bluuebunny/crossref_metadata_2025 huggingface dataset:
Successful Multistage, Hydraulically-Propped Stimulation through Gas Lift Completion Leads to Remarkable Capex Savings Offshore
Authors: Chiriac Antoanela Andreea , Saqib Latif , Sauter Jason Patrick , Albu Marius
Published: November 2019

The paper / presentation objective is to describe the achievement of the first gas lift well completed for multistage, hydraulically propped stimulation in a Romanian offshore field. The scope of the paper is to present the challenges and learnings associated with this well concept / design, engineering, modelling, equipment selection, yard testing, final design / program and offshore installation, operation, and results.

Reservoir depletion modelling indicated artificial lift would be required as early as 6 months within initial well start up. In order to effectively optimise production from the well for a longer range of well life cycle, a multi-stage stimulation sandface completion was selected and plans were made to install gas lift equipment during initial completion installation, prior to rig release. To meet the concept requirements, risks were assessed and case histories were investigated / incorporated during the planning phase to ensure reliability of performing high-pressure stimulations through gas lift (dummy) valves.

The material selection and specifications of the lower and upper completion equipment were defined considering:Artificial lift designReservoir characteristics, Casing size, High pressure stimulation, Life of well operations

Equipment suitability and compatibility considerations resulted in a few equipment selection changes, requiring yard trials to define optimum pulling / running tool string components and configurations, which were then applied offshore.

The final upper completion design consisted of gas lift mandrels (Gas lift dummies were replaced with gas lift valves following the HP stimulation), safety valve, permanent downhole pressure gauge and chemical injection mandrel. The lower completion consisted of hydraulic open hole packers, open hole anchor and open-close stimulation sleeves (all HP rated).

Collaboration within the multi-discipline and with multiple service providers was vital in developing the final, tested design and implementation in the offshore well. The current design in the well is showing great benefits in terms of production (a higher rate than expected) and cost (initial completion includes gas lift equipment already available for future potential use). The concept proof is considered to be of great success for upcoming projects and is increasing the confidence of the operator to develop and approach the upcoming wells with multistage stimulation gas lift completions.

This is the first well constructed in Romania that was hydraulically stimulated using proppant through an upper completion already having gas lift capability. A review of literature indicates this is an industry first. The success and communication of this well could provide benefit to the industry and could increase confidence when combining life-of-well requirements early in the well construction process.
Application of Advanced Seismic Processing to Old Seismic Data for Enhanced Fault Plane Imaging: A Case Study from Offshore Abu Dhabi
Authors: Paul Subhrankar , Khakimov Oleg , Barajas Carlos , Miyamoto Hiroki , Almheiri Afra , Mahgoub Mohamed
Published: November 2019

Low fold poorly sampled vintage seismic data often suffers from poor fault imaging. This can have a critical impact on reserve estimation and well planning. Acquiring high density seismic data over producing fields requires overcoming logistic challenges along with additional costs and increased acquisition time. However, advances in seismic processing technology could improve the fault resolution of vintage seismic data in a cost effective manner. This has been proven in a case study from offshore Abu Dhabi.

The presence of strong surface wave energy, resulting from the shallow water environment and near surface heterogeneity, masked events in the deeper part of the section. Poor and irregular spatial sampling caused aliasing of the surface wave. In the vintage processing, strong de-noising was applied to tackle the aliasing issue, which smeared the fault definitions. During the re-processing, a joint low-rank and sparse inversion was applied to regularize and densify the input data to obtain a de-aliased surface wave noise model. Subsequent adaptive subtraction of the noise from the input removed strong surface waves without damaging the body waves.

The stack quality was improved by application of cascaded surface wave attenuation algorithms. Additional five dimensional Fourier reconstructions of the data improved the signal quality. A carefully designed fault-preserving residual noise attenuation workflow further reduced the residual noise content. Automatic picking of key stratigraphic horizons was carried out in order to evaluate the spatial resolution of the re-processing outcome. Sharper discontinuities along fault planes observed compared to the interpretation of the vintage seismic data. Increased confidence in fault interpretation is of value for structural restoration study and further reservoir understanding. In addition, several new, previously not-visible, small fault features were highlighted as evident from volumetric curvature and semblance analysis. They have been effectively utilized in a forthcoming drilling campaign to de-risk well operation.

