bluuebunny/crossref_metadata_2025 huggingface dataset:
A Novel Technique for Removing Wax Deposition in the Production System Using Thermochemical Fluids
Authors: Hassan Amjed , Alade Olalekan , Mahmoud Mohamed , Al-Majed Abdulaziz
Published: November 2019

In the petroleum industry, deposition of hydrocarbon wax is one the critical problems. Wax can deposit and accumulate inside the well completion, surface facilities and transportation pipelines. Wax deposition can lead to significant pressure drop in the production system and may result in stopping the hydrocarbon production. Several treatments are used to remove the deposited wax and improve the hydrocarbon flow. This paper presents a new and cost-effective technique for removing the wax deposition from the production system. In this work, inexpensive and environmentally-friendly fluids have been used for wax removal. Chemicals that able to generate heat and pressure at certain condition were used.

In this study, thermochemical fluids were utilized to remove the accumulate wax in the production tubing. Actual wax from Arabian oil field was used to mimic the real condition of wax deposition. Thermochemical solutions that consist of two chemical reagents were used to remove the accumulated wax in a production tubing. The used chemical can react at certain condition and generate significant amount of heat and pressure. Temperature up to 500°F and pressure up to 2000 psi can be in-situ generated due to the thermochemical reaction. The chemical reaction can be triggered using acetic acid as an activating agent, to reduce the operational time for wax removal.

The results showed that, more than 95% of the deposited wax can be removed using thermochemical solutions. The in-situ generated heat is able to liquefy the precipitated wax, then, the induced pressure due to the chemical reaction can flush the wax out of the production tubing. The used chemicals did not result in any damage in the pipeline, no corrosion or precipitation was observed in the production tubing. Also, the generated pressure due to thermochemical treatment did not reduce the pipe integrity, no pipe enlargement or damage was induced in the treated samples.

This study presents a novel and high-performance treatment for wax removal using thermochemical fluids. The used chemicals can remove the wax from production tubing, surface facilities, and transportation pipelines; without affecting the integrity of the production system. The thermochemical fluids can be used at harsh situation of high temperature and high salinity condition. The obtained results show that there is a good potential for field application of this work in the next few months.
EPC Contractor's Strategies for Timely Completion of Offshore Brownfield Projects
Authors: Onojeta Kennedy Mudiaga , Karuppusamy Kandasamy K. , Agrawal Rajender Kumar , Kamal Faris Ragheb , Takieddine Ousama Halim
Published: November 2019

The O&G industry is continuously seeking cost reduction strategies that result in competitive advantage among their competitors especially during periods of fluctuating oil price. This has led to the engagement in Brownfield projects as a cost saving measure which arguably involves less capital to execute when compared to Greenfield projects with high cost of execution. Hence, Operators and EPC Contractors tend to focus on cost efficient and sustainable approaches that will maintain the profit margin and gain competitive advantage. This strategy places the companies in a better shape such that after the price fluctuation periods, they will be more prepared to face new challenges in developing new fields that will improve their bottom lines and be leaner in their operations.

The focus of this paper is on the strategies applied in executing Brownfield works for many offshore platforms in Arabian Gulf by National Petroleum Construction Company (NPCC). The case study demonstrates the installation of over 3500 tonnes of deck extensions onto existing platforms using a simplified design approach, standardized seafastening arrangements that requires less offshore work, minimal interface and operations shutdown of live equipment.
Collaborative Workspace for Employee Engagement Leveraging Social Media Architecture
Authors: Chowdhury Khairul , Lamacchia Diego
Published: November 2019

Employee Engagement had long been a challenge for any organization in the world. The problem has been even worsened due to the enhanced endeavor on digital transformation, where most of the employees are left behind. In addition to that, the new (and young) generations who are heavily social media-oriented face substantial challenges to engage themselves into the workplaces, which are either very much traditional or much advanced to adopt and require substantial skills.

The objective of this paper is to present a digital collaborative framework, intelligent digital Eco-System (iDES) for bringing multiple organizations and employees along with their work and communication into one single platform that engages all generations of employees. The framework is built addressing the architecture of a new of way of project management, the "Open Project Management" (OPM). Such framework will allow workers to engage in the organization by bringing personal lifestyle of using social network, which should trigger a cultural step change in the workplace.

