bluuebunny/crossref_metadata_2025 huggingface dataset:
Numerical Investigation of Non-Darcy Flow Regime Transitions in Shale Gas Production
Authors: Berawala Dhruvit Satishchandra , Østebø Andersen Pål
Published: November 2019

Shale gas reservoirs are organic rich formations with often ultra-low permeability. Gas is stored in free and adsorbed form. Conventional Darcy flow cannot fully describe the gas transport in such porous media. It is thus crucial to study the shale gas production considering different flow regimes and time dependent permeability, which can improve well-induced fracture design and ultimate gas recovery. In particular, this paper will focus on the transition in non-Darcy flow regimes near fracture-matrix interfaces using mathematical modelling. Especially, we investigate conditions at which these effects vanish, and Darcy flow assumptions become reasonable.

The model describes a representative well-induced high permeability fracture surrounded by shale matrix. Investigated Non-Darcy mechanisms include apparent permeability, Knudsen diffusion, gas desorption and Forchheimer flow. Pressure diffusion is the main driving force for single phase gas flow from the matrix to the fracture and from the fracture to the well. Pressure dependent gas desorption is defined by Langmuir's isotherm and is a key production mechanism. The composition and flow properties of free and desorbed gas are the same. This model is implemented in Matlab using Marcellus shale field data.

Scaling the model shows that recovery of gas depends on two dimensionless numbers that incorporate geometry relations, time scales of flow, intrinsic variables of the porous media, non-Darcy constants, adsorption and boundary conditions. The model is initialized using laboratory and field scale measurements and investigated by sensitivity analyses. The dimensionless numbers define if the fracture or matrix control the gas production rate. When one of the media limit production, the non-Darcy flow mechanisms in the other medium have reduced importance due to lower rate in that medium. In such cases, it is less important to include non-Darcy mechanisms. It is also concluded that slippage effects impacts gas production but can be accounted for in a simpler manner in the model. By checking the magnitude of selected dimensionless numbers, the modelling approach can be determined in advance and huge computational time can be saved.

The proposed model provides a tool for interpretation of complex shale gas production systems. It can be used for screening of flow regimes at different operational configurations and hence appropriate modelling approaches. The model can be used to optimise fracture network design and potentially in identifying stimulation operations that may significantly improve production rates and ultimate recovery from unconventional gas reservoirs.
Successful Float Over Installation by Portable DP Vessel
Authors: Abu Bakar Azlan
Published: November 2019

Float over topside installation has become a cost effective alternative for offshore construction over the past 25-30 years, as ever-increasing integrated topside weight constantly exceeds the lifting capacity of installation vessel cranes.

The basic concept of float over installation is to transport the topside on a vessel in one piece, position the vessel over the substructure, and lower the topside onto the substructure while maintaining the position of the vessel.

While this basic principle of loadout and transportation remains the same, methods and systems used to execute the concept vary significantly, and pose numerous technical and operational challenges.

PETRONAS Carigali Sdn. Bhd. (PCSB) undertook the development of BARDEGG-2 and Baronia EOR project located offshore Sarawak, Malaysia within South China Sea. Baronia B Central Processing Platform (BNCPP-B) was installed in May 2017 and was the first PCSB's float over installation by a portable Dynamic Positioning 2 (DP2) vessel.

A Deck Transportation Vessel (DTV) was upgraded with DP2 capability by adding two portable azimuth thrusters to allow safe and efficient installation of the topside. Sea trials and annual DP trials were conducted in ensuring DP functionality and performance in compliance to Class requirement. Float over engineering was performed including float over design criteria, hydrodynamic analysis and mating analysis. All outfitting, secondary steel works and grillage structures were installed on the vessel before mobilization for transportation and installation of BNCPP-B Topside.

The operation required high precision engineering and execution considering the close proximity between BNCPP-B Topside and existing BNQ-B platform during the vessel approach towards BNCPP-B Jacket. Additional control measures were taken for safe execution. DP checks were conducted at certain intervals while approaching the jacket. BNCPP-B Topside installation commenced at first daylight on 22 May 2017 and successfully completed by noon.

It has again proven that float over installation by portable DP2 vessel was technically feasible and would be an example for future projects undertaking the same approach. Having a vessel with portable DP2 system will help to optimize the vessel utilization and improve overall project cost.

This paper aims to highlight the float over methodology for BNCPP-B topside using portable DP2 vessel and the technical challenges for offshore execution. The activities during the float over operation, analysis and simulation methods are also presented in this document.