Multi-dimensional data densification to de-alias surface waves and five dimensional re-construction of the signal proved to be beneficial to enhance the fault features on the poorly sampled seismic data.
Sustaining Crude Quality Specifications by Leveraging IR 4.0 Solution
Authors: Ahmed Syed , Al-Zubail Ahmad , Al-Jeshi Majed , Yousef Khaled , Musabbeh Alya , Mousa Saad , Bukhari Adeeb , Seraihi Emad , Alamri Sultan H.
Published: November 2019

This paper describes integrated solution that leverages Industrial Revolution 4.0 to sustain crude quality specifications for Saudi Aramco supply chain covering more than 50 GOSPs (Gas Oil Separation Plants), Pipelines, and Terminals. Sustaining crude quality specifications such water content (BS&W), salt content, etc. for the Arabian Crudes (Arab light, Arab Extra Light etc.) requires big data analysis across the supply chain. To address this challenge, Saudi Aramco developed a customized solution called Crude Quality Monitoring Solution (CQMS) which leverages 800+ critical data streams every minute (PI values), classifies the data according to the risk level impacting crude quality specifications. Three developed risk levels are leading proactive, lagging proactive, and lagging reactive, each of which has a defined acceptable risk matrix. Each risk matrix initiates automated notifications for corrective actions proactively. Moreover, patterns and operational events can be easily recognized in the solution visually. The paper also describes several examples where the solution notifications have proactively remediated process disturbances by up to 20% at upstream and downstream facilities while ensuring asset integrity. The solution deployment has also substantially improved the operational efficiency across the network by benchmarking critical data streams. Saudi Aramco is continuing to enhance the solution capabilities to ensure maximization of the crude network.
In-situ Pore Plugging Using Nanosilica Based Fluid System for Gas Shutoff
Authors: Karadkar Prasad , Almohsin Ayman , Bataweel Mohammed , Huang Jin
Published: November 2019

A nanosilica based fluid system was evaluated for forming in-situ glass-like material inside matrix for permanent gas shutoff. This novel method involves two steps; firstly, pumping low viscosity aqueous nanosilica mixture into the formation and allowing it to gel up. Secondly, gas production dehydrates nanosilica to form glass-like material inside the matrix. For this paper, a nanosilica-based fluid system was assessed for pumping strategy and performance evaluation.

A nanosilica based fluid system consists of a mixture of colloidal silica and activators. It possesses low viscosity, which assists in deeper penetration during placement. With time and temperature, it can lead to in-situ gelation to form a rigid gel to block the pore space. Gas production can dehydrate nanosilica gel to form in-situ glass-like material inside formation porosity for permanent gas shutoff. The nanosilica based fluid system was optimized using gelation tests and core flooding tests to evaluate its performance under high-pressure, high-temperature conditions. Formation of in-situ glass-like material inside pores was analyzed using a scanning electron microscope (SEM).

The gelation time can be tailored by varying the activator type and concentration to match the field operation requirements. Kinetics of colloidal silica gelation at elevated temperatures showed faster viscosity buildup. Before gelation, the viscosity for the nanosilica based fluid system was recorded less than 5 cp at a 10 1/s shear rate, whereas the viscosity was increased more than 500 cp at a 10 1/s shear rate. Using core flow tests, N2 gas permeability of the Berea sandstone core was completely plugged after pumping the 5-pore volume nanosilica based fluid system at 200°F. During nanosilica based fluid system injection through the core, differential pressure was increased to only 10 psi showing better injectivity. The SEM images showed the presence of glass like material filling the porosity, which showed in-situ generation of glass-like material inside pores.

The nanosilica based fluid system has a low viscosity and can penetrate deeper into the formation matrix before transforming into a gel. Undesirable gas flow can dehydrate nanosilica gel to form in-situ glass-like material inside matrix for permanent sealing. This is environmentally friendly and can serve as an alternative to currently used conformance polymers for gas shutoff applications.
One Plot - Multiple Geotechnical Solutions
Authors: Perumal Kumaresan , Adel Khalid , Al Awadhi Ibrahim
Published: November 2019

Site soil conditions play a vital role in Oil & Gas projects and it has high influence on project viability and cost. Adopting appropriate strategies by evaluating & implementing ideal geotechnical schemes, the construction cost/time can be significantly optimized. This paper presents a case study of recently executed project with similar concerns and discusses the challenges encountered and fit-for-purpose solutions offered catering to various soil types, which resulted in cost optimization and early project completion.

Geotechnical investigation was carried out at site to establish soil strata/characteristics by drilling bore holes at strategic locations. Results revealed presence of varying subsoil conditions across the plot with high ground water table. At some locations, extremely loose soil was encountered at intermediate depths and at other locations soil was highly loose for top 5m depth.

Initially it was proposed to remove top soil for entire area and replace with compacted fill, however was not pursued due to huge cost. By ‘Thinking differently’, a unique approach was devised and ‘fit for purpose’ solutions offering optimum bearing capacity/settlement were provided based on anticipated loads in respective zones.

The plot was divided into distinct zones based on soil profile, type of structures, anticipated loads, allowable settlement, etc., and cost benefit analysis was performed for different geotechnical solutions. Subsoil in large storage tank areas was investigated for settlement concerns under heavy loads and liquefaction potential during seismic event. Due to weak soil, improvement using ‘vibro-replacement’ technique was finalized to preclude excessive settlement.

In areas supporting heavy structures such as tall vessels/rotary equipment/piperack, etc, special pile foundations with optimum depth were decided to limit differential settlement and safely transfer huge loads to firm strata.