A digital collaborative work-space mimics popular social media platform. In the workspace the employees in the network are connected thru projects, and allows making of attractive dynamic reports by incorporating drawing visuals, complex analytics, cloud applications, videos and visualize their existing documents or presentations or spreadsheets to create their work-image. A project management capability, that allows synergism of traditional and agile approach, is introduced to have a truly team driven project management process for valued tasks, including an effective communication tool with a scheduler, video conferencing, and file sharing. eLearning modules facilitating easy training and knowledge share are also introduced for technology adoptions. Overall, the workspace is designed to have most of the work process within the system, allowing employees to display their work out of their siloed room structure to an open digital space.

Such architecture of collaborative work space allows a creation of self-image, like social media, into the workplace, enhancing employee motivation towards work, increases multi generation employee participation in digital transformation and providing a transitional phase to any employee through the cultural step change required to implement digital transformation objectives.

The comprehensive capability of performing tasks and engagement into one single place will create substantial amount of data related to human resources which can be utilized for further enhancement of employee engagement and empowerment. The novelty of the digital workspace lies in empowering people in many details and helps driving business by making them a fundamental building block in the digital transformation endeavor.
Planning, Design and Optimization of CT Intervention for the First Successful Multistage Fracturing Completion with Sand Control System in the Region
Authors: Rodoplu Rasim Serdar , Al-Mohanna Khalid S.
Published: November 2019

For the first time in the region, a multistage fracturing completion technology that enables simultaneous fracturing and controlled sand production was successfully installed. After the fracturing operation was conducted through frac ports in multiple zones, coiled tubing (CT) intervention was needed to shift the frac ports closed and then open the production sleeves located within the sand screens. It was necessary to use the appropriate shifting tools and utilize the downhole parameters to ensure the shifting operation success.

CT was first utilized to mill the frac balls and associated seats after the fracturing operation, and this was followed by CT intervention to close the frac ports and open the sand control production sleeve. CT providing real-time downhole parameters was utilized during the shifting operation as its downhole weight provided the ability to apply required surface forces to shift the respective well accessories. Additional benefits were gained by utilizing the depth correction and obtaining the required differential pressure across the shifting tool in real-time ensuring tool functionality at optimum parameters.

The success of the innovative multistage completion operability depended on the successful implementation of shifting operations to close the frac ports and open the production sleeves with sand screens. Therefore, it was very important to select and deploy the appropriate shifting tools that can be trusted to actuate each of the respective well accessories. A series of yard tests were conducted to understand the hydraulically operated shifting tools. After the successful yard tests, during the design phase, each of the shifting operation steps were elaborated with the respective contingencies, and it was confirmed that the CT equipment utilized for the job can provide the required surface and downhole weights.

The hydraulically activated shifting tools operation during the actual CT intervention was optimized using the CT by providing real-time downhole measurements of depth correction, tension, compression and pressures. The downhole measurements helped in repeating the shifting step as needed and helped in confirming that the respective well accessory is shifted. During the intervention, two frac ports were shifted close. Whereas, there were two production sleeves with screens shifted open.

The use of the two different hydraulically activated shifting tools during the shifting operations for the first successful multistage fracturing with sand control completion system will be detailed. The paper also describes the full benefits of monitoring downhole parameters during shifting operations enabling the tools to operate at optimum conditions and ensuring the shifting is conducted successfully.
Use of Advanced Drilling Engineering to Define the Correlation Between ROP, MSE and Formation Properties in the Crest of a Giant Offshore Field in Abu Dhabi
Authors: Iftikhar Choudhry Bilal , Cantarelli Elena , Abdulrahman Alzaabi Mohamed , Toki Takahiro , Al – Ali Salim , Khaled AbdelKarim Islam , R. Oviedo Vargas Mario , Ahmed Osman Mohamed , Torres Javier , Kadoura Olla , Alfonso Mendez Freddy , AlQahtani Bader
Published: November 2019

The paper explores the contributing factors impacting/constituting enhancement of the drilling in the 6' section in one of the giant offshore fields of ADNOC. While there is a tangible and obvious contribution from the surface manipulation of parameters, there is also an irrefutable connect between down hole factors and ROP. Factors such as formation density, porosity, Mechanical Specific Energy, Orientation, mud weight, DDI crestal or flank placement of the well and their impact on performance. The crestal wells have come with their own inherent downhole problems and challenges. While at times there is linearity between the formation Mechanical Specific Energy and formation Density, there isn't necessarily a linear relationship between the drilling parameters and the resultant ROP. The density and porosity of the formation not only impact the MSE but the ROP downhole as well. The required parameters to drill each formation also vary with these properties and their effectiveness can in turn be tracked with the MSE being seen as a direct result of the BHA and formation interaction. The analyses entailed cover the formation density, discrimination plots, Azimuth, mud weight, BHA stabilizations, MSE and the respective intra parameter interactions that form the overall resultant drilling performance.
Challenges and Opportunities to Reduce Flaring at Upstream Oil and Gas Facilities - Highlights of Petroleum Development Oman's Strategy as an International Best Practice
Authors: Agrawal Harshit
Published: November 2019

