiago , Sanwoolu Ayodele Olusegun , Al-Rabah Abdullah Abdul , Montero Jacobo , Gonzalez Gregorio
Published: October 2019

This study presents the development of predictive models (for a single or a group of wells) to proactively manage water production in a heavy oil field in North Kuwait (average 16 °API crude, ~100 cp at 100 °F). Each resulting model is based on reservoir and time-dependent wellbore mechanical parameters that were obtained through several well tests. The primary goal is to be able to predict the water cut based on a well's current as well as "possible near-future" operating conditions.

The exercise involves using advanced predictive methodologies. Standard parameters (referred to as features) include water cut as the response variable along with pump intake pressure, total liquid production, pump speed, and surface unit power consumption among others as response variables. Random ForestsTM (RF), Alternating Conditional Expectations (ACE) and Multiple Linear Regression (MLR) algorithms were tested. Features were primarily grouped based on clustering. The predicted results are compared to history. The resulting models are further extended to generate type curves for future water cut prediction for different combinations of the operating parameters.

MLR and ACE based predictive models showed promising results. These algorithms also provided a way to characterize the influence of different features on the model outcome (i. e. predicting historical water production). The model quality significantly improves when only time-dependent features are used. The static parameters (e.g. permeability, perforation stand-off to oil-water contact, pump size) do not appear to have a big impact on improving the model score. Also, improvements were observed by introduction of principal component analysis (PCA) followed by clustering. The generated type curves allow the prediction of the near-future water production and to proactively adjust a well's operating parameters.

A predictive model is a time-saving tool compared to full range dynamic simulation. This provides a means to the engineers to establish an operating envelope for a well (or a group of wells) to manage water production. This is also a precursor to a full-scale machine learning process that could be implemented for automatically updating models when the quantity of data is expected to be massive in the coming years.
Keeping The Bucks Rolling: Monetizing Shallow Hanging Fruits Through Behind Casing Opportunities and Strategic Collaboration
Authors: Zulkipli Siti Najmi , Harun Norhana
Published: October 2019

Maximizing production and sustaining it as much and as long as could is the aspiration to all oil and gas key players. Current producing reservoirs may not giving good yield till the end of expected production life due to depletion and watered-out issue. Presence of prolific reservoirs with thick pay zones and excellent quality are also becoming scarcer. Hence, prior to the onset of production decline, efforts to arrest it need to be addressed strategically both in short-term and long-term basis. This paper will present several case studies on monetizing behind casing opportunities (BCO) to assist in production enhancement as well as adding value to the reserves portfolio.

Identifying BCO opportunities starts by screening the potential from several sources including idle wells, wells with declining rate less than 200 bopd and high water-cut and also wells with new unperforated reserves to be put on stream. Comparison of nearby wells performance and generating stick plots to detect fluid contact movement will be part of the screening stage. Application of in-house reservoir enhanced modeling (REM) to reveal those new promising reserves which are masked by thin lamination, low resistivity and high silt content proves to have an astounding impact in production gain which are further ranked for execution priorities. To support industrial collaboration, all high risk, high cost and complexity well candidates could be clustered under special contract arrangement where the solutions, technology and execution methods will be proposed by the service providers.

Results indicated minimum of 1489 bopd of instantaneous gain is recorded with significant new reserves addition which further open-up new opportunities for appraisal and development drilling campaign. String management has improved by 20% due to idle wells reactivation, 14.8% reduction in water-cut and even 2 years extension of well economic life. Through strategic collaboration with service companies, several new technologies are successfully unlocked to deliver the barrels at minimum 15% cost optimization with the ‘know-how’ technology being replicated to similar facet of production business across the company.

