bluuebunny/crossref_metadata_2025 huggingface dataset:
Maintaining Seal Integrity During Waterflooding in Shallow Depleted Heavy-Oil Sands: Implications to Geomechanical Model
Authors: Ahmed Khalid , Zhang Ian , Schutjens Peter , Benham Philip , Saika Pabitra , Mirhasanov Ramil , Al-Rabah Abdullah , Reijnders Gert-Jan , Warrlich Georg
Published: December 2018

Cap rock integrity assessment is one of the corner stones for heavy oil field development where thermal, water flooding, or other Enhanced Oil Recovery (EOR) related fluid injection operation is involved. In this paper, we present our recent work related to cap rock in a heavy oil field in Northern Kuwait. The cap rock in our field is unique in many aspects compared to other heavy oil fields around the world, in that it is very shallow in burial depth, highly unconsolidated with high porosity and permeability and very ductile in terms of geomechanical properties. Furthermore, there are multiple pay reservoirs separated by different mudstone layers, so the term of cap rock becomes somewhat vague and complicated by itself. The unique properties of the cap rock in our field call for unique core analysis approaches and put up exciting challenges to petrophysical data acquisition and interpretation. A special core analysis approach has been adopted to provide mudstone porosity and permeability that is different from either the Gas Research Institute (GRI) shale analysis or the more conventional routine core analysis suitable for clastic rocks. Integrated study has been performed to understand these special attributes of the mudstones in this field, using core analysis, downhole wireline and surface mini frac measurements, which are all used as inputs into geomechanical model initiation.

Based on integrated study, we have established the fracture gradient of different layers of mudstone intervals, gain initial understanding of the rock property of mudstones in this field, and identified data and information gaps that need to be closed by further data collection and study. In the end, we have made recommendations on future mini frac data collection and core analyses for shallow unconsolidated ductile mudstones.
Understanding and Parameterization of Greater Burgan Fluid Spatial Variation Using an Extensive PVT Data Base
Authors: Ortegon Luis Rodrigo , Al-Shammari Nouf Abdullah , Al-Qattan Abrar , Al-Samhan Amina , Al-Enizi Nawaf Khalaf , Duvivier Giles , Brown Richard C. , Perez Godofredo , Ritchie Sarah
Published: December 2018

Executive Summary

Fluid characterization and mapping in the Greater Burgan field was performed using an extensive database of PVT analysis reports. This enabled an enhanced understanding of the distribution of fluids, in which a lateral compositional gradient was discovered.

Summary information of 381 samples that had been acquired from 1938 to 2017 was gathered and plotted against both true vertical depth subsea (TVDSS) and spatial directions (northing and easting). Correlations of average fluid characteristics of all these samples against TVDSS and the direction in 15° north-east was determined. The API gravity, oil viscosity and solution gas to oil ratio were parameterised as a function of horizontal direction and depth. The saturation pressure was modelled using a correlation, being a function of the other variables modelled in space. Over 30 correlations published in the literature were ranked, and the best-fitting correlation was selected to predict the saturation pressure distribution spatially. All these properties were mapped by formation.

This is the first study in which the existence of this lateral gradient is fully described. This work is being used as a reservoir management tool to predict zones close to or below the saturation pressure and reduce the production offtake from those zones and to develop an appropriate sampling plan. This work has also help manage access to the heavy oil zones.
Integrated Study for Well Productivity Enhancement in a Heavy Oil Reservoir in Northern Kuwait
Authors: Kharghoria Arun , Ahmad Khalid , Al-Rabah Abdullah Abdul , Guha Kaustubh , Kalia Devesh , Montero Jacobo
Published: December 2018

Focused well reviews were carried out to identify productivity enhancement opportunities in a heavy oil reservoir in Northern Kuwait. In an integrated effort, involving multi-disciplinary and cross-functional teamwork, well and reservoir management opportunities were assessed. The goal was to recommend well restoration and optimization opportunities for short, medium and long-term implementation, thereby creating a business impact.

The process involved an in-depth comprehensive review of 59 wells. Available completion, production and pressure build-up data were tuned to analytical well models to assess individual well. Inflow performance analyses and the sensitivity check were done for drainage volume. Based on the difference between actual well performance and its estimated potential, production enhancement opportunities for the under-performing wells were estimated with proper engineering judgement.

Initial Productivity Indices (PI) were found to be consistently higher than actual well performance during the production phase, potentially due to initial flush production and short duration of the initial tests. Design of facilities, well configurations (deviated wells) and sand production were also investigated and found to have some degree of impact on well performances. Out of 59 wells reviewed, opportunities were identified for 44 wells (~75%). Out of these, 26 wells were identified for productivity enhancements methods and water shut-off/management (18 wells). Once recommendations are implemented, oil production is expected to increase by 20%.