Flaring at oil and gas facilities leads to significant loss of gas resources, impact environmental air quality, as well as affect the organization's reputation. Global benchmarks indicate that around 145 billion cubic meters of gas was flared globally in 2018. This amount of gas is enough to power whole of the African continent. At an organization level, flaring can contribute to loss of more than 2% of a company's overall hydrocarbon production. This is partly due to a misconception that the value associated with continued oil production is often much greater than avoiding flaring the associated gas. As organizations develop strategies to reduce flaring, it is important to consider different aspects for establishing a holistic framework to achieve long-term value for the organization. This paper provides an overview and summary of these aspects which have been deployed at Petroleum Development Oman such as identification and delivery of new technology solutions, management of upsets leading to non-routine flaring and deployment of an innovative Heart's and Mind's program called Let's Talk Flaring.

Similarly, it is important to understand and address the challenges and opportunities, which typically arise while implementing flaring reduction at upstream oil and gas facilities. These challenges include, unclear ownership of associated gas, lack of off-takers in local energy system, equipment troubleshooting capabilities at local or regional scale etc. This paper describes how some of these challenges offer new opportunities towards effective utilization of associated gas.
The Effect of Pore Geometry on Relative Permeability in Mixed-Wet Carbonate Reservoirs in Abu Dhabi
Authors: Dernaika Moustafa , Masalmeh Shehadeh
Published: November 2019

Carbonate rocks are complex in their structures and pore geometries and often exhibit a challenge in their classification and behavior. Many rock properties remain unexplained and uncertain because of improper characterization and lack of data QC. The main objective of this paper is to study flow behavior of relative permeability with different rock types in complex carbonate reservoirs.

Representative core samples were selected from two major hydrocarbon reservoirs in Abu Dhabi. Rock types were identified based on textural facies, PoroPerm characteristics and capillary pressure. Porosity ranged from 15% to 25%, while permeability varied from 1 mD to 50 mD. Primary drainage and imbibition water-oil relative permeability (Kr) curves were measured by the steady-state technique using live fluids at full reservoir conditions with in-situ saturation monitoring. High-rate bump floods were designed at the end of the flooding cycles to counter capillary end effects. Aging period of 4 weeks was incorporated at the end of the drainage cycle. Robust data QC was performed on the samples, and final validation of the relative permeability was conducted by numerical simulation of the raw data and measured capillary pressure.

The followed QC procedure was crucial to eliminate artefact in the relative permeability curves for proper data evaluation. The different rock types showed consistent variations in the relative permeability hysteresis and end points. Imbibition relative permeability curves showed large variations within the different rock types, where Corey exponent to oil ‘no’ increased with permeability from 3 to 5, whereas the Corey exponent to water ‘nw’ decreased with permeability and ranged from 3 to 1.5. The variations in the relative permeability curves are argued to be the result of different rock structures and pore geometries. Variations were also seen in the end-point data and showed consistent behavior with the rock types.

The different carbonate rock types were identified based on geological and petrophysical properties. Higher permeability samples were grain-dominated and more heterogeneous in comparison to the lower permeability samples, which were mud-dominated rock types. Imbibition Kr curves showed larger variations than the primary drainage data, which cannot be interpreted based on wettability considerations only. The relative permeability curves have been thoroughly evaluated and QC'd based on raw data of pressure and saturation by use of numerical simulation. Such RRT-based Kr data are not abundant in the literature, and hence should serve as an important piece of information in mixed-wet carbonate reservoirs.
Q-Compensation from Near Surface to Reservoir and Below: Case Study from Onshore Abu Dhabi
Authors: Smith Cara , Vasilyev Pavel , Glushchenko Anna , Zarubov Dmitriy
Published: November 2019