In a nutshell, BCO and strategic collaboration are two major pipelines for expanding resource base and generating the cash. The efforts must continue with more success being replicated and bringing more technology to initiate chain impact to production growth.
An Approach to Benchmark Summaries of Core Data and Procedures for North Kuwait Heavy Oil Fields, Against Similar Heavy Oil Operations in Other Countries
Authors: Saikia Pabitra , Freeman Michael , Choudhary Pradeep , Tyagi Aditya , Zhang Zhiyi Ian , Benham Philip , Warrlich Georg , Gomez Fernando , Al-Terki Abdulrazaq , Ahmad Fatma , Ahmad Khalid , Al-Wael Hamad , Taqi Fatma , Al-Boloushi Ahmad , Al-Doub Abdulaziz , Al-Rabah Abdullah
Published: October 2019

Challenging aspects to heavy oil field development are the large volume of data which is collected, in particular from cored evaluation wells, and the difficulty in evaluating of the quality of such data. This paper outlines an approach to summarize coring data and procedures from two heavy oil fields in North Kuwait, and then to compare those summaries with similar heavy oil operations in other countries, in order assess their quality and degree of representativeness.

For two North Kuwait heavy oil fields, data was tabulated for the cumulative amounts of core cut and recovered relative to their field areas. This data was then further analyzed to summarize recovery by rock type, and assess the quality and quantity of plug samples collected. Benchmarks were established by summarizing core data from similar heavy oil operations in other countries, and the North Kuwait heavy oil data was then compared with those benchmarks. In a similar manner, documented core handling procedures for North Kuwait Heavy Oil operations were compared with procedures from similar heavy oil operations in other countries.

The benchmarks which were used to compare North Kuwait Heavy Oil data summaries with other countries include the following: 1) Coring Well Area Coverage Densities; 2) Coring Well Vertical Coverage of Cap Rock and Reservoir Intervals; 3) Core Plug Sample Rate and Survival Rate; and 4) Core Handling Procedures and Volume of Coring.

For many of the benchmarks used, North Kuwait heavy oil operations compare favorably with similar operations from other countries. However areas of improvement were identified from these benchmarks in terms of areal core coverage, vertical core coverage, core plug rates and core handling procedures. It is expected that these improvements, when implemented, will lead to a more representative sampling of the areas and rock types (reservoir rocks, baffles and cap rocks) in North Kuwait. This in turn should lead to a better understanding of fluid volumetrics, reservoir characterization and subsequent life of field development. As well by applying a focused approach to future coring operations, a significant cost savings is expected relative to original evaluation well plans.

A significant product from this study is a large summary database of all coring information for two North Kuwait heavy oil fields, which can be queried by area, rock type and sample type. This data base has been compared with similar operations in other countries using a series of benchmarks. Planned future coring and sampling operations have been modified through the use of this benchmarking tool.
Development of the Hybrid Sand Control Screen for Surface Size Exclusion and Depth Filtration Media
Authors: Hosseini Seyed Abolhassan , Roostaei Morteza , Mahmoudi Mahdi , Alkouh Ahmad , Fattahpour Vahidoddin
Published: October 2019

Production from weakly and unconsolidated sand formations relies on the efficiency of the employed sand control method. Performance of current sand control devices is based on surface size exclusion and depth filtration depending on their geometry and application. In this study, we investigate the possibility of using the advantage of both mechanisms in a single device.

The standard cut point test was used to determine the micron rating of different meshes in order to categorize them in different classes based on the average pore size. Different mesh weaves, namely Dutch twill, reversed Dutch twill and square mesh screens with different micron rating were investigated in terms of filtration performance. In the next step, a dead-end filtration set-up was designed and commissioned to evaluate the flow performance and sand control capabilities of mesh screens. Additionally, a new, customized sand control device was designed and included in the testing matrix to compare its performance with the common mesh screens in the market.

Dead-end filtration results indicated that by choosing the proper combination of morphology, both optimized open to flow area (OFA) and sand control could be achieved. The custom designed hybrid screen performed better compared to other investigated mesh screens with similar micron rating, in terms of both flow and filtration performance. Therefore, the customization was found to be the key parameter to achieve the optimized design. This further emphasizes that by employing the hybrid benefits of surface size exclusion and depth filtration, one can reach the optimized sand control and flow performance. Regarding the weave of different mesh screens, the results did not show any trends that could lead to a conclusion of better performance of a certain weave. Further investigations are required under different testing condition to achieve a conclusive comparison between different mesh types.