Results obtained from the study indicates that the approach of suitable inflow management is a critical aspect to the heavy oil recovery project. This approach could be applied to other heavy oil projects with practical challenges of oil production with managed gas and water productions to maximize recovery.
Optimizing Training Paths in the Heavy Oil Realm: Insights Developed in KOC
Authors: Capello Maria Angela , Benham Philip , Warrlich Georg , Sousa Maria J. , Nassef Mostafa , Cheers Michael
Published: December 2018

Developing the necessary skills in the oil and gas workforce has always been a challenge for operating companies, as each individual needs not only knowledge in their specific discipline but also sufficient understanding of the interfaces to other parts of the business. The challenge is higher for specialized areas of application, like Heavy Oil. This paper will present our insights and learnings in the process of shaping skilled profiles needed to handle heavy oil developments, grounded on our experience in Kuwait Oil Company (KOC), with a focus on subsurface profiles.

To further support the development of its heavy oil resources, KOC signed a 10-year Enhanced Technical Services Agreement (ETSA) with Shell in December 2016, in which a key driver is the enhancement of KOC staff technical competencies. Within this framework, KOC and Shell jointly created a capabilities-development program for Heavy Oil staff, encompassing discipline-driven coaching, on-the-job training, attachments, mini-learnings, and customized courses, constituting a blended-learning approach.

Heavy Oil developments and operations require integration of information, knowledge and experience from the very early phases of the field development, due to the high cost per barrel that challenges profitability. Every optimization counts. In addition, there are specific skills inherent to heavy oil, like steam injection expertise, cap rock characterization, modeling/management of viscosity changes, besides processing and transportation.

After the culmination of the first year of the ETSA, opportunities to accelerate the uplift the efficacy of the training plans for heavy Oil skills were identified: Cross-discipline training, to enhance the integrated approach to studies and operationsMore operational and hands-on training formats needed in the blended training frameworksAssessment processes, pre- and post-learning events, to measure the value of trainingStrategic career planning as a planning requisite for the optimization of trainingSoft skills training, to endow the creation of enriching teamwork, beyond corporate cultural nuances.

A selected example will exemplify how the collaboration efforts IOC-KOC for integration were successful, exposing Reservoir Engineers to an integrated core and field-based seminar that was shifted from a pure geological focus to address multidisciplinary topics such as reservoir modeling, steam conformance, reservoir heterogeneity and integrated analysis of subsurface-surface interdependence.

The learnings derived from the first year of exchange and collaboration between an NOC and an IOC will be useful for similar cases in the world, to augment the specialized skills and core expertise in the oil and gas workforce.
From Exploration to Production in Record Time: A Case Study of Lower Fars Heavy Oil Reservoir in Umm Niqqa Field, Kuwait
Authors: Sajer Abdulaziz , Al-Bader Haifa , Al-Rabah Abdullah , Singh Sunil , Harami Khalid , Dillabough Garahm , Al-Ajmi Afrah , Al-Ibrahim Abdullah , Ayyavoo Mani Maran , Al-Ateeq Abdullah , BoSalhah Ammar , Dashti Jalal , Al-Qattan Faisal , Al-Houti Shoroq , Mushnuri Sudhakar , William Awad , Arguello Luis , Sangani Pratik , Chakravorty Sandeep , Franco Francy , Sahmkow Roberto
Published: December 2018

Conventionally discovery to development of a heavy oil reservoir takes very long (Minimum 10-15years). However, significant volatility in the oil prices have required more collaborative workflows and strategies from operators and service companies to optimize cost and maximize efficiency and innovation. We present here a joint service integrated model between an NOC and a service company which was used in the fast track development of an unconventional heavy oil reservoir and resulted in discovery to production in record time.

A conceptual field development plan was put in place for fast track development of the Lower Fars reservoir in the Umm Niqqa field after drilling and testing 26 exploration wells. The plan consisted of drilling and completing over 80 wells in conjunction with the construction and commissioning of an early production facility (EPF) to handle the sour heavy crude. Given the brief time and the unconventional nature of the reservoir, significant challenges were faced during the execution phase. To address the challenges, an integrated workflow was put in place combining multiple disciplines. The entire project required seamless integration between drilling, characterization, production and surface facility teams for flawless execution. The collaboration resulted in successfully drilling and completing all planned wells in less than 1 year.