Interest in quantitative interpretation (QI) of seismic data in the Abu Dhabi region continues to steadily increase, and the objective of creating inversion-ready seismic data is driving evolution of the surface seismic data processing workflows to focus on more detailed and thorough handling of the amplitude and phase throughout processing (pre-, during, and post-imaging). To achieve close well ties across the survey and to ensure the data is suitable for interpretation purposes, zero-phasing and wavelet stability (along with using well information during earth model building) are key stages in the depth imaging seismic processing workflow. Accurate amplitude with offset and azimuth handling is also required for inversion studies. In this paper, we propose a workflow where a geophysically and geologically credible, 3D variable Q-field is built into the earth model early in the processing flow, allowing a more complete approach to handling the Q-effects of the subsurface without increasing project turnaround time. This case study shows that a data-driven spatially variable Q-field combined with Kirchhoff Pre-Stack Depth migration compensates effectively for both amplitude and phase effects, providing a broadband image with improved event continuity and better handling of noise compared with applying a constant pre-migration Q-compensation (which was previously thought to be suitable for this low-relief region). By calibrating the variable Q-field to available well logs and near surface information, and ensuring that the different geophysical parameters in the earth model are all suitably coupled, an enhanced image is achieved which then requires minimal spectral shaping or residual phase corrections post migration. Ray-based Q-tomography workflows allow iterative 3D updates alongside coupled subsurface properties like anisotropy and velocity, within a high-resolution Earth model suitable for depth imaging. Reliable phase stability, higher resolution, broader useable bandwidth and improved amplitude preservation are key targets of this holistic approach.
Predicting Valve Failures in the Digital Age of Valve Management
Authors: Jeeves Simon Clausen , Berstad Carina , Gjøvåg Markus Bratten , Riple Mathias , Bjorøy Marita , Sangolt John-Kenneth , Erstad Thomas
Published: November 2019

Valves are critical and essential parts in an oil & gas (O&G) production plant, which means that if a failure occurs it can potentially great implications on safety and profitability of the plant.

The traditional approach in today's oil and gas process industry for verifying valve reliability is simplistic and provides little information regarding valve degradation mechanisms.

Therefore, this paper discusses new theories and concepts to help increase the reliability of production & safety critical valves.

Focus has historically been targeting on using corrective and scheduled maintenance strategies, rather than using condition and performance monitoring applications as a tool to plan and prioritize maintenance and achieve a higher standard for safety.

In the search for a solution to increase the reliability of production and safety critical valves it is reasonable also to look at industry 4.0 and its concepts. The digital revolution which implements concepts such as cyber-physical systems (CPS), industrial internet of things (IIoT) and cloud-based storage. Based on these concepts the paper visits the use of valve diagnostic systems for identifying failure mechanisms of valves subjected to degradation by the application of sensors and small computers used to continuously monitor valve performance and store this data within cloud-based servers.

Today we experience an enormous progress in real time monitoring by use of sensors in conjunction with data collectors. There is new technology to process and gather data that supports decision making, such as Valve Diagnostic System (VDS). By taking advantage of new technology there are immense benefits to be had by monitoring valves rather than traditional physical observation and testing. This method has multiple advantages and it can contribute to reducing maintenance cost, down time and increase safety.

Multiple unwanted and hazardous events have occurred through the last decades, such as the tragic Piper Alpha disaster (Macleod & Richardson, 2018). This has contributed to drive the industry to improve and adhere to safety regulations and requirements. This makes the sensor technology even more beneficial and opens a wide range of potentials within the maintenance- and risk management genres.

Today all in-operation risk calculations are based on reported accidents or unwanted occurrences. This practice gives way to inaccurate reliability calculations that are indisputable and inaccurate. It is a practice where potentially many failures are not reported, understood or even revealed. Experts within Functional Safety Management points to the basis of the calculations with skepticism due to the validity of the data and the fact that the data in itself is not a proactive approach to sound valve management.
Innovative Seismic Depth Imaging Workflow for Better Reservoir Understanding: TZ Offshore Abu Dhabi Case Study
Authors: Al Messabi Saif Ali , Mahgoub Mohamed , Damianus Fritz , Hasan Babar , Khakimov Oleg , Tertrais Bertrand
Published: November 2019

High fidelity seismic amplitude reconstruction through pre-stack migration is crucial for accurate elastic inversion. Despite a relatively flat geology of the Abu Dhabi region, accurate imaging is required for a stable elastic inversion. This can be challenging because the main reservoir Arab lies underneath the strongly anisotropic overburden of the Nahr Umr formation. In this case study, we show how we effectively addressed this challenge through PSDM.

With PSDM imaging, we have overcome the challenges of complex ray paths passing through the strongly anisotropic Nahr Umr layer and the rapid lateral velocity variation in the Mishrif formation. Evidently, the success of PSDM relies strongly on the accuracy of the depth velocity model used. To achieve this we adopt different forms of tomographic inversion, for example, using 3D non-linear slope tomographic inversion, where velocity and anisotropy (Epsilon) models are jointly inverted. Additionally, short wavelength velocity variations caused by the Mishrif interval are resolved through structurally-constrained tomography (SCT).