This paper investigates the possibility of customized sand control design, which uses the hybrid benefits of surface size exclusion and depth filtration to reach the optimized sand control and flow performance.
Overcoming Challenges Resulting from Surplus Fuel Oil
Authors: Al-Azmi Mohammad Falah , Ojha Gunjan
Published: October 2019

Reduction of LNG prices has thrown up a very serious challenge for the Refining Industry as it is rapidly replacing the demand of the Fuel Oil. Refiners need to find a way for a suitable upgrade of the Residual Fuel Oil from the Crude Distillation Units (CDU). One of the most economical and attractive ways to do this is to process the surplus Fuel Oil in the Resid Fluidized Catalytic Cracking (RFCC). These days, higher amount of surplus Fuel Oil is resulting in Higher capacity RFCCs. However, does it come without any challenges? Certainly No. As we all know that the current market scenarios discourage production of Gasoline while emphasizing on maximizing Poly Propylene and Para Xylene. However conventional RFCCs are considered for producing Gasoline. So, we are left with a challenging question. How to minimize Gasoline from RFCC while increasing its capacity? It is rarely possible to reduce Gasoline production while increasing RFCC capacity. Sounds Impossible but this is made possible by an innovative Process Unit Reconfiguration in KIPIC. This article will highlight the various challenges associated with the increased RFCC capacity. This will discuss in detail how the optimum configuration is achieved for minimizing the Gasoline production and maximizing the feed stocks to downstream Poly Propylene and Aromatics complex to produce the valuable Polypropylene and Para Xylene. The paper will conclude that by an innovative Process Unit Configuration, the overall Gasoline quantity can be reduced by 15% even by almost doubling the RFCC capacity. It will also elaborate how the optimum configuration helps in reducing the overall CAPEX / OPEX of the units, increases the overall reliability, eliminates the dependence on the imported feed stocks and helps in value maximization of the intermediate streams. The paper will be of interest to anyone who is involved in carrying out the Configuration study for the secondary processing units of the Refinery and looking for optimum solution to the surplus Fuel Oil. It will provide an insight to the latest options available for upgrading the fuel oil to various products meeting the current market demands with minimum CAPEX and OPEX. The paper also focusses on how RFCC overall Reliability is increased and how yields of high value products is maximized from the unit.
Dynamics of Surfactant Flooding in Tight Carbonate Rocks
Authors: Rabbani Harris Sajjad , Osman Yossra , Almaghrabi Ibrahim , Rahman Mohammad Azizur , Seers Thomas
Published: October 2019

With the global increase in the demand for crude oil, the need to develop enhanced oil recovery techniques is crucial. These techniques must focus on how to displace greater volumes of trapped oil from within a given rock. Since carbonate reservoirs constitute over half of the world's oil reserves, research has recently shifted its focus on recovery techniques as they pertain to carbonate reservoirs. However, due to complex depositional textures and diagenetic processes, carbonate reservoirs are challenging in terms of recovery. In this study, a robust experimental core flooding setup is employed to assess the impact of wettability of tight carbonate rock in governing the effectiveness of surfactant flooding. A series of flooding experiments with well-defined boundary conditions were performed on the low porosity core plug samples of Indiana Limestone. The three core samples used in this study are referred to as FD3H, FD4H, and FD5H. The cores have an approximate dimension of 13 cm length and 3.8 cm in diameter. The porosity is in the range of 13-21% and the permeability is in the of 0.69 −2.17 mD. The core samples exhibited differing wetting characteristics: strongly oil-wet, moderately oil-wet and weakly oil-wet. Initially, the core samples were saturated with oil and then water flooding was conducted until irreducible saturation was achieved. Later, surfactant flooding was performed as a tertiary recovery technique. The experimental results demonstrate that the efficiency of surfactant flooding increases as the tight carbonate rock get more oil-wet. The strongly oil-wet core manifested highest oil recovery, whereas in the weakly oil-wet core the recovery efficiency as a result of surfactant flooding was least.
Laboratory Imaging and Phase Field Modeling of the Interaction of Hydraulic Fractures with Well Cemented Natural Fractures
Authors: AlTammar Murtadha J. , Alotaibi Talal E. , Sharma Mukul M. , Landis Chad M.
Published: October 2019