This paper should be an interest to those who will perform the offshore installation via float over method utilizing Portable DP Vessel.
Sequential Failures in Incident Investigation Process Hindering Prevention of Incidents
Authors: Tayab Muhammad , Valappil Suhail , Shah Vishal , Azhibekov Takhir , Zeinati Michel , Al Ameri Mohammed , Al-Hameli Fatima
Published: November 2019

Over the last 10 years, Oil & Gas operations have come under tremendous pressures due to increasing production demands and economic conditions, demanding higher performance and venturing into technically challenging operating conditions. Operating with aging facilities in harsh environmental conditions and higher crew turnaround, have resulted in higher number of serious incidents. Prevention of incidents remains high on the agenda of oil & gas companies and focus is placed on incident investigations to identify root causes of incidents and development of corrective actions. However, repetition of incidents with similar findings and causes have been observed, raising concerns if right root causes were identified and focused corrective actions were identified and/or implemented.

An extended analysis of over one thousand (1000) incidents was conducted to assess degree of repetition of causes and regrouping of causes to assess linkage of human factors with organizational behaviours. It was found that 31% of incidents were triggered by human errors & mistakes whilst 27% were attributed to violations. All violations were deemed as intentional & routine and further investigation was not undertaken. Management Supervion & Employees Leadership was identified a leading root cause category of incidents and this category contributed 20% of incidents followed by Work Planning (18%) and behaviour (12%). 55 % of incidents were caused by human factors and hauman factors were triggered by errors and mistakes rather than violations.

Often efforts are exerted to to influence individual's behaviour however human attitude (cognitive, emotional and commitment) is overlooked as linkage between attitude change leading to behavior change, not fully explored. However, linkage from behavior change to attitude change is much stronger. If worker consciously change their behavior, it requires re adjustment of associated attitudes to align with the new behavior. Positive reinforcement is an effective tool to influence individual's behaviour. If discipline and punishment are used to discourage unsafe behavior, the intended results are not achieved (e.g., incident or near miss are not reported for fear of sanctions).

Assessment of non-compliant behaviors (Violations, mistakes and errors) & conditions and factors influencing such behaviors are often not evaluated and focused action plans to address abilities and motivations with due consideration to isolated or systemic conditions are instrumental in preventing incicidents.
Multi-Scale Compaction Well Operability Limits
Authors: Garzon Jorge , Hsu Sheng-Yuan , Shenoy Karthik , Tenny Matthew J. , Meier Holger A.
Published: November 2019

Wells that are used to recover hydrocarbons from reservoirs are subjected to large amounts of complex geomechanical loads that may compromise the well's integrity over its operating lifetime. While the reservoir depletes, the pore pressure in the rock reduces and the effective stress in the rock formation increases. As a result, the rock deforms and the reservoir experiences an overall volume reduction (compaction). Under such compaction, any well casing experiences a substantial amount of compressive and shear stress/strain in all directions. In order to ensure safe operation of a well, it is necessary to impose operational limits (drawdown and depletion) so that stresses imparted on the casing do not exceed the casing strength. This problem has been studied in the past [1,2,4,6,8,10] and due to computational complexity and cost, past methodologies have used simplified analytical solutions or decoupled modeling by separating the large scale deformation of the rock (3D model) from the casing behavior (2D model). These simplified methodologies rely on choosing an a priori failure mechanism and also make assumptions on how the load transfer happens between the rock and the well hardware. Based on our experience, this approach is conservative and leads to poor approximations. In this study, a fully detailed two-scale 3D Finite Element (FE) model is used to simulate various drawdown and depletion combinations derived from a reservoir model simulation. The large-scale model captures the far-field effects of drawdown and depletion as well as the effects of neighboring producer wells. The small-scale model includes details such as casing, cement, perforations, and surrounding rock. This approach is not constrained to a specific failure mechanism (axial compaction, pipe collapse, bending or shear), but rather includes all possible deformations based on rock mechanical behavior, stress, pressure change, and geometry. Thus, complex casing deformations with different failure locations can be observed.

This technology has been applied to a number of business units within ExxonMobil, allowing us to establish practical drawdown/depletion limits. In this paper, we discuss a field example of this approach.
Evaluation About Adsorption Gas and Free Gas Content Inside Shale Matrix under a Wide Range of Atmosphere Conditions
Authors: Sun Zheng , Shi Juntai , Yang Zhaopeng , Wang Cai , Gou Tuobin , He Minxia , Zhao Wen , Yao Tianfu , Wu Jiayi , Li Xiangfang
Published: November 2019