The superiority of PSDM imaging over PSTM in reconstructing AVA compliant seismic amplitudes is demonstrated on an ocean bottom survey from the transition zone offshore Abu Dhabi. Fast-track AVA elastic inversion is used to assess the benefit of PSDM imaging over PSTM. With a more stable Vp/Vs ratio and smaller inversion residual, PSDM imaging demonstrates a greater accuracy in reconstructing the pre-stack seismic amplitude and thus are more appropriate for estimating elastic reservoir properties.

The value of PSDM imaging for better understanding of reservoir characteristic has been well demonstrated in this case study from the Abu Dhabi transition zone, thus optimizing the value of the acquired seismic data for asset development.
Surface Controlled Subsurface Safety Valve Refurbishment, In-house
Authors: Al-Ghaferi Mohamed Mubarak , Al Jaberi Fawzi Omar , Albadi Mohamed Mubarak , Yugay Andrey , Agarwal Anubhav , Pangestu Yohannes Fisher
Published: November 2019

Downhole Safety Valve is an integral part of Well Integrity Mangement System and acts as a failsafe equipment to prevent uncontrolled release of reservoir fluids. Periodic inspection and maintenance of downhole Safety Valve is essential under normal service conditions. Each Downhole Safety Valve should be tested and lubricated at specified regular intervals as recommended by ADNOCs Standard Operating Procedure and as dictated by field experience. Since it is a Critical Safety Equipment, preventive maintenance of Wireline Retrievable type downhole Safety Valve is being carried out annually which involves valve retrieval, leak/function test and redressing if required.

Current practice within ADNOC Onshore is to carry out redressing with third party for all Wireline Retrievable Safety Valve annually or in case they are observed to be passing (not meeting the maximum acceptable gas leak rate of 15 scf/min for gas and 400 cc/min for liquid) or do not pass function test carried out during 6 monthly and yearly Preventive Maintenance Schedule.

The cost incurred for third party redressing is substantial and can be optimized by evaluating the possibility of carrying out redressing in-house with available resources and using Original Equipment Manufacturer redress kit in situations where internal leak is not observed in the valve and valve can be redressed without the need to open tension spring and flow tube which requires extensive redressing setup available with third party.

The new proposal helped in saving cost and time for redressing by utilizing the available resources and formalising in-house redressing wherever applicable under compliance to ADNOC Onshore competent authority guidelines.
Reverse Time-Lapse Technique for Moveable Gas Identification
Authors: Lukmanov Rinat , Kindi Amani
Published: November 2019

The Barik, Miqrat and Amin formations are deep, tight reservoirs of the Haima Supergroup that provide the majority of gas production in the Sultanate of Oman. The Miqrat formation is a feldspathic sand/shale sequence with complex pore structure and occasional bitumen presence. In the area of interest, it occurs at a depth of approximately 5000 m. Average porosity varies from 5 to 9%, average permeability for Lower Miqrat does not exceed 0.1 mD. In general, Archie equation derived saturation in low porosity rocks is subject to medium to high uncertainty. Therefore the most common challenge in the petrophysical evaluation of tight reservoirs is the determination of gas saturation and fluid type identification.

In an effort to improve the reliability of saturation calculation and fluid typing, several different methods were tested including cased-hole Pulsed Neutron Logs (PNL). The classical sigma interpretation was found to be too sensitive to input parameters and did not provide significant improvement to saturation determination in the complex Haima lithologies. An important breakthrough was made when the dynamics of the mud filtrate invasion process in these reservoirs was understood. During open-hole logging usually very little or no gas effect is observed on logs with negligible or no density-neutron separation. The reason is considered to be deep mud filtrate invasion pushing moveable gas beyond the depth of investigation of radioactive logs. One or two months later, the filtrate in the invasion zone dissipates with gas returning to the near wellbore formation.

The best match between log calculated moveable gas saturation and production test data was obtained using a reverse time-lapse technique, with PNL cased-hole logs compared to baseline open-hole neutron measurements. The changes in neutron porosity with time can be attributed to moveable gas saturation. Careful neutron log quality control and normalization across non-reservoir and known water-bearing sections is required. Knowing the hydrogen index of gas, we can calculate the moveable gas saturation from the difference in neutron log response. In contrast to the sigma approach, an accurate rock matrix model is not required.