Induced hydraulic fractures in the field interact heavily with pre-existing natural fractures in the rock that are abundant in many formations. Most laboratory fracturing investigations in the literature consider pre-existing fractures as frictional interfaces with zero thickness. However, natural fractures in subsurface formations are often sealed with mineral cementing material of finite thickness. In this study, we present a novel experimental demonstration of the behavior of an induced hydraulic fracture as it approaches a cemented natural fracture utilizing a two-dimensional (2-D) hydraulic fracturing cell.

Sheet-like test specimens are cast with natural fractures of varied mechanical properties, thickness, and relative position to a fluid injection port. Plaster is used as the specimen matrix. The filling material for hard natural fractures are cast using hydrostone while soft natural fractures are cast using a mixture of plaster and talc. Several tests are performed to characterize the mechanical and flow properties of these materials. A novel method for casting the specimen matrix and filling material of the natural fracture is described and used to enable strong bonding between the natural fracture and specimen matrix. The test specimen is placed between two thick, transparent plates and constant, anisotropic far-field stresses are applied to the specimen. Fracturing fluid is injected in the center of the specimen and the induced fracture trajectories in several experiments are captured with high-resolution digital images.

We show a clear tendency for the induced hydraulic fracture to cross thick natural fractures filled with materials softer than the host rock and to be diverted by thick natural fractures with harder filling materials. The induced hydraulic fracture also tends to cross hard natural fractures when the natural fractures are relatively thin. In addition, the induced hydraulic fracture from the injection port is shown to be diverted by a thin, hard natural fracture that is placed relatively close to the injection port but crosses the same natural fracture when placed farther away from the injection port. Using our in-house numerical simulator that is based on the phase field approach, we model these laboratory experiments to gain insights into the observed fracture behaviors.

Our results provide clear evidence of the impact of natural fracture filling material, natural fracture width, and the induced hydraulic fracture length on the outcome of hydraulic fracture interaction with natural fractures. The small-scale, 2-D nature, and well-characterized properties of our laboratory specimens are also valuable for validating numerical hydraulic fracturing simulators that are capable of modeling the effect of pre-existing natural fractures on hydraulic fracture propagation.
Secure and Resilient Digital Oil Fields in Kuwait Oil Company
Authors: Al-Shammari R.. , Al-Mai N.. , Robert H.. , Charife Tamer
Published: October 2019

Over the years, cybersecurity threats have grown significantly, and securing Operations Technology (OT) assets is one of the biggest challenges within the oil and gas industry today. Poor security policies could lead to unauthorized access to business-critical assets, confidential information leakage and result in business disruptions causing HSE, financial, and reputational impacts. This paper details how advanced and robust security policies shall mitigate cybersecurity risks and enable a smooth execution of Digital Oil Filed (DOF) projects and other complex O&G projects involving high convergence between IT & OT environments.

The DOF projects include integration of Industrial Control System (ICS) network with corporate network at various levels, and this mandates consideration of multiple layers of security controls to implement a defense in depth strategy in order to secure ICS & Corporate infrastructure. It includes establishment of an integrated governance model that orchestrates the Cybersecurity Management System (CSMS) that encompasses IT & OT, define a secure architecture for ICS, lay enforcement zones to segregate ICS network from the Corporate/ Enterprise network by enabling strong firewalling/ intrusion monitoring policies, perform continuous monitoring and develop response capabilities to combat cyber-attacks/ intrusions. Additionally, the awareness level of the entire workforce should be escalated to ensure they are ‘cyber risk-aware’ and comprehend how crucial it is to incorporate ‘security sense’ at work. Since cyber-attack aimed at ICS environments heavily leverage physical security weaknesses to introduce a cyber-physical impact, it is quintessential to consider robust physical safeguards to protect marshalling rooms, control equipment, and the overall perimeter of facilities.