Much attention has been attracted by the successful development of shale gas reservoir in recent decades. Correspondingly, research aspects of shale gas reservoirs become more and more heat among the academic community, especially in the fields of nanoscale gas transport mechanisms as well as the storage modes. Fascinated by the craft interactions exerted by organic or inorganic shale surface, drastic discrepancy takes place in terms of the gas behavior inside the nanoscale dimension and that in conventional dimension. It is crucial to figure out the exact influence on shale gas recovery and overall production efficiency due to the above large difference. Notably, this paper is designed to comprehensively explore the methane storage behavior in shale nanopores, expecting to provide the direct relationship between adsorption gas and free gas content under various environmental conditions. Also, a novel and simple prediction method with regard to ultimate gas recovery is proposed, which is connected to the pore size distribution and formation pressure. First of all, the gas storage modes in a single nanopore with defined pore size are analyzed seriously. As a result, the evaluation model is constructed for adsorption gas and free gas content in a single nanopore. After that, an upscaling method is applied to extend the adaptiability of the model from single nanopore to nanoporous modia. Finally, sensitivity factor analysis work is performed and a recovery prediction methodology is developed. Results suggest that the adsorption gas content will be a larger contribution to total gas content when it comes to small pore radius and low formation pressure. In contrast, free gas content will increase with the increasing pressure and pore size. More importantly, pore size distribution characteristic has a key impact on gas storage modes and ultimate gas recovery. The high proportion of small nanopores plays a detrimental role on gas recovery, resulting in large content of adsorption gas at low pressure, which will not be produced and remain in shale gas reservoirs.
Direct Thickening of Supercritical Carbon Dioxide Using CO2-Soluble Polymer
Authors: AlYousef Zuhair , Swaie Othman , Alabdulwahab Amin , Kokal Sunil
Published: November 2019

Two major applications of injecting dense carbon dioxide (CO2) into the petroleum reservoirs are enhanced oil recovery and sequester CO2 underground. For enhanced oil recovery applications, CO2 has low miscibility pressure causing the swelling of crude oil and reducing its viscosity therefore improving the macroscopic sweep process. However, the low viscosity of injected CO2 compared with the reservoir fluids causes the fingering of CO2, which may lead to bypassing huge amount of oil, early breakthrough of CO2, and increasing the gas to oil ratio (GOR). The use of direct thickeners, such as polymers, is one of the techniques used to increase the CO2 viscosity. Nevertheless, the solubility of polymers in CO2 and the high cost of soluble polymers are the main challenges facing this technique. In this study, a novel, soluble, and cost-effective thickener is proposed to directly increase the CO2 viscosity.

In this study, a PVT high pressure and high temperature (HPHT) apparatus was used to evaluate the compatibility and the solubility of the thickener in dense CO2. Also, a custom designed apparatus was used to measure the viscosity of dense CO2 in the presence of the thickener at different conditions. The assessment was conducted at different experimental pressures, temperatures, and thickener concentrations. The effect of pressure on the solubility of the thickener in CO2 and on the measured viscosity of CO2 was evaluated at 1500, 2000, 2500, and 3000 psi. Also, the influence of temperature was evaluated at 25 and 50°C. Moreover, the concentrations used to study the effect of thickener concentration on the measured viscosity of CO2 ranged between 0.10-2 %.

The results from laboratory experiments clearly demonstrated that the addition of the thickener at certain conditions can significantly impact the dense CO2 viscosity. The results revealed that there must be a minimum pressure at which the thickener dissolves in the dense CO2. The solubility of the thickener can occur when the CO2 is either in the liquid or supercritical phase. The results also pointed out that the CO2 viscosity increased as the pressure increased. The increase of CO2 pressure can significantly impact the solubility of the thickener in the dense CO2 and consequently the CO2 viscosity. The increase of the thickener concentration also had a significant impact on the measured CO2 viscosity. The results showed that the CO2 viscosity increased with the thickener concentration. The CO2 viscosity increased 100 to 1200 -fold as a result of adding the thickener depending on the experimental conditions
Optimization of Corrosion Inhibitor for a Gas and Condensate Field
Authors: Hirano Susumu , Sunaba Toshiyuki , Sasaya Kazuyo , Kobayashi Atsushi , Yorozu Hirokazu , Iijima Hironari
Published: November 2019

Qualification of a new corrosion inhibitor was carried out for both tubing and flowline services in a gas and condensate field because the production condition changed. The methodology and result of the inhibitor evaluation under a sweet condition was summarized. The depth of production well is 4,500 m and the bottom hole temperature and pressure are 180 °C and 50 MPa respectively. Two brands of corrosion inhibitors had been used for production tubing and flowline respectively in the field. A new inhibitor was investigated for the both applications. The performance of corrosion inhibitor efficiency was evaluated with a rotating cage autoclave. In order to evaluate the tendency of emulsion forming, Oil, brine and an inhibitor were poured into a centrifuge tube and it was shaken intensely. Gas chromatograph - mass spectrometer (GC-MS) and Fourier transform infrared spectroscopy (FT-IR) were studied to measure the residual amount of inhibitor. Finally the field trial was carried out with the new inhibitor. The new inhibitor was adopted successfully for the both services. The GC-MS analysis showed the flow back lasted more than two hours. The risk of emulsion forming became lower because the mixing of two brands of inhibitors was avoided. Reducing the number of the chemicals contributed to reduction of the operation cost too.
Field Application and Performance Evaluation of Polymer Microsphere Profile Control in Low Permeability Oil Reservoir
Authors: Jia Yuqin , Yang Haien , Cheng Chen , Li Zhiping , Hou Ganggang , Yuan Xinyu , Zhao Wenyue , Zhang Zhen , Liu Tongjing
Published: November 2019