This paper describes the tasks performed during the project for successful execution. It was initiated by a robust assessment of the discovery in terms of OIIP and type of hydrocarbon. It further describes the construction of a fit for purpose field development plan. During the execution phase we explain the challenges faced while drilling deviated wells in soft unconsolidated reservoirs with extremely shallow kick off points. The challenges in logging and evaluating deviated wells to optimize completion strategy are also described. The optimization of testing, completions and artificial lift workflows played a significant role is assessing the dynamic behavior of these reservoirs. The workflows in conjunction with continuous production monitoring and workover planning allowed the minimization of non-productive time (NPT). We further highlight the surface facility designed for such heavy sour crude and the recommendation for future development.
Feasibility of Multi-Physics Reservoir Monitoring for Heavy Oil
Authors: Passalacqua Herminio , Davydycheva Sonya , Strack Kurt
Published: December 2018

A new microseismic-electromagnetic (EM) acquisition system for reservoir monitoring includes surface and borehole hardware, processing software and interpretation methodology. For heavy oil reservoirs it allows mapping of steam/water flood fronts and surveillance of cap-rock integrity. The new array acquisition architecture combines novel technologies which reduces operational cost, due to unlimited channels capability: EM and microseismic acquisition is in the same receiver node to optimize the synergy between the methods.

While microseismic channels address seal integrity information, EM data are used to track fluids, due to their high sensitivity to the fluid resistivity. The fluid resistivity drops strongly with mobility increase and pore size variation. Dense data further reduce the cost per receiver in a surface location. EM channels provide three-component (3C) electric and 3C magnetic data acquired on the surface and in shallow vertical boreholes. For later versions and deeper reservoirs deep wireline receiver with through casing measurement capabilities are planned. We include in the system an independent physics verification measurement using a differential approach to the surface data called focused source EM (FSEM) with practically little cost.

Carrying out feasibility for each reservoir is key to control risk and cost. The feasibility includes 3D EM modeling, which allows integrating typically complex nature of the reservoir, and on-site EM noise test to tie 3D modeling to actual measured voltages.

3D modeling feasibility for a heavy oil reservoir proves the methodology to monitor the boundaries of the steam flood with accuracy and with high fidelity. Above the edges of the flooded (higher-temperature – lower-resistivity) area the results predict time-lapse EM anomaly exceeding 500%.

The entire system is coupled with processing and 3D modeling/inversion software, significantly streamlining the workflow for the different methods.

The system is capable of measuring and integrating the 3C of the electric field and 3C of the magnetic field in order to map the steam front and at the same time measuring microseismic occurrences in order to monitor seal stability. Channels capability of the system is practically unlimited allowing a denser coverage of the area in order to increase resolution and improve inversion.
Successful Installation of Stand Alone Screen in Challenging Environment in Umm Niqa Field
Authors: Zeidan Amr , Al-Bader Haifa , Pandey H Chandra , Al-Ibrahim Abdullah , Ayyavoo Mani , Al-Ateeq Abdullah , AL-Kandary Esraa , Erhamah Abdulaziz , Bosilca Daniel
Published: December 2018

Objectives/Scope

In 2014, number of exploratory wells were drilled and tested in Umm Niqa (UN) Field located in north Kuwait NE which approved a new discovery in Lower Fars (LF) reservoir.

LF is unconsolidated, sub –hydrostatic- sand stone reservoir with highly sour and moderate corrosive environment (H2S 8% and CO2 4%). Subsequently additional wells were drilled to evaluate the production potential of UN field. With rig on location UN wells are completed with test (Progressive Cavity Pump) PCP and tested. During the initial testing period the PCP is run at different speeds to evaluate the well productivity, water cut, and determine sand-free draw down to enable selection of suitable completion PCP for production.

Methods, Procedures, Process

Well UN-X is one of the developed wells which is perforated in LF sand in overbalanced condition using 4-1/2" (High Shot Density) HSD guns with 0.83" entrance hole diameter at 12 shoots per foot.

During initial testing with test PCP, the pump tripped due to high torque because of sand production (up to 60%). Five runs were performed to clean out the wellbore and repeated test PCP runs failed due to high sand production.

Coordination between FDHO (Field Development Heavy Oil) and Discovery Promotion Team was conducted to perform quick sand analysis to LF sands from offset sand distribution since subject well has no available sieve analysis. Based on the outcome of sieve analysis, decision was made to utilize one of the available SAS (Stand Alone Screen) designed for LF sand in another field to control sand production. It was agreed by both teams to install SAS in the subject well to mitigate the sand problem and minimize cost due to NPT (Non-Productive Time) of the rig. SAS was installed and the potential zone in UN-X could be tested successfully with tubing PCP. No sand problem was observed during testing and after testing while clean out operation there was no sand.

Results, Observations, Conclusions

Well test showed an average liquid rate of 124 BFPD with 37% WC (predominantly completion brine). The well was put on production on November 2016 and producing till date without any sand problem.