The "security" factor for DOF primarily focuses on the availability of the systems, minimizing downtime risks which is of paramount importance for Oil & Gas business. This paper focuses on KOC's comprehensive approach to secure its critical assets within DOF which comprises people, process and technology components that contribute towards achieving KOC's business objectives.
An Integrated Study of Probabilistic Formation Evaluation and Geomechanical Analysis to Investigate the Potential of Hydraulic Fracture Stimulation in Najmah Unconventional Shale Reservoirs
Authors: He Ting , Hornbrook John W. , Dharanidharan Bala , Al-Bahar Mohammad , Al-Sane Amal , Suresh Vandana , Hickey James J
Published: October 2019

The Najmah Shale, an organic-rich marl, is generally considered the primary source rock for hydrocarbons in Kuwait’s Jurassic and Cretaceous reservoirs. The purpose of this study was to estimate the original hydrocarbons in place (OHIP) and the geomechanical properties of the Najmah reservoir to aid in the design of a hydraulic fracture stimulation program in West Kuwait.

An integrated petrophysical evaluation utilized conventional and sidewall core measurements, and standard and advanced open-hole logs were used to estimate net pay, porosity, oil saturation, and geomechanical properties. Formation evaluation of the Najmah Shale as a potential unconventional reservoir posed numerous challenges. These challenges included the ambiguous effects that high total organic carbon (TOC) has on conventional porosity logs and resistivity logs and the associated shale volume estimations. In this study, a probabilistic multi-mineral model was developed to more accurately assess the TOC of the rock and the associated porosity, saturation, and clay volume. Advanced well logs, including spectral gamma ray and elemental spectroscopy logs, were used to improve the mineralogical model of the complex formation. Routine core analysis, programmed pyrolysis, and X-ray diffraction (XRD) analyses were used to verify and calibrate the multi-mineral model results. Since a dual-porosity system was present in the formation, the Simandoux saturation equation was used to evaluate the fluid saturations. Anisotropic horizontal stress profiles were developed for specific wells based on analysis of dipole sonic logs, resulting in a greater regional understanding of the target interval.

Based on the results of the multi-mineral modeling, the average TOC of the Najmah Shale varies from well to well throughout West Kuwait, with values as high as 14.8%. The effective porosity of the Najmah Shale ranges from 1 to 8%. Water saturation is low for these organic-rich formations. Water zones may occur above or below the organic-rich interval depending on the location. The geomechanical properties of the Najmah Shale are conducive to hydraulic fracture stimulation, by analogy to proven productive shale plays. The Sargelu interval, below the Najmah Shale, exhibits distinctly higher minimum horizontal stress gradients while the limestone above the Najmah Shale presents a weaker stress barrier.

The results of the probabilistic formation evaluation of the Najmah Shale indicated that a significant volume of hydrocarbons is present in the formation. The geomechanical properties of the Najmah and adjacent units are conducive to successful hydraulic fracture stimulation. The evaluation of water-bearing zones adjacent to the target formation is critical to the investigation of the formation’s stimulation potential.
A New Algorithm to Quantify the Productivity of Hydraulically Fractured Horizontal Gas Wells
Authors: Mohamed Abdelmjeed , Abdalla Mohamed , Alnuaim Sami
Published: October 2019

Multi-stage hydraulic fracturing is considered as a solution to low-productivity wells when the reservoir properties are not good enough to produce oil or gas naturally. The Inflow Performance Relationship (IPR) is the most common method used to evaluate well productivity. Many models have been introduced to estimate the IPR for horizontal wells. However, a significant error will result when they are applied for fractured horizontal wells. This work introduces a new IPR model to estimate gas production rates from multi-stage hydraulically fractured horizontal gas wells at different well pressures.