During the development of low permeability oil reservoirs in Changqing oilfield, the nonuniformity of injection profile is a commonly seen problem. Conventional profile control methods face the difficulty caused by hard injection and poor reservoir adaptability. Polymer microspheres (PMs) are considered to have good profile control capabilities due to their properties such as hydration swelling and plugging. Therefore, it is proposed to use PMs profile control method to improve the oil recovery in low permeability reservoirs. There are two key factors for the success of PMs profile control, which are matching relationship and plugging properties. In this paper, the average pore throat diameter of the pilot test area was calculated, and the hydration swelling properties were studied by measuring the diameter of PMs. The plugging properties of PMs were studied by displacement experiment. Based on the experimental research, in 2016, 4 well groups in Changqing oilfield were selected for PMs profile control. Calculation results showed that average pore throat diameter of the study area was 2.28μm. The diameter of 800 nm named PCE been selected for PMs profile control. The hydration swelling experiment results showed that PCE initial average diameter was 784nm. After 13 days of hydration swelling, PCE average diameter was 2798 nm and increased by 2.57 times. The results of PCE displacement experiment showed that resistance factor, blocking rate and retention rate was 3.5, 71.42% and 96.22%, respectively. The performance of the PCE application in oilfield showed that 11 production wells were effective after PCE injection, and the success rate of profile control was 47.8%. The average validity period was 150 days. And a total of 1365.5t of oil had been increased during the validity period. For the injection wells, the average injection pressure and the thickness of water absorbing layers increased by 1.415MPa and 3.28m respectively.
Correlation of Wellbore Geometry with Geo-Mechanics and Drilling Practices in a Giant Offshore Field in Abu Dhabi
Authors: Iftikhar Choudhry Bilal , A. Shaver Michael , Abdulrahman Alzaabi Mohamed , Toki Takahiro , Al - Ali Salim , Khaled AbdelKarim Islam , R. Oviedo Vargas Mario , Torres Javier , Ahmed Osman Mohamed , Alfonso Mendez Freddy , Vican Kresimir , Yee Lee Chung
Published: November 2019

Over the course of drilling wells in one of ADNOC Offshore fields, there have been numerous endeavors in the Crestal region of the field with each well presenting its unique array of issues and challenges related to well construction, stability and delivery. Even while drilling two identical wells with extremely similar well designs and architecture, the wells encountered different and at times opposite responses from the formations being drilled. This resulted in the well construction becoming more problematic than expected in some cases while in others the situation was completely opposite, thus drilling and well construction went extremely smooth delivering the well ahead of time as opposed to the nearby sister well.

While the denominators may be segregated based on commonality and differences, there is one particular aspect of the drilling process and planning that has been significantly overlooked, the Azimuth of the well particularly in the crestal region of the field. Over the years, investigation into the well trajectory, the well fluids and intrinsic properties have been dissected to arrive at a result but has not produced the expected success. The Azimuthal impact on the resultant seems to have been ignored to the extent of not understanding the Azimuth impact on a well trajectory. It is of paramount importance to investigate and identify the imp act since the related stresses and their directions directly define and drive the stability and the optimal mud weight needed to drill successful wells.
Recognition and Mitigation of the BHA Lateral Vibration Chatter Mode
Authors: Bailey Jeffrey R. , Lathi Harshit , Prim Matthew T. , Carson Andrew D. , Tenny Matthew J. , Payette Gregory S.
Published: November 2019

Lateral vibration modeling of certain BHA (bottomhole assembly) designs has shown great sensitivity to the proximity of stabilizer blades. This paper will explore the nature of the vibrational dysfunction that we call BHA chatter. A frequency-domain model that has been field-proven shows how this dysfunction occurs, its rotary speed dependence, and mitigation methods and results.

A frequency-domain BHA lateral vibration model will be used to illustrate the role of the nodal point constraint in the determination of the dynamic side forces acting at stabilizer and LWD tool blade borehole contacts. These contact forces may be strong functions of rotary speed and BHA contact spacing, especially if the spacing is close.

The relationship between the dynamic contact forces and vibration index model results will be described in relation to the solution to the lateral vibration model. Examination of the dynamic contact side forces associated with these vibration indices reveals the nature of the dysfunction that the indices represent.