State-of-the-art soil stabilization technique using geo-synthetics, which is proven to modestly increase the stiffness of weak soil was employed in areas intended to support moderately loaded facilities. Removal of loose top soil and replacement by ‘Engineering Fill’ supplemented with adequate compaction was deemed sufficient in certain areas bearing lightly loaded facilities.

By tailoring geotechnical solutions to befit diverse soil conditions, unwarranted/expensive soil improvements & large/raft foundations were eliminated. As a result, foundation footprint/quantities were optimized which resulted in substantial savings in construction cost. In addition, the project was completed ahead of schedule due to elimination of laborious activities.
Common Failure Modes in Oil Flooded Rotary Screw Sour Gas Compressors
Authors: Pallister David , Ong Pang Lin
Published: November 2019

There are many types of equipment failures encountered during the operation of oil-flooded twin screw natural gas compressors. Defining the failure modes of gas compressors mining sour gas is of primary importance for improving reliability. The failure modes for compressors operating with hydrodymanic journal bearings are different from compressors operating with rolling element bearings. Gas compressors operating in corrosive environments easily succumb to failures such as corrosion-pitting, hydrogen-assisted fatigue and chemical attack. Some common failure modes will be defined for each type of bearings used in rotary screw compressors. Identifying these failure modes assists in defining the problem so that new lubricants can be designed to extend the working life of the compressor.

The failure modes of roller bearing equipped compressors operating in sour and acid gases are primarily due to premature spall formation from hydrogen-assisted fatigue (i.e. hydrogen embrittlement) and sulfide stress corrosion. We have found that hydrodynamic journal bearings equipped compressors operating in sour gases will fail due to sulfide corrosion attack of the hydrodynamic bearings. A new additive system was developed to inhibit both types of failure modes. Laboratory corrosion tests were used to compare corrosion inhibition of new additive system to well-established compressor lubricants. When levels of corrosion inhibition were established, the experimental lubricants were field tested. Field tests of this experimental lubricant were carried out in compressors operating with both hydrodynamic bearings and rolling element bearings. The testing in this difficult natural gas field, demonstrated that CPI’s new experimental fluids have extended the operating time to failure, for compressors operating with both type of bearing systems, from about 2,000 hours to well over 10,000 hours. CPI has developed lubricant solutions that improve the reliability by extending the time to failure for oil-flooded twin screw compressors mining water-saturated natural gas streams with both acid gas and sour gas elements.
Using Depositional and Petrographical Rock-Types to Define Hydraulic Rock-Types - A Case Study from the Permian-Carboniferous Unayzah Formation, Offshore Abu Dhabi
Authors: Silva Gonzalez Patricio , Fernandes Melissa , Siddiqi Saad , Hannon Loay , Steiner Stefan , Chitrao Amogh
Published: November 2019

Rock typing represents an important tool for classifying clastic reservoir rocks, especially in reservoirs showing low permeability and low porosity values. For this study we first approach these challenges from a geological perspective and subsequently translate the results of traditional facies and RQ analysis into rock types by integrating previously obtained results with mercury injection capillary pressure (MICP) data. The rock typing workflow proposed by Rushing et al. (2008) is applied to the low porosity-low permeability Unayzah Formation penetrated in three offshore wells, UAE. The characterisation of this type of low reservoir quality (RQ) rock confronts the geologist with some challenges.

The Unayzah Formation is an important clastic reservoir unit in the Middle East, especially in the UAE. It is characterized by low porosity and low permeability values and therefore, according to Holditch (2006) can be classified as a tight gas reservoir where a tight gas reservoir is "a reservoir that cannot be produced at economic flow rates nor recover economic volumes of natural gas unless the well is stimulated by a large hydraulic fracture treatment or produced by use of a horizontal wellbore or multilateral wellbores". In order to characterize the Unayzah Formation we used newly acquired geological and laboratory data obtained from detailed core description, facies, petrographic- and reservoir quality analysis. In a second step we translated these geological laboratory related data into rock types by integrating these data with MICP data considering pore throat geometries for a more accurate reservoir quality characterisation of the Unayzah Formation.
A Systematic Approach to Design and Development of a New ICD to Minimize Erosion and Erosion-Corrosion
Authors: Woiceshyn Glenn , Dikshit Ashutosh , Hagel Liam
Published: November 2019

To prevent or minimize problems associated with water coning in horizontal oil producers, inflow control devices (ICDs) are installed along the wellbore to better equalize the toe-to-heel flux. Nozzle-based ICDs are popular because they are: 1) easy to model accurately, 2) virtually viscosity independent, and 3) easy to install at the wellsite with many unique settings. Nozzles can be installed either in the wall of the base pipe (radial orientation) or in the annulus between the base pipe and housing (axial orientation). The advantages of the former are: 1) smaller max running OD, and 2) no need for a leak-tight, pressure-rated housing. One disadvantage is the high exit velocity that raises concern of erosion or erosion-corrosion of the basepipe.