This paper describes the Reverse Time-Lapse technique: a novel application of the classic time-lapse technique between open-hole neutron and cased-hole PNL. The case studies demonstrate that this technique is applicable for completion decision making and field-scale development planning.
HT Carbonate Formation Acidizing Using Chelating Acid and Temperature-Control Design Method
Authors: Wang Da , Feng Fuyong , Wang Gui , Lu Yan , Zhou Fujian , Yang Guowei , Gao Jichao
Published: November 2019

The 185°C formation temperature of BZ-22 Offshore Oilfield in China poses a great challenge to the treatment fluid selection and acidizing design just because of the high corrosion rate and the inefficient wormholing using conventional acid systems.

A deep penetration chelating acid is presented in this paper. In comparison with conventional acid, it has a much lower Cl-content, which is the main source of tubing pitting corrosion under high temperatures. In addition, it has a much lower corrosion rate to production tubing and a much lower reaction rate with formation rocks by forming a thin film over the rock and tubing surfaces. Very important, different from original chelating acid acidizing operations, a temperature dependent acidizing design has been proposed, in which the volumes of different types of acid, not only chelating acid, are calculated based on the temperature field software simulation. So that the traditional HCl slug can also be used in this high temperature formation after the formation is cooled down to the designed temperature to ensure efficient wormholing.

The operation has been carried out in 2018 for a pilot gas well. Before operation, the gas production rate was only 500m3/d with nearly 0 wellhead pressure, but after operation the production rate was as high as 55,000m3/d with 1,100psi wellhead pressure. The high production increase ratio shows that wormhole rather than face dissolution has been achieved and the near wellbore damage has been successfully removed. Besides, the downhole temperature monitoring data showed that the measured temperatures for different types of acid stages were in accord with the software simulation results.

Although this low Cl-content chelating acid and the temperature-control design method have been developed and used in China offshore oilfiled, it can be applied in other carbonate formations with high temperatures.
Fluid Property Prediction with Unified Equation of State in a Compositional Surface Network Comprising 5000+ Wells
Authors: Mogensen Kristian , Asarpota Jyotsna , Bansal Yogesh
Published: November 2019

ADNOC has embarked on the second phase of its ambitious integrated capacity model (ICM) project with the overall aim to optimise its fluid production portfolio from the well level to the processing facilities. A key feature of the new software tool is the ability to track and predict fluid properties over time across the entire production network, comprising thousands of wells and a myriad of pipelines.

The reservoir fluid composition is assigned at well level for each producing reservoir. The compositional tracking over time is straightforward for many wells, but complicating factors do arise, such as

Lateral compositional variation related to complex reservoir charging history Vertical compositional gradients, especially for near-critical fluids The presence of initial and secondary gas caps, resulting in gas coning Injection of miscible gas for enhanced oil recovery

The fluid systems range from medium-API oil to gas condensates and the key chemical components vary as follows: C1 [5-80%], CO2 [0.5-8%], and H2S [0-35%].

Mixing of pressurized fluids with different compositions at various junctions in the network requires a robust thermodynamics model to capture the associated variation in fluid properties, particularly density and viscosity as a function of pressure and temperature. We demonstrate that it is possible to constrain one unified equation of state applicable to all fluids, as long as the fluid systems used for the tuning span the entire range of compositions observed. Mixing of fluid streams is computationally much simpler if each stream is made up of the same components (although in different amounts) with the same component properties. On average, the predicted fluid density is within 1% of the measured value from a multi-stage separator test.
A Field Applications of Effective Stimulation High Pressure/Temperature Multi-Stage Completion which Shows Significant Well Performance Improvement in Deep North Kuwait Jurassic Unconventional Reservoir
Authors: Al-Saeed Abdullah , Al-Dhafiri Anood , Fidan Erkan , Al-Mutawa Majdi , Abdul Hadi Ahmad
Published: November 2019

Selecting the completion design and stimulation technique in North Kuwait Jurassic Gas (NKJG) were critical to overcome reservoir challenges by stimulating these unconventional formations efficiently and effectively. Therefore, the completion design must be high-pressure rated upto 15,000 psi, high temperature of 275°F and sour service specified because of high H2S & CO2 content. These reservoirs are heterogeneous carbonate type with various productivity index due to existence of natural fracture which needs proper completion type that treat each reservoir layer separately. The most challenging factor in these unconventional reservoirs is the high permeability contrast among the different flow units because of the dual porosity effect which needs convenient diversion mechanism during the stimulation. The reservoir was segmented into different intervals to enhance the productivity index of each flow unit.

For that reason, "High Rate Matrix Acidizing (HRMA)" method was obtained with retardard acid to restore the well productivity due to the drilling fluids which alter the effective permeability near the wellbore. By dividing each flow unit into separate stages across packer system and stimulate them subsequently is the aim to overcome high permeability contrast across the reservoir flow units.