The contact forces that push a stabilizer blade to be constrained within a borehole include both static and dynamic components. The static forces are well understood. However, the dynamic forces are difficult to visualize as they are generated by the BHA in motion, and a well-formulated dynamic model is required to evaluate these forces.

Dynamic dysfunction at a particular location along the BHA is revealed by examining the underlying states of a dynamic model. Charts of the dynamic contact side force quantify the amount of dysfunction. Vibration indices comprising the integrated, length-averaged bending strain energy provide a good summary of the overall BHA response that is particularly useful in BHA design investigations, but it is the dynamics of the individual contact points that drive the dynamic response of the model.

Examples of field BHA designs illustrate both good and bad drilling results, generally in agreement with expectations based on the modeling. The literature is full of references to the whirl mode of lateral vibrations. This is commonly accepted. Chatter is a different mode that occurs primarily in response to the spacing of blade contacts. It is difficult for two blades that are close together to simultaneously serve as nodal points. A lateral vibration wave propagating along the BHA may generate alternating wall contact at the two blades, causing a dynamic chatter dysfunction.
Alleviation of Scaling Concerns and Controlling of Chemical EOR Under-Performance Risk for a Giant Sandstone Reservoir in North Kuwait
Authors: Al-Murayri Mohammed T. , Kamal Dawood S. , Khan Mohammad Y. , Al-Mayyan Haya E. , Abu Shiekah Issa , Shahin Gordon T. , Shukla Shunahshep R. , Bouwmeester Ron , de Kruijf Sander
Published: November 2019

An inverted 5-spot Alkaline Surfactant Polymer (ASP) pilot is planned for a giant sandstone reservoir in North Kuwait. Despite the development of a robust lab-optimized ASP formulation at reservoir temperature (90°C) and the execution of a successful Single Well Chemical Tracer Test (SWCTT), the combination of high temperature and divalent ion concentration (∼20,000 ppm) makes the implementation of a successful multi-well ASP pilot very difficult mainly due to the challenge of inorganic carbonate scale. This paper presents some unique challenges in connection with the design of an inverted 5-spot ASP pilot and discusses practical strategies to mitigate them.

Due to the high divalent ion concentration in the formation brine, the design basis for the planned chemical EOR pilot requires pre-flushing the reservoir using softened seawater prior to ASP injection. In the base-case scenario for the pilot, injection and production within the pattern were balanced to target a Voidage Replacement Ratio (VRR) of 1. However, it was realized that such a pre-flush strategy would still present significant carbonate scaling risk at the producers. In view of that, an extended softened-water pre-flush strategy (over-flush) was considered to alleviate the anticipated scaling concerns.

Simulations were carried out to explore various scenarios to work out the optimal over-flush strategy for the pilot to mitigate the potential for scale formation at the producers. It was realized that over-flushing the hot reservoir brine by large volumes of cooler surface water could result in significant cooling of the reservoir prior to ASP injection. This change in reservoir temperature compromises the performance the original lab-optimized formulation that was designed considering a reservoir temperature of 90°C. In view of that, careful re-tuning of the chemical formulation was necessary to make it robust for pilot conditions post softened water over-flushing.
Predict Oil Production from Geological and Petrophysical Data Before Hydraulic Fracturing Using an Improved Particle Swarm Optimization Based Least Squares Support Vector Machine
Authors: Feng Cheng , Li Jiahong , Feng Ziyan , Zhong Yuntao , Zhang Ning , Mao Zhiqiang
Published: November 2019

For no natural productivity, hydraulic fracturing is widely used in unconventional reservoirs. Thus, oil production prediction before hydraulic fracturing is crucial. In general, it is usually obtained based on percolation theory and fracture geometrical model from engineering data. However, before hydraulic fracturing, the obtained data are mainly geological and petrophysical data. Hence, predicting oil production from them before hydraulic fracturing can make a lot of sense for guiding fracturing design. Although geological and petrophysical data have complex and nonlinear relation with oil production after hydraulic fracturing, least squares support vector machine (LSSVM) is very suitable for such high-dimensional and nonlinear problem with small datasets. As the performance of LSSVM highly depends on parameter selection, an improved LSSVR is designed based on particle swarm optimization (PSO). The selected study area is tight oil reservoirs of Chang 8 Formation, Triassic, Ordos Basin, China. In order to build a reliable data-driven oil production prediction model, a systematic formation evaluation workflow is proposed. Firstly, choose wells with similar hydraulic fracturing type in the study area, which is the base. Secondly, the oil production prediction problem is converted into a classification problem by dividing the oil production into four levels. Thirdly, the dataset of 24 geological, petrophysical and engineering parameters from 85 wells are selected and constructed, reflecting lithology, physical property, saturation, rock mechanics, thickness and facies. Fourthly, 8 parameters, including density, the difference of neutron and density porosity, permeability, water saturation, effective thickness, Poisson's ratio, interlayer stress difference and displacement amount, are optimized as sensitive ones by principal component analysis (PCA). Fifthly, the data from 85 wells are separated into two categories: training and testing data, according to the proportion of 70% and 30%, respectively. The former are used to train the model, while the latter are used for verification. Sixthly, the improved PSO based LSSVM and the LSSVM are trained and tested via the dataset respectively. The tested results present that the coincidence rate of the prediction of the two methods are 88.06% and 81.16% respectively. This work verifies that predicting oil production from geological and petrophysical data before hydraulic fracturing via an improved LSSVM is feasible and cost-effective, which can be important for guiding fracturing design and providing scientific basis for deployment of development program.
Selection of Barium Sulphate/Barite Dissolver Chemical through Establishment of Standard Laboratory Screening Protocols
Authors: Raja Sahar Raja Nor , W Mohamad Wan Amni , Rustam Ali Khan Ema Farima , Mohd Hatta Siti Aishah
Published: November 2019