To overcome this disadvantage, a new nozzle had been developed with a novel geometry that reduces the exit velocity about ten-fold compared to a conventional nozzle for the same pressure drop and flow rate. Computational fluid dynamics (CFD) was used to first fine tune the design to meet strict erosion-corrosion prevention requirements on the wall shear stress downstream of the nozzle for both production and (acid) injection directions, and then to develop flow performance curves for four different nozzles "sizes" that vary in their choking ability, thereby allowing many unique settings per joint at the wellsite.

Full scale prototype manufacturing and flow loop testing were then performed to validate the CFD flow performance predictions and to demonstrate mechanical integrity and erosion resistance for high rate production and injection. The results, as presented herein, demonstrate a robust and commercially viable ICD design that: 1) has predictable flow performance using CFD, 2) minimizes erosion and erosion-corrosion in either direction, 3) minimizes running OD, 4) simplifies the housing design, and 5) allows easy installation at the wellsite with 34 unique settings per joint. Also discussed are two new advantages over other ICDs that were not anticipated in the original development.
Field Experience on the Design and Operation of Mid-Water Arch MWA in South China Sea
Authors: Mohd Zain Zanussi , Fontaine Emmanuel , Abdul Hamid Saifulbahari
Published: November 2019

This paper reviews the current industry practice for the design of Mid-Water-Arch (MWA) including the guidance from International Standards, requirements from Class, engineering (EPC) installation (OIC) practices. Best industry practice has been developed by MISC Berhad based on the past experiences and leasons learnt , to ensure the continuity of operations and prevent production loss through immediate mitigation actions, efficient repair strategy and minimum requirements for new design. The benefits of establishing of a minimum size of tether chain and the implementation of backup tether interventions are emphasized. The information provided in this paper may provenly useful for Class to amend mooring guidance to account for specific technical requirements for MWA long term requirement.
Assessment of Fishbone Well Design Performance in a Tight Carbonate Compared to Single Extra-Long MRC Lateral
Authors: Alyan Mohand , Al Sowaidi Alunood
Published: November 2019

A reservoir simulation study of different fishbone well designs performance compared to a base development well design of extra-long maximum reservoir contact (MRC) single lateral wells is presented. The objective is to compare different well design concepts in a waterflood recovery scheme to achieve production target rate and maximize resource value for economic development of an undeveloped tight carbonate reservoir. The studied reservoir is located in a giant offshore oil field in the Middle East and was used as a representation of the different tight reservoirs within the field. It is characterized by poor quality rocks with a permeability trending from 2 – 0.5 md in a SE – NW direction.

The study compromises an assessment of the achievable initial maximum oil rate, volumetric reservoir sweep and expected ultimate oil recovery factor for different well design concepts for a base short well spacing utilized for effective pressure support. In addition to that, the impact of fishbone well design on well count reduction potential utilizing twice the base short well spacing compared to single lateral wells development design utilizing the base short well spacing was evaluated.

A sector model with equal producer to injector ratio was used with refined gridding to wells and bulk area gridded with a cell size of 10 m by 10 m in a representative area of the reservoir. The modeled wells incorporated with vertical flow performance tables with gas lift capabilities. The analysis also incorporated generating streamlines for analyzing fishbone well designs areal reservoir sweep and an examination of remaining movable oil areal distribution. An assessment matrix was formulated for comparing extra-long MRC single laterals base development design versus different fishbone well designs. The assessment matrix incorporated in addition to reservoir related flow performance indicators: drilling complexity and well cost, well life cycle activities, etc. for a comprehensive assessment.

The main findings show that fishbone well designs have complicated areal sweep performance, especially with sealed motherbore, that result in a lower oil recovery factor with higher hydrocarbon pore volume injected and water oil ratio compared to extra-long MRC single laterals. Also, fishbone well designs have serious limitations during well life cycle activities compared to extra-long MRC single lateral design in terms of stimulation, well accessibility and well intervention options making the extra-long MRC single laterals the preferred field development concept within tight reservoirs especially with the base short well spacing. Finally, the analysis has shown that Fishbone well designs can't reduce the well count since base short well spacing is still needed for effective pressure support by water injection in addition to maximizing the oil recovery factor within the field life time and building and sustaining the target plateau.
In-situ Proppant: Beads, Microproppant, and Channelized-Proppant
Authors: Huang Jiangshui , Gong Wei , Lin Lijun , Yin Congbin , Liu Fuchen , Zhou Han , Bai Litao , Song Lulu , Yang Zhengzhou
Published: November 2019

Tight oil reservoirs need stimulation in order to produce the trapped oil. The most common form of stimulation used by the oil and gas industry is hydraulic fracturing. Fracturing operations tend to create fractures including primary fractures and microfractures. The objective of this study is to develop a fracturing fluid which can be converted into microproppant, beads, and channelized-proppant as desired in-situ during a fracturing operation to enhance the hydraulic conductivity of the microfractures and the primary fractures, and simplify the hydraulic fracturing operation, where the channelized-proppant is defined as the pillars surrounded by channels.