The Monobore Multi-stage was chosen as a completion type to produce from different zone of interest. These Reservoirs are divided into different stages and acid treated with various stimulation techniques (Acid fracturing & High Rate Matrix Acidizing). The success of the stimulation treatment in monobore Multi-stage completion depends on several factors such as: selecting proper fluid recipes, rock/fluid properties, job design, and field implementation. That type of completion is activated as a drop-ball system to stimulate each flow zone individually but in single well intervention setup.

This paper presents a 15K open-hole HPHT MSC field success case application that describes the best practices, learning, planning, design, installation and stimulation in NKJG unconventional reservoirs to enhance well performance and overcome reservoir challenges. An improvement in understanding of production performance from several reservoir sections is the key enabler selective stimulation and effective testing. After stimulating all the stages milling of the ball seats of completion was obtained in order to pinpoint well production profile. The post stimulation flow tests results and production logs provided a good evidence for applying this technology these unconventional reservoirs.
Automated Sector Performance Review - A Collaborative Process to Identify, Interpret and Implement Profitable Opportunities
Authors: Khan Muhammad Navaid , Al Bishr Manal , Mohan Richard , Al Marzouqi Mohamed , Saputelli Luigi
Published: November 2019

The complexity of the recovery mechanism generally increases with the maturation of a producing field; therefore, the granularity of the reservoir analysis must increase proportionally to better understand the well and reservoir dynamics. ADNOC's Integrated Reservoir Management (IRM) Framework has instituted a set of workflows to focus on analyzing the reservoir performance at the sector level to assure reservoir performance sustainability. ADNOC has developed and implemented a robust automated Sector Performance Review (SPR) process using state-of-the-art analytics and business process management tool. The main objective of this work is to foster collaboration among multiple disciplines to assess the reservoir performance, as well as, to identify, interpret and implement profitable opportunities through a centralized platform (Al Marzouqi et al, 2017).

A unique process has been implemented in the five major assets of the ADNOC group, which covers approximately 50% of UAE overall production. The system leverages an automated integration of subsurface data from numerous sources; live analytics visualization provides reservoir performance insights on the sector level through automatically calculated KPIs and diagnostic trends. (Al Marzouqi et al, 2018). The integrated interface helps the multidisciplinary teams to identify the value-driven opportunities; the ranking and the feasibility analysis of these opportunities are governed by a closed-loop maturation process that involves the formal approval processes in order to obtain approval or authorization for action.

The solution offers an innovative way to establish collaboration among different assets to assimilate reservoir performance insights through a sustainable platform. Some of the immediate benefits include the effective execution of a reservoir management scheme, monitoring the variance between actual and anticipated performances during the course of projects, and assuring production target compliance whilst mitigating the shortfalls proactively. In fact, a reservoir level analysis tool (RPR) was piloted during 2017 and presented in SPE-193012-MS. However, with the necessity of having analysis at the sector level, the overall design of the solution is transformed to allow the users to carry out the analysis at sector and well level granularity. The SPR (Sector Performance Review) is enabling the achievement of a consistent approach across all assets for all subsurface performance review processes while improving efficiency through automation of data gathering and presentation and the identification of all underperforming reservoir, sectors, and wells.
Normally Unattended Installations, the New Frontier for Cost Reduction
Authors: Munoz Jean-Michel , Bartoli Eric , Johnson Edward Aubrey , Rivière Luc , Meyer Eric
Published: November 2019

Progress in the digital area has been quite significant in the past few years in terms of data monitoring, remote collaborative work, telecommunications and robotics to the point that disruptive ways to operate and to design surface installations can now be envisioned with HSE benefits and substantial cost reductions without compromising production efficiency.

Normally Unattended Installations with presence of people on site only once a year (NUI-1Y) for maintenance campaigns is the ultimate aim of unmanned concepts and a new frontier for cost reduction. This approach is particularly relevant for remote production sites where operations usually require a continuous presence of a large crew and heavy logistical means.

Although, this concept seems very challenging, it is in fact a natural extension of what has been applied with success on subsea developments starting over twenty years ago where wells, valves, separators, pumps and now compressors have been remotely operated from a host facility, together with the occasional assistance of Remote Operated Vehicles. A NUI-1Y development, in its philosophy, is very similar to a subsea architecture that would be applied to a surface installation.