Barium Sulfate (Barite, BaSO4) scale is the most difficult scale to remove due to its low inherent water solubility. After more than 10 years of production in Field A, barite scales are recently found deposited in the tubing and at the topside in one of the oil producer wells. In this case, barite scales are precipitated through mixing of formation water containing high concentration of barium ions and injection seawater with high sulphate concentrations. Successful method of removing barite scales is using chelant based chemicals i.e. EDTA/DTPA. The best possible way to reduce failure risks of the pilot removal application using these chemicals for Field A is through series of lab testing. This paper describes the selection of barite scales dissolver chemicals through establishment of standard laboratory screening protocols prior to field applications in PETRONAS.

In the industry, there are various experimental methods to study the effect of barite dissolver chemicals on barite scales dissolution. Since PETRONAS has just recently encountered barite scales deposition issues, it is crucial to have a standardized protocol to ensure the effectiveness of the chosen chemicals to remediate the issue immediately. The protocol developed was based on various references and citations from other operators and chemical service provider.

The protocols are divided into three (3) sections in series i.e. characterization of deposit samples mineralogy, barite dissolution and chemical compatibility testing. Prior to barite dissolution tests, deposit samples collected from the wells/topsides are characterized through XRD/XRF analysis, organic scale identification/analysis and acid solubility test. Finally, the most effective barite dissolver chemical will undergo chemical compatibility tests with production fluids, incumbent production chemicals and core samples.

Barite scales deposits collected from Field A were found to be radioactive. Testing procedures were in-line with precautions taken to prevent risks exposure to these materials. Scale characterizations indicated samples are dominated by barium sulfate containing some small percentage of calcium carbonate scales and organic contents. Static disintegration and dynamic dissolution tests carried out shows significant results differences where application of barite dissolver chemicals in the well may require coil tubing assistance. Compatibility studies of the dissolver chemical with incumbent production chemicals shows suitability of the different chemicals when the well is flow back after treatment.
Innovative Machine Learning Method to Locate the Root Cause of the Unreliable Data Coming from Intelligent Field Equipment
Authors: Wasfi Bayan , Alqasimi Mohammed , Al Kadem Mohammad , Alghamdi Abdullah
Published: November 2019

Analyzing large amounts of continuous real-time data along with sustaining its reliability is a challenging task for engineers. Low reliability of data can prompt off base data examination results and make it difficult to make critical decisions in the oil and gas business, especially for the cases where the processing of data is continuous real-time data. One example is the continuous real-time data coming from Intelligent Field equipment. Intelligent field equipment for upstream can be a combination of Wellhead sensors, ESP, PDHMS, MPFM, SWC, SPFM, MOVs and H2S sensors. Intelligent Field equipment data follows specific transmission nodes as it flows from each sensor or instrument to a Remote Terminal Unit (RTU), to the Supervisory Control and Data Acquisition (SCADA) system, to a Plant Information (PI) data historian, and after appropriate filtration into the Exploration and Production (E&P) Corporate Database (Oracle), and finally into Petroleum Engineering developed applications. The unreliability of data can occur at any transmission nodes along this path. To discover the root cause of the unreliability, the Engineer must go through an exhaustive and lengthy process. Therefore, this paper introduces a promising methodology that tackles this challenge, by utilizing machine learning methods, to develop pattern recognition algorithms that recognize the transmission nodes where the unreliability of data appeared. Therefore, this paper aims to tackle two main challenges:Estimating data reliabilityDetecting the error location of unreliable data