A single-horizontal-well simulation model was built to generate the production data, and several scenarios were created by changing different parameters, such reservoir permeability anisotropy and fracture properties (fracture dimensions, conductivity, and the number of fractures) to determine the parameters that significantly affect gas production rates from such wells. After the effective parameters were determined, 70% of the resultant data was used to develop the new IPR model using nonlinear regression techniques, while 30% of the data was used for testing. Afterward, a statistical study was performed to evaluate the proposed model to ensure its accuracy in estimating gas production rates using different statistical means, such as R-squared, mean percentage error, variance, and standard deviation.

The term dimensionless conductivity was introduced to simplify the model. This term is a combination of reservoir permeability, fracture half-length, and fracture conductivity. The gas production rate was found to be a strong function of the ratio between vertical and horizontal permeability, the number of fractures, and fracture conductivity, while the height of the fracture and the half-length had no significant effect on the dimensionless IPR curve. The new model showed an excellent performance in estimating gas production rates for hydraulically fractured horizontal wells with a mean percentage error of 3.06% and R-squared of 0.9966.

This study introduced a new simple and reliable IPR model that accurately estimates the gas production rates from multi-stage hydraulically fractured horizontal gas wells at different flowing bottom-hole pressures.
Optimization of Development of Heavy Oil Reservoirs through Geochemical Characterization
Authors: Canbaz Celal Hakan , Deniz-Paker Melek , Hosgor Fatma Bahar , Putra Dike , Moreno Raul , Temizel Cenk , Alkouh Ahmad
Published: October 2019

Geochemistry is not only a well-known tool in providing a better understanding of the distribution of fluids in the reservoir rock but also an efficient kit in developing reservoir by decreasing the uncertainty throughout the characterization process. Utilizing geochemistry, not only efficiently identify the fluids and type of oil alteration drastically laterally and vertically over short distances in heavy oil reservoirs where such differences are of significant importance in production of heavy oils in these already challenging reservoirs, but also outline the value of geochemistry to justify the value of information in the process of more robust reservoir characterization and management of heavy oil reservoirs.

A conceptual model representative heavy oil reservoir recovery is utilized to compare the recoveries between a case where geochemistry is applied to characterize the reservoir and another case where geochemical methods are not employed by using a full-physics commercial reservoir simulator. A sensitivity and optimization software is coupled with the reservoir simulator to outline the relative significance of the important parameters in the recovery process.

Geochemical characterization, not only, provides information on gas content and its likely behavior where it can also lead to better decisions on completion strategies to avoid zones of different viscosity, but also the essential correlation between the geochemistry and the thermodynamics of heavy oil. Comprehensive reservoir characterization leads to a more robust identification of reservoir fluids where such knowledge will greatly enhance the efficiency thus the economics of the process that is especially important in low oil price environments. There is lack of studies recently on the application of geochemical characterization on the recovery of the process analyzing the relative significance of components, key drivers and the value of the information throughout the process, even though some authors have been published their research on geochemistry and its use in the characterization of the reservoirs. Our study outlines a comprehensive background including latest developments, investigates the key factors, and the value of information on comparative cases considering the relevant components of the process.
New Robust Model to Evaluate the Total Organic Carbon Using Fuzzy Logic
Authors: Mahmoud Ahmed Abdulhamid , Elkatatny Salaheldin , Ali Abdulwahab , Abouelresh Mohamed , Abdulraheem Abdulazeez
Published: October 2019

Total organic carbon (TOC) is an essential parameter used for unconventional shale resources evaluation. The current methods for TOC determination are based on conducting time-consuming laboratory experiments or by using empirical correlations; the later are developed based on assumptions that restrict their applicability. This study provides a new robust model for TOC estimation based on conventional well logs. The model was developed using an adaptive neuro-fuzzy inference system with subtractive clustering (ANFIS-SC).