A successful NUI-1Y development would also be the result of an optimization where from the initial design phase, the project would try to reduce as much as possible Site Working Hours, both planned and unplanned. This is accomplished through careful selection of new architectures, a fully electrified concept, extensive use of digitalization, low maintenance and highly reliable components or technologies. These technologies exist or are under development and include autonomous ground robots which can operate in routine or downgraded situations during the period between site visits. Along with the design, traditional operating philosophies must also be amended to address operations in a fully remote mode.

This paper will give an overview and examples on how Total is:

– Maturing new designs, focusing first on reduction of Site Working Hours as a new Key Performance Indicator, alongside other KPIs such as topside weight reduction and equipment uptime. – Challenging traditional safety concept and bases of design and philosophies which were previously biased towards design and safety of permanently manned installations. This includes developing remote or automated technical solutions that previously required human presence for specific operations. – Piloting autonomous ground robots and adapting installations so that they can be robotically operated.
Increasing Reliability of Stress Characterization through Optimum Design and Sensitivity Analysis of Fracture Injection Tests, Coupled with Enhanced Geomechanical Analysis
Authors: Perez Oswaldo , Fragachan Francisco , Omer Mohammed
Published: November 2019

Diagnostic fracture injection tests (DFIT) are conducted to estimate the magnitude of the minimum horizontal stress (tectonic) and characterize essential reservoir properties, such as reservoir permeability and actual reservoir pressure in conventional and unconventional reservoirs. When properly designed, and conducted, this type of transient test can help operators to reliably extract important reservoir data and reduce related operational costs and time. This paper provides a state of the art sensitivity analysis based on real pressure data that describes the impact of DFIT design on reservoir parameters acquisition.

In this study, the engineering steps to optimize the design, conduct the test and interpret acquired data are examined through a sensitivity analysis to obtain reliable results. Furthermore, the interpretations of the performed tests can be combined with an enhanced image log analysis (if available) to constrain the in-situ stress conditions, including the magnitude and direction for all three principal stress components.

Multiple operational parameters, such as injection rate, injection duration, rate reduction, leak-off mechanism and fall-off duration could significantly impact the fracture extent and mechanical response of the rock, thus affecting the fluid flow regime after shut-in. Therefore, all these variables should be evaluated in the proposed methodology to optimize the test, which is the key difference between conventional design and the presented reservoir driven design. To quantify the impact of operational parameters in reservoir response and validate the proposed approach, extensive sensitivities are performed with a complete well data set from a typical unconventional play by running in-house fracture models, considering multiple testing parameters (such as injection schedule, fluid type, leak-off, and net pressure analysis). Eventually, the optimal injection scenario can be determined, which could be applicable for regions with similar geological conditions.

This study demonstrates how uncertainties can be narrowed down when estimating the stress condition from fracture injection tests. The proposed approach can identify critical parameters and suggest best practices for diagnostic fracture tests under certain reservoir conditions. It can also be coupled with an enhanced image log analysis to fully determine the in-situ stresses magnitude and direction, which will increase the reliability of related geomechanical and reservoir analyses.
Research and Application of the Optical Fiber Technology for Real-time Temperature Test of Offshore Thermal Wells
Authors: Zou Jian , Han Xiaodong , Liu Yigang , Wang Qiuxia , Zhang Hua , Liu Hao , Wang Hongyu , Han Chao
Published: November 2019

Thermal recovery method with horizontal wells has been conducted in Bohai Oilfield for almost ten years. The horizontal section length of the horizontal well is about 300 m. For thermal wells, monitoring the real-time temperature data downhole is of importance for analyzing the temperature distribution and variation rules along the wellbore, and consequently improving the produced degree of the horizontal wells.

Different kinds of high-temperature monitoring technologies are summarized and the high-temperature optical fiber is selected for temperature monitoring of the offshore thermal wells. The steam injection tubing with functions of temperature monitoring is designed by using the optical fiber. In the horizontal section, the optical fiber is installed inside the steam injection tubing, goes outside of the tubing through a Y-joint, and connects to the surface along the annulus. Thus, the optical fiber could monitoring temperature of both the horizontal section and the annulus. Two target well are selected for project design and put into field application during the steam injection process. The monitoring results show that the high-temperature optical fiber works normally for about one month while the steam injection temperature is about 350°C. Besides, with the real-time temperature monitoring, the upward movement of the steam in the annulus is also observed and controlled by adjusting the Nitrogen injection parameters in the annulus.

This is the first time that the optical fiber technology is applied in offshore thermal wells, which would be important for verification of wellbore parameter calculation and analysis of the casing variation when heated during the steam injection process. The successful application of the optical fiber in offshore thermal well would provide a guidance for the subsequent offshore thermal exploitation.