By utilizing Machine Learning methods to develop pattern recognition algorithms that recognizes the transmission nodes where the unreliability of data appeared. Two out of three machine learning algorithms were selected; Decision Tree and Gradient Boosting (GB). Decision Tree showed an accuracy of 94.6%, while Gradient Boosting showed higher accuracy of 96.4% when estimating data reliability and error location determination. The robustness of GB over decision tree is that GB construct and train trees all at once while the latter train each tree independently. Training all trees at once helps to learn faster and reduce the error dramatically.
Best Engineering Practices in Standardization of Offshore Wellhead Tower Design – EPC Contractor’s Experience
Authors: Singh Sunil Kumar , Wasnik Rakesh , Singh Harendra , Kamal Faris Ragheb , Takieddine Oussama
Published: November 2019

The wellhead tower facilities in Offshore are designed to receive well fluid from different oil fields and transport through pipelines for further processing. The functional requirements for any typical wellhead tower do not vary much; leading to similar design features in most of the Offshore facilities. This paper discusses the best practices applied in standardization of Offshore wellhead tower’s design and highlights its advantages in execution of EPC projects.

In the standardized design, the sizing of equipment and piping for a wellhead tower are normally pre-defined and fixed for all new projects. The pre-defined design specifications are finalized based on best engineering practices and field experiences. For example; the well flow line size of about 6" is found sufficient for typical oil production platforms as well as meets conventional line sizing criteria for most of the projects. Similarly, the material of construction for all piping and equipment can also be pre-selected as part of the standardized design for all new wellhead towers.

The execution of an EPC project from detailed design stage to commissioning, within a given schedule is essential for success of any project. In conventional design approach, various design activities for a wellhead tower such as engineering calculations, design verification and specialized engineering studies are repeated for each project even though the design is already pre-fixed. This is a time-consuming approach and takes significant amount of time without any value addition. This also delays the procurement activities leading to cascading effect on fabrication, installation and commissioning of the facilities. In the standardized approach, design details such as equipment/line sizes, layout is already finalized and EPC contractor is mainly required to update engineering deliverables based on the vendor design information/details. This approach significantly reduces the project schedule. The standardized approach provides an opportunity for fast-track execution of the projects. In addition, it leads to better management of material resulting in reduced maintenance and shutdown period during operational phase. The standardized design also provides flexibility to the operator for easy maintenance and operation of the similar facilities at other locations.

NPCC has recently successfully executed many wellhead tower projects involving standardized design approach. Based on the experience gained and the lessons learnt through these projects, NPCC proposes the best engineering practices that can be adopted for the execution of standardized offshore wellhead towers design providing benefits to all stakeholders.
Trend for Offshore Pipeline Installation Methodologies as a Result of Evolution in the Oil & Gas industry
Authors: Dai Xuexin , Goh Kia Hock , Ng Eng-Bin
Published: November 2019

The objective of the paper is to present the manner in which the Oil & Gas Industry has evolved and how this evolution has impacted the trend in pipeline installation methodologies.

The content for the paper is based on authors’ personal experience within the various installation contractors that he had worked for and observation in the industry spanning 4 decades, as well as research on the evolution of the design of production facilities and how this evolution has impacted the various installation methodologies. The research pertains to both on-line research as well as discussions with various experts working for the various installation contractors, including authors’ employer.

The findings from the study show that changes in design codes have been made to cope with increasing demands for deep-water facilities. The changes in design code has allowed for pipelines to be installed deeper, in particular for conventional S-Lay methods, as well as pave the way for other installation methodologies, such as Reel-Lay. Other novel methods have also been invented, such as the Controlled Depth Tow Method, although this method had evolved not as a result of the changes in code but innovative ideas that allow for deep-water installation with little impact on pipeline stresses.

The findings from the study shows that pipelines are being installed in deeper waters as a result of improvement in design such as shorter stinger radius, which allows for pipeline to leave the lay vessel almost vertically, increased lay tension capacities, advanced welding and NDT techniques and so on. Changes in design codes have contributed to the accomplishment of deep-water pipe-laying.

In addition, the trends for pipeline installation are discussed, as well as gaps and opportunities for future development.
Benchmark Primary Drainage Saturation Height Function: Theory, Methodology, Applications and a Carbonate Case Study in the Sultanate of Oman
Authors: Hadidi Shahab , Boya Ferrero Maria , Van Den Nouland Casper , Nicholls Christopher
Published: November 2019

The benchmark primary drainage Saturation Height Function (SHF) is a standardized dimensionless function that describes the expected saturation-depth profile for a specific rock type resulting from primary drainage. The paper's ambitious goal is to introduce the concept of creating an inventory of benchmark functions for every reservoir rock type. The benchmark function is the reference point to validate the fluid fill history and identify areas of primary drainage for a specific field. Furthermore, it can be used as a diagnostic tool to analyse changes in the reservoir rock type and pinpoint fluid fill variations. The benchmark function is a complementary model to constrain the SHF when there are insufficient data, especially in the transition zone. A key diagnostic criterion for a reservoir rock type is that it contains a consistent combination of pore types and hence has consistent (or predictable) capillary properties. Case studies on carbonate fields are presented from the Sultanate of Oman. The same concept is also applicable to clastic reservoirs.