Four conventional well logs of deep resistivity, sonic transit time, gamma ray, and formation bulk density collected from Barnett shale formation were used to develop the ANFIS-SC model for TOC estimation. A dataset consists of 645 records of the four well logs and TOC were used to develop the new model. The model was optimized for the different combinations of the ANFIS-SC’ design parameters and for training/testing data ratio. The optimum predictability of the ANFIS-SC TOC model was reached after 400 iterations using a cluster radius of 0.3 and a training/testing data ratio of 70/30.

The statistical analysis showed that TOC is a strong function of the bulk density, moderate function of the sonic transit time and gamma ray, and a weak function of the deep resistivity. The training and testing results proved that the developed ANFIS-SC model is able to predict the TOC based on the four mentioned well log data with high accuracy. For the training data set, the TOC was estimated with an average absolute percentage error (AAPE) of 8.62%, a coefficient of determination (R2) of 0.91, and a correlation coefficient (R) of 0.96. For the testing data set, the associated AAPE in predicting the TOC is 9.57%, while R2 and R between the actual and predicted TOC are 0.89 and 0.94, respectively.
Laboratory Study on Polymer Mechanical Degradation in Carbonate Core Plugs Versus in Capillary Tubes
Authors: Cao Dongqing , Han Ming , Leng Zhenpeng , Wang Jinxun
Published: October 2019

Polymer mechanical degradation can be induced by high flow rate during the injection in subterranean formations, especially near-wellbore regions. This work presents a study on the polymer injection in carbonate core plugs and capillary tubes at different injection rates in order to assess the critical shear rates beyond which significant polymer degradation takes place. The polymer degradation process in capillary tubes is correlated with that in the carbonate core plugs, which facilitates the degradation assessment.

A semi-dilute polymer solution in synthetic injection water was injected into carbonate and sandstone core plugs with different permeabilities and length. The collected effluent solutions were monitored by viscosity measurement using a rheometer and molecular weight distribution measurement using gel permeation chromatography (GPC). Similar procedures were followed for the polymer mechanical degradation using capillary tubes with inner diameters of 0.12, 0.254 and 0.508 mm.

Flow in porous media induced severe polymer degradation at a flow rate above the critical shear rate. The carbonate cores showed lower critical shear rates than the sandstone cores. For carbonate core plugs with permeability 390md and 60md, the critical flow rate was 20mL/min corresponding to a shear rate of 4402.1 s-1 and 2mL/min corresponding to a shear rate of 1122.2 s-1. For the sandstone core plugs with permeability 490md and 40md, the critical flow rate was 10mL/min corresponding to a shear rate of 2198.0 s-1 and 1mL/min corresponding to a shear rate of 771.5 s-1. It was observed that greater polymer degradation appeared in the flow through the lower permeability core plugs. Core length had limited effect on the degradation. The average molecular weight became smaller while the molecular weight distribution became wider for the polymer solutions after the mechanical degradation, indicating the irreversible fragmentation of polymer molecules. In comparison, polymer degradation in capillary tubes appeared at a critical shear rate in the magnitude of 200,000 s-1. Similar with the scenarios of polymer injection in core plugs, greater viscosity loss happens in the flow through smaller capillary diameter. By the correlation, the polymer degradation in carbonate core plugs can be predicted by the measurement in the capillary tubes.

This work provides the insight of polymer mechanical degradation in carbonate matrix. An easy-to-operate method on the evaluation of polymer mechanical degradation was developed to assist in the operation of the polymer injections.
Utilising Advanced Mud Gas Assessment SATLOG for De-Risking in Business Development
Authors: Pedersen Rasmus , Opsal Jan Gunnar , Kråkenes Kristian , Harrison Darrell
Published: October 2019

A case study is presented, by KUFPEC Norway AS in cooperation with Searcher Geoservices AS, introducing an advanced mud gas evaluation workflow (SATLOG). Results from well analyses are used to aid in the screening, ranking and prioritising of business development opportunities in a strategically important KUFPEC core area in the Norwegian North Sea.