Resin, curing agents, surfactants, and aqueous phase were mixed together to form O/W emulsion to serve as fracturing fluid. After curing process, resin and curing agent would react and form proppant in-situ. The parameters affect the proppant formation such as the curing temperatures, pressure, mixing strength, surfactant concentration, and size control additives were all studied and thus through controlling the parameters, microproppant, beads, and channelized-proppant can form in-situ as desired. The particle size distribution, sphericity, roundness, conductivity, acid solubility, and crush strength were tested.

Through controlling the experimental parameters and adding size control additives, fracturing fluid can be converted into microproppant, beads, and channelized-proppant as desired at a temperature from 30° C to 90° C. Almost 100% of the resin and the curing agents were converted into proppant with a specific density of 1.09g/ml. For the beads, both the sphericity and roundness are over 0.9, less than 2% fines were generated after being loaded to 15 kpsi, the acid solubility is 2.37%, and the conductivity of the beads of 20/40 mesh tested with proppant loading of 1 lb/ft2 at 4000 psi at room temperature was 227 mD-ft. For the microproppant, both the sphericity and roundness are close to 1 with d50 about 80 µm. Furthermore, channelized-proppant was formed in an artificial fracture with walls made of glass sheets. Thus, with the fracturing fluid developed, the conductivity of the well can be maximally optimized through the in-situ formation of channelized proppant and microproppant to keep the primary fractures and microfractures open respectively.
Designing the Maximum Allowable Cost of Surface Facilities Using the Control Chart Analysis: A Case Study in Indonesia
Authors: Abdul Azizurrofi Ahmad , Erwanto Edward , Asnidar Asnidar , Rahmat Firdaus Rikky
Published: November 2019

During the period from 2005 to 2018, the oil prices had reached the highest level in 2008 (99.67 US$/bbl) and the lowest level in 2016 (43 US$/bbl). The fluctuation in oil prices will affects the cost of investment (drilling and surface facilities) worlwide. Based on this condition, the standardization of the Investment Cost is needed to help the government and contractor in estimating the cost of investment in an oil and gas project.

As per December 2018, there were 471 projects approved by the government of Indonesia and the 266 of them are projects that producing oil (oil projects) and gas (gas projects). In these projects, there are details of investment costs that are included in the economic evaluation. This paper will calculate and produce the Maximum Allowable Cost ("MAC") of surface facilities per boe (US$/boe) based on statistical analysis of 266 projects. Hopefully, this method can be used as a reference (guidance) in giving approval for the cost of surface facilities and providing an overview to contractors regarding the estimated MAC of surface facilities in an oil and gas project.

For the purpose of this paper is, to divide the areas of Indonesia into 2 areas (Onshore and Offshore) which in each of these areas has 2 different types of projects (oil project and gas project). Then, to collect the data that related to cost of surface facilities and reserves and then the MAC of surface facilities per boe are calculated and produced using the Control Chart Analysis method. Lastly, the result will be distributed to those aforementioned areas.

Based on the analysis of 266 Projects in Indonesia, the MAC of surface facilities per boe in Onshore area are 20.80 US$/boe (oil project) and 18.59 US$/boe (gas project), while the MAC of surface facilities per boe in Offshore area are 14.32 US$/boe (oil project) and 27.62 US$/boe (gas projects). In general, the MAC of surface facilities per boe still far bellow the oil price.

Finally, this paper will show how to produce MAC of surface facilities per boe by using control chart analysis. This paper also expected to provide references for the government of Indonesia in giving approval to the cost of surface facilities proposed by contractors and provide contractors a quick look at oil and gas industry in Indonesia especially to those who plan to invest in Indonesia, and also help them create their petroleum exploration and exploitation strategy in Indonesia by considering on this information that will provide benefits for both government and contractor.
Cost Effective Structural Extension of Shallow Water Wellhead-Cum-Production Platforms with Concept of Partial Jacket
Authors: Shah Jinesh , Chatterjee Prabir
Published: November 2019

Due to requirements of process and other facilities upgrade, offshore platforms frequently need structural extension to create additional deck space. The present work deals with a wellhead-cum-production platform installed in 2011 at offshore Turkmenistan of Caspian Sea. The offshore platform consists of two 4-legged fixed jackets in 33.0 m water depth with 12-conductor slots. The platform requires additional space to install artificial lift systems and other process facility upgrades along with increased power generation capacity. Installation of another 4-legged jacket requires several months of engineering, construction and installation activities with sizeable marine spread and significant additional cost. Hence, to optimize the cost and schedule, extension of the platform is designed considering two partial jackets connected to the platform by means of clamped (underwater) and welded (above water) connections which can be carried out by smaller capacity cranes ensuring easy integration to the existing structure.