The benchmark primary drainage function can be derived from the capillary pressure data. Conversion of this data into a normalized capillary pressure system is required. In this paper, we will introduce a workflow to utilize the saturation log data from different fields to build a benchmark function that is not influenced by reservoir fluids densities' and interfacial tension.

Benchmark primary drainage functions were created in different scenarios and rock types to aid saturation modelling in several fields. In one carbonate field, the saturation log data from an analogue field were used to constrain the transition zone due to data limitations. The benchmark function was also used to identify fluid fill variations and unlock a potential development.

The benchmark function of micro-porous rock, derived from several analogue fields, was the baseline for the saturation modelling workflow of a complex carbonate reservoir with a tilted contact and significant imbibition and it was a vital enabler in simplifying the saturation model.
Unmanned Facilities: The Way to $30bn Savings
Authors: Nevin Michael
Published: November 2019

In the Arabian gulf alone, there are an estimated 500+ wellhead towers, of varying designs, varying complexity, varying cost, currently installed.. Expand that to a global view and the number is estimated to be greater than 7000.

Consider the magnitude of life cycle cost savings and HSE performance improvements that would have been made if all those towers could have been designed differently, with significantly less topsides equipment and hence CAPEX, reduced maintenance requirements resulting in much lower OPEX, offshore visitation reduced to once per year, helicopter transportation eliminated – and yet the same basic function maintained. More importantly, as our industry faces up to the challenge of increasingly marginal field developments in an increasingly cost competitive environment, consider the potential to unlock previously non-economic projects through a new approach to this key element.

In this paper we demonstrate what the wellhead tower of today could look like, based on a case study of a recent project undertaken for a major operator. We discuss the technologies required and the approach to operations and maintenance to significantly reduce the life cycle cost, reduce offshore visitation and improve the HSE performance of future wellhead towers.

Finally, with an eye to the ever-evolving future, we project how a similar approach may be adopted not only for wellhead towers, but for more functionally complex processing facilities.
Optimizing Oil Rim Development in a Tight, Fractured Carbonate Field: Khuff Formation, Yibal Field, Sultanate of Oman
Authors: Knoerich Andrea , Dhahli Adnan , Lai Sonia , Habsi Sumaiya , Farsi Shadia
Published: November 2019

The Khuff formation in the Yibal field is currently undergoing one of the largest field development campaigns in PDO. While the main project driver is securing gas production (highly sour) at a stable plateau rate, maximizing oil rim recovery and production is the main objective of the presented study. This is challenging as all wells are pre-drilled as per FDP recommendation and any later development optimization is expected to be difficult and costly.

Newly available static (seismic, well log, borehole images) and dynamic (well test) data were utilized in a decision driven modelling approach to update existing static and dynamic models to confirm the robustness of subsurface development decisions, oil production promises and EUR. Updated structural and property modeling results were utilized to optimize placement of 2/3 of the remaining wells in order to improve drainage. Reservoir rock typing and fracture interpretation, along with cased-hole surveillance data acquired in all wells, were used to optimize production intervals and to confirm the productivity of the different intervals (dolostone/ limestone/ fractures); which were then integrated to confirm the perforation strategy going forward.

This study describes the first development of Khuff carbonates in Sultanate of Oman, with limited historical production data and no analogues in Sultanate of Oman. The study highlights the importance of continuous integration of new data in a decision driven modelling approach to ensure robustness of project decisions with timely project adjustments to prevent NPV erosion.
Enhancing Productivity Using Blended Acquisition with Temporally Signatured/Modulated and Spatially Dispersed Source Array
Authors: Ishiyama Tomohide , Ali Mohammed , Blacquiere Gerrit , Nakayama Shotaro
Published: November 2019

Recently, we established a blended-acquisition method: temporally signatured and/or modulated and spatially dispersed source array, namely S-/M-DSA, that jointly uses various signaturing and/or modulation in the time dimension and dispersed source array in the space dimension. Our S-/M-DSA method makes the blended-acquisition encoding and operations significantly simple and robust, as well as for the deblending processing. In this paper, we discuss how this method enhances the acquisition productivity, in addition to the deblending performance, both in the time and space dimension. This shows that S-/M-DSA enhances the acquisition productivity by decreasing the sweep length by a factor of the number of frequency bands in the time dimension, and decreasing the number of simultaneous shots using non-uniform, even-but-random and multi-scale sampling in the space dimension. This also reveals that S-DSA attains a best acquisition productivity whereas M-DSA attains a best deblending performance compared to conventional blending methods.