The unique SATLOG approach is based on the reprocessing of digitised mud log well data (gases, C1 to C5) along with analysis of available drilling parameters, core data, and both seismic and wireline log interpretation.

The background for this study is a new ventures and business development initiative in a KUFPEC core area close to the Gina Krog and Sleipner Fields in Norway.

In summary, these SATLOG interpretations can aid in re-classifying well results and highlight one missed discovery and indicate a number of wells may have missed oil pay. This information is vital to the in-house KUFPEC Norway evaluation and prioritising of business development opportunities in the area.

The SATLOG (advanced mud gas) assessment was performed on multiple wells, with a focus on the chemical signature present in producing fields and discoveries. This was followed by a detailed comparison to the wells containing oil shows and wells stated to be dry. In the study area, several wells are formally defined as dry with no shows, however, the SATLOG study indicates that some of these dry wells could hold significant hydrocarbon saturation in missed pay and up-dip accumulations on the scale of 100-150 million barrels STOIIP.

In addition, the SATLOG assessment highlights that some areas can be deemed to be of limited interest as lateral barriers or ineffective migration paths are clearly indicated.

The novel aspect of utilising SATLOG together with seismic and wireline interpretation is the ability to cost effectively re-interpret existing data and gain new and vital knowledge of upside potential in new ventures and business development initiatives in strategically important core areas.
Downhole Energy Harvesting From an Isothermal Well Zone by Converting a Differential Pressure into a Differential Temperature and Combining Thermo-Generators for Smart Well Completions
Authors: Noui-Mehidi Mohamed Nabil , Rizq Ahmed
Published: October 2019

The present paper is concerned with a new method for downhole energy harvesting from an isothermal well zone. It is shown that in a horizontal well compartment where there is thermal equilibrium, the pressure differential between the sand face and the wellbore can be converted into temperature differential using a vortex tube system. The flow, pressure and temperature measurements using the vortex tube in a physical model are correlated to the amount of energy generated with different pressure ranges expected in the well environment. The data reveal that the energy generated can charge substantially a battery to operate downhole sensors and control devices.
Geologic, Seismic, Climatic and Oil Production Controls on Hydrocarbon Seepages at Al-Ahmadi Town, South-Eastern Kuwait
Authors: Ibrahim Muhammad W
Published: October 2019

A series of explosions destroyed several houses at Al-Ahmadi Town in southeast Kuwait during 2010 and 2011; they were initially attributed to gas leakages from discarded old domestic gas supply system. The incidents led Kuwait Oil Company (KOC) to commission a surface geochemical survey of one of KOC's Al-Ahmadi housing blocks which was affected by the explosions. A serious gas explosion in Al-Ahmadi on the 18th of May 2015 prompted an evacuation of a number of Al-Ahmadi houses, followed by a prolonged investigation of the source(s) of the recurrent gas leakages. This paper is a review of the published surface geology, subsurface stratigraphy, seismic structural motives and consequences of prolonged production operations of Greater Burgan Oil Field (with special focus on the surface and subsurface stratigraphy and structure of the Al-Ahmadi Ridge of Greater Burgan Oil Field, which is situated beneath the afflicted Al-Ahmadi Town) in search of natural seepage(s) rather than man-made leakage(s) of the exploding gas. The review revealed that the gas explosions were not likely caused by trapped gas in the discarded domestic gas supply network, and argue for an imperfect Greater Burgan oil trap, with inherent ancient oil and gas seepages propagated by environmental side effects of prolonged oil production operations, which attained recurrent cycles in response to climatic seasons, and probably amplified by the occasional regional earthquake seismic waves. The review concludes that under current environments and production practices, the historic trend projects an increase in the volume and number of gas seepages sites over and beyond the footprint of Greater Burgan Oil Field. Furthermore, the review recommends some habitat gas seepage mitigation measures and the deployment of mobile technologies for regular surveying and monitoring of Methane and H2S build-up in the air, and in the shallow subsurface reservoirs below the Ahmadi Town as routine risk management procedures.