This paper proposes a method of installing horizontal structural extension by partial jackets and new piles. The structural extension of the platform will provide about 30% additional deck space with two or three levels. A partial-jacket is adequately connected to the existing structure to ensure intended distribution of vertical and horizontal loads. A partial-jacket frame thus address the requirements of guiding the piles as well as strengthening of the platform in compliance with code-check requirements (API RP 2A or ISO 19902).

Most of the steel structure can be fabricated and assembled at onshore and transported to designated location based on lifting capacity of the installation barge/vessel crane. The partial jackets, pile segments, deck framing and other loose items can be lifted (to/from the transportation barge) and installed by a barge crane of about 100 MT capacity for the present case. The same crane can also be utilized to drive the new piles.

The few advantages of the proposed method are: An optimum solution to create additional space for extra process facilities on production platformThe light structural weight helps in utilizing available small crane vessel for installation of partial jackets, deck framing and also driving the piles.The installation can be done in phases to address the immediate upgrade requirements.The entire installation work can be completed within a few weeks with minimum errors/ misalignment.This approach of platform extension has the flexibility for easy integration to the existing structure.The engineering, fabrication and installation actitivities can be performed by in-house resources (if available).
Selecting Friction Reducers Based on Variability in the Completion Water Mineralogy: Case Study, Permian Basin
Authors: Zamar Federico , Mendoza Cinthia Duran , Adil Faraaz
Published: November 2019

Performance comparisons of different tier friction reducers (FRs) using field water samples from the Delaware and Midland basins within the Permian Basin are discussed. The objective is to correlate them with their respective water mineralogy to identify the primary components affecting FR effectiveness, allowing a proper FR selection based on individual elements and not just by total dissolved solids (TDS). Identifying critical minerals that affect the proper FR selection enables making an educated FR selection not based on TDS count alone, which could potentially reduce the amount of testing and unsuccessful field trials.

To zero in on the primary elements within the water that affect friction reduction behavior, extensive testing was performed. Traditional and inductive couple plasma (ICP) water analyses were performed to determine mineralogy, and flow loop testing was performed to determine FR performance. Additionally, specific parameters (i.e., hydration time, maximum FR percentage, and stability) were measured and compared to the multiple tests to determine trends between FR performance and water mineralogy.

Understanding how a flow loop apparatus works is discussed, which helps when interpreting friction reduction performance. This is a fundamental component for understanding the behavior of the FR during testing and how it affects performance in the field. Additionally, this paper can be used as a basic guide for flow loop interpretation, and it attempts to identify possible causes of varying FR behavior in the field versus laboratory testing.
Towards Real-Time Edge Analytics - A Survey Literature Review of Real-Time Data Acquisition Evolution in the Upstream Oil and Gas Industry
Authors: Djamaluddin Basirudin , Jovin Tony , Nugraha Budhi
Published: November 2019

Edge analytics in the oil and gas industry has become an important topic, especially with the development of Industry 4.0. This paper reviews the existing literature regarding the movement away from traditional data acquisition and towards edge analytics. A meticulous, systematic literature review was conducted in order to understand how the industry would benefit from the implementation of edge analytics. It also aims to discover any advanced technologies belonging to other industries that could be of benefit to oil and gas.

The result shows that edge analytics implementation in oil and gas industry has started to build evidence for its successful implementation at the wellsite. Various innovations from other industries may be useful for further enhancement of existing edge analytics or transforming existing data aggregation of data acquisition at the wellsite.
Advanced Production Plant Optimization with AI
Authors: Kalagnanam Jayant , Piotrowski Dariusz , Murali Pavankumar , Subrahmanian Dharmashankar , Zhou Joe , Ma Claire , Silva Giovane , Williams Jacqueline , Liu Crystal , Haider Adnan , Rahman Pavel
Published: November 2019

Managing the dynamic behavioral changes of a production plant process to keep to a production plan is a challenge and requires the ability to predict the dynamic behavior of processes and alter any controls, as needed, to adhere as closely as possible to the plan. This paper presents a novel solution (called Cognitive Plant Advisor) based on the use of advanced machine learning to learn complex dynamics from sensor data coupled with mathematical programming to optimize the operations of a production plant. The Cognitive Plant Advisor provides set point recommedations for a 12-72 hour horizon to (i) improve throughput, or (ii) provide optimal recovery plan for a disruption. This advisory system has the potential to improve throughput by upto 1% of total production.
Novel Approach to Matrix Corrections in Complex Khuff Deep Gas Reservoirs, offshore Abu Dhabi
Authors: Menon Pradeep , Steiner Stefan , Mills Carey , Basioni Mahmoud , Mosse Laurent , Dasgupta Suvodip
Published: November 2019

The Permo-Triassic Formation of Khuff in offshore Abu Dhabi has shown a considerable potential as a tight gas reservoir, but the complex mineralogy and the heterogeneity has made formation evaluation challenging for this reservoir, particularly in respect to saturation. Complexities with log interpretation in these tight formations have called for the use the advanced measurements to help interpret more basic logs in a simple but accurate and consistent manner.

Deriving porosity from density requires the knowledge of matrix density. In complex Khuff reservoir, with a varying mix of dolomite and anhydrite with some calcite, it is impossible to put a constant matrix density. Photoelectric factor is not enough to resolve the mineralogy and advanced spectroscopy measurement is mandatory to provide matrix properties such as grain density, neutron (thermal and epithermal) and sigma (capture cross-section). These properties are used to compensate the formation density, neutron and sigma for the matrix effect, focusing any residual separation between the corrected porosities onto fluid effects.

Matrix-corrected density, neutron and sigma porosity curves can be used effectively to qualitatively interpret presence of gas, which is a big challenge in these tight gas reservoirs and this approach is demonstrated on multiple datasets. Since this is being applied on wireline logs with a depth of investigation shallower than 10-in, uncertainties remain concerning the deep, uninvaded zone water saturation. The deep resistivity measurement is still the only access to deep saturation. To quantify the water saturation from resistivity, besides the knowledge of formation water salinity, the other key information is the Archie parameter m (cementation exponent), which is directly dependent on the texture of the rock. Complex diagenesis on the varying mineralogy of the Khuff has created complex water-phase tortuosity, which needs to be considered. Multi-frequency dielectric measurement in addition to giving a shallow zone water saturation, also provides a water-phase tortuosity parameter, which is then used to improve deep water saturation computation.

When facing a complex reservoir, the temptation is high to jump to complex evaluation workflows, neglecting simple, quick-look-type approaches. However, advanced measurements, such as spectroscopy and dielectric dispersion empower this type of simple approach, enabling efficient controls and insights on the evaluation, as will be shown through the examples in this paper. Final evaluation still requires a fully integrated analysis, but it will benefit from the lesson learnt and insights from the quick-look.
Unlocking Challenges in Water Injection Development Schemes Utilizing a Novel IRM Automation Workflow for Opportunities Generation
Authors: Shbair Alaa , Saputelli Luigi , Noordin Firdaus , Bogoslavets Victor , Alblooshi Younes , Soufi Abdulrahman Al , Hijjawi Mohammed
Published: November 2019

Water injection is by far the most popular method used in the secondary recovery phase of field development for oil displacement and pressure maintenance. Proactive reservoir management is important to validate the efficiency of the existing water injection schemes and to assess field development strategies to prolong oil production plateau and improve the recovery factor (RF). The main challenges arise in stretching the reservoir target whilst ensuring stabilized or reduced water cut (WCT), minimizing by-passed oil volumes and preventing wells from becoming inactive due to high WCT.

In order to mitigate premature water flooding issues, mainly two options are available: (1) artificial lift techniques to activate producers suffering early and rapid water breakthrough; and (2) optimized completion designs via preventive or corrective controls. Preventive (i.e. proactive) approach involves segmenting the wellbore using sliding sleeves, influx control equipment, limited-perforated liners, while corrective (i.e. reactive) methods attempt to divert/remedy unwanted water influx via water-shut off (WSO) interventions. None of these alternatives can be fully pursued as full-field development strategies without realizing the technical limitations as well as their economic benefits.

The objective of this paper is to determine the value of applying subsurface water control strategies in the context of enhancing reservoir management and develop a novel framework to assess potential remediation opportunities. The technical evaluation was supported by a robust Integrated Reservoir Management (IRM) process. This process identified the rig/rigless jobs opportunities to intervene inactive wells due to high WCT and rank all possible mitigation methods in an automated economic manner.

The findings have also proved the value of installing autonomous inflow control devices (AICDs) to control water production along horizontal sections. In effect, it controlled water slumping without jeopardizing oil production of wells awaiting gas lifting. A case scenario of combined Gas-lift and ICD deployments suggested a net incremental value of $66 million (or 106%). Field test results of the horizontal well's production and WCT were found to be within 10% of the expected planned rates, and the oil gain is expected to further improve by 50% when gas-lift is commenced.
Production Assurance of Oil Field by using Integrated Modeling
Authors: Gouhar Hatem , Zhao Wenyang , Youssef Lina
Published: November 2019

The Production Assurance Tool is developed to calculate the potential oil production from any field for different operational scenarios considering well potential and pipeline network limitations. This Tool represents integration between the pipeline hydraulic model and the performance of the production wells.

The developed tool utilized PIPESIM software to model the pipeline network and Microsoft Excel as database for well performance in the format of lift curve, applying reservoir constraints and best reservoir management practices and as a general user interface for inputs and results. The programming script is performed by visual basic code to link PIPESIM with Microsoft excel to run number of iterations until the net system capacity is concluded. The challenges in each field determine the objective and configuration of the tool.

The tool is being utilized extensively by COMPANY as an efficient, accurate and swift method to support strategic decisions related to net capacity of the field considering reservoir potential and pipeline network limitations. Examples of applications include optimizing plans of new wells, identification of production loss and possible areas for compensation for specific operational scenario.

The tool is totally controlled by the designed general user interface with no physical interaction with the PIPESIM software and it can be easily updated with latest well lift curves and guidelines via COMPANY database, which is regularly updated by subsurface team.

As being an In House Tool, it can be always updated and tweaked as required for different objectives.

The tool provided an efficient methodology to fill the gap between reservoir performance and pipeline hydraulics by using available tools in the COMPANY with no extra investments and reduced the time required to conclude the feasibility and production optimization of different flow assurance scenarios.
A Broadband Full Azimuth Land Seismic Case Study Onshore Abu Dhabi
Authors: Glushchenko Anna , Roig Carlos , Smith Cara , Vasilyev Pavel
Published: November 2019

A state-of-the-art, high-density full azimuth seismic dataset was acquired over a producing field south-west Abu Dhabi to determine optimum high-resolution acquisition and processing parameters. The existing 3D seismic data was acquired in 1994-95 with low fold coverage. The central part of the new seismic volume has good well control to develop, optimize, and QC processing workflows. The new dataset utilised the system with single-sensor geophone accelerometers, point source DX80 vibrators using the Maximum Displacement sweep design with an enhancement of low frequencies as such a broadened amplitude spectrum. The key specifications for seismic acquisition include full azimuth high-density single-source / single-sensor data, long offsets and a broadband vibroseis sweep that retains low frequencies down to 3Hz. The single-sensor single-source technology and the full azimuth dense geometry (5x5m grid) was designed for an optimum subsurface imaging for this survey. The volume was processed through anisotropic prestack time and depth migration followed by poststack wavelet processing and spectral balancing.
How CFD Can Help to Understand Corrosion in Heat Exchanger
Authors: Christian Chauvet , Christophe Meynet , Fariz Maktar
Published: November 2019

Despite the long service life of heat exchanger with minimum maintenance, more and more tube rupture due to corrosion in heat exchangers are observed and become one of the most common cause of failure in any type of production facilities. In the recent cases studied by the Wood CFD team, it appeared that the main reason of the failure came to a bad distribution of the flow either on the shell side or within the tubes entraining an increase of the tube wall temperature.

Computational Fluid Dynamics (CFD) have been used in several occasion in order to determine the detailed flow pattern of the shell fluid especially around the inlet of the heat exchanger in order to identify areas of poor flow distribution. The increase of computing power and the reliability of the modelling approach have allowed to develop more accurate models which can help the engineers to understand the detailed phenomena happening in the heat exchangers.

The regions with recirculation or low velocity identified by the CFD are often matching the region where tube wall thinning due to corrosion are observed. The CFD modelling is not only limited to the shell fluid but can be also coupled with simulation of the tube fluid and conjugate heat transfer within the tube walls. The CFD simulation of the complete vessel allows the corrosion engineer to fully understand the mechanism at the origin of the failure. Through several examples, the author will demonstrate how CFD simulations have been used to understand the root causes of the failure and help the corrosion engineer and the heat exchanger designer to improve the performance and prevent failures.

The approach used has proven to be very effective to identify root cause of heat exchanger failure and is now proposed at a standard practice when such incident happens
AI Based Intelligent Pigging Solution
Authors: Nidhi Varun , Rao Rakesh , Mittal Aakash
Published: November 2019

Pigging is a process used by operators to efficiently run oil and gas pipelines. It involves PIGs short form for Pipeline Inspection Gauge, to perform various maintenance operations. PIG tool is pushed in the pipeline using the pressure inside the pipeline. This is known as the pigging process. It is used for cleaning and inspection of pipelines among other functions. PIGs are launched and received using special purpose sections installed at various locations of the pipelines called launching and receiving stations. In this paper we will be discussing the use of smart or intelligent PIGs, used for inspection of pipelines.

An intelligent PIG has many sensors along its circumference to capture the information about the health of the pipeline. Some of the most used sensors used for inspection are Magnetic Flux Leakage (MFL), Ultrasonic and Eddy current. PIG also contains other sensors like Gyro, Odometer used to estimate the location of the PIG and other diagnostics parameters for sensors and corresponding electronics. In this paper we are covering PIGs with MFL sensors used for the inspection. The tool contains a data storage device to store the data captured by the sensors for post processing and analysis. Once an inspection run is completed the storage device is used to download the data to computer system for analysis. Pigging companies generally use their proprietary software tools to analyze the inspection data.

The data contains signatures from the inspected pipeline. A skilled analyst with the help of the software tool is able to classify the signatures. The classification is divided into known features of the pipeline like weld, magnetic marker, sleeve, flange and more. The other division is defects namely metal loss, dents and more. Efficient detection and classification of defects allows the operators to take proactive actions, increasing operational efficiency, life of pipeline and reducing chances of faults and unplanned shutdowns. Some of the critical parameters used by operators to analyze the corrosion in the pipeline are wall loss percentage due to metal loss, depth profile, repair factor and metal loss clusters. Major part of this paper covers the use of software to detect and classify different metal loss features in the pipeline.