Novel/Additive Information

This paper will include discussion on the approach used to select a sand control method for cold and heavy oil production. The results of sieve analysis was in the middle between sand screen and gravel pack but based on the team experience in sand control and the nature of heavy oil and its relatively low oil production rate, the decision was made to install SAS and that was proved to be prudent decision.
Simultaneous Occurrence of Miscible and Immiscible Displacement Processes During Solvent Displacement of Heavy-Oil: A Parametric Analysis Using Micro-Scale Experiments
Authors: Shi Yu , Babadagli Tayfun
Published: December 2018

Oil-solvent mixing is essential during solvent injection applications to reduce the viscosity of oil but mass transfer by diffusion becomes slower as the oil becomes heavier. Thus, an interface exists between oil and solvent at certain times being stronger in the beginning of the process. This results in an immiscible displacement controlled by the capillary forces while mixing is in progress. It is of practical and fundamental importance to determine the mechanisms responsible for the displacement of heavy oil and the behavior of solvent (acting as both immiscible and miscible displacement agent) as it could be advantageous to accelerate the dilution of heavy oil in many circumstances, including heterogeneous (fractured, layered, wormholed) systems. This is a complex process consisting of multiple pore phases (oil, solvent, their mixtures, aqueous and vapor phases) at the same time while different mechanisms such as capillary imbibition, miscible interaction (diffusion and convection), and gravity also act simultaneously.

To investigate this complex phenomenon for different oil-solvent systems, a novel experimental method was employed. The underlying mechanisms that dominate the solvent displacement process were comprehensively identified. The movement and evolution of interfaces among different fluid phases in glass capillary tubes was observed and recorded. The oil samples with different viscosities were utilized to examine the effects of oil viscosity on the mass transfer accelerated by imbibition transfer. The effects of temperature, wettability and boundary conditions on the interaction of miscible fluids pairs were also studied. Pentane, heptane and decane were used as the solvent phases. Advanced photographic techniques using UV light and dyed fluids were applied to better track the flow of different phases in the mixing zone.

The experiments demonstrated a slowly smearing interface between solvent and viscous oil. A unique natural convection was induced with the combined effect of gravity, diffusion (mixing) and capillarity all contributing to the recovery of heavy-oil. Based on the saturation method, boundary condition and the Bond number, four different motion modes of mixing zone and interfaces of miscible fluids in the capillary tube were unveiled and categorized to identify the degree of interface development (immiscible flooding). Also, the mixing zone, mass flux, and flow behavior were quantified using dimensionless parameters. The results indicate that priority may be given to a solvent with a high interfacial tension for solvent-based oil recovery technique because of a strong imbibition and further enhancement of the dilution and displacement processes under condition of similar viscosity ratio. The data provided will be useful for the accuracy of modeling studies, especially for complex geologies where oil-solvent interaction is critically difficult to develop in order for mixing to occur.
Improving the Decision Making for Heavy Oil Field Development Projects Using the Fuzzy Analytical Hierarchy Process FAHP
Authors: Passalacqua Herminio , Qubian Ali
Published: December 2018

The selection of the best EOR option for optimizing the recovery in a field development plan is probably one of the most difficult decisions, as many parameters and options, as well as uncertainties play a role difficult to rank and characterize. This work presents the application of a new methodology, Fuzzy Analytical Hierarchy Process (FAHP), aimed to select the best EOR option, illustrating its practical application to a heavy oil field development case.

In order to rank efficiently prospects opportunities and exploitation scenarios the most common approach is the evaluation based on economical parameters. However, technical parameters like well-types options, facilities configurations, transport options, operability, and reliability, are not strictly, nor solely economical parameters, hence, not easily considered during the screening and selection phases of the FEL (Front-End-Loading) process. When the number of options and parameters becomes very large, the human judgement must be supported by some kind of logical methodology or Multiple Attribute Decision Making (MADM) methodology.

One of these methodologies is the FAHP (Fuzzy Analytical Hierarchy Process) which is a modification of the Analytical Hierarchy Process (AHP) tested previously for the development of a heavy oil field in the pre-FEL stage aiming to improve the decision-making process, including technical elements in addition to the conventional economic parameters.

The application of the FAHP technique is analyzed in this work, deriving conclusions of interest when dealing in field development decisions that require decisions from a group of experts.
Application of Supercritical Water Coupled with Toe-Point Injection Technique for Heavy Oil EOR: A Case Study
Authors: Qu Shiyuan , Jiang Hanqiao , Li Junjian , Hu Jinchuan , Sun Fengrui , Qiao Yan , Dong Mingda , Chen Wenbin , Zhou Yu
Published: December 2018

Heavy oil is an important part of unconventional resources. Many great breakthroughs have been made in heavy oil EOR mechanism of thermal methods. With the unprecedented development of technology, Super-critical Water Coupled with Toe-point Injection Technique is entering people’s view.

Compared with previous thermal methods, the reservoir can be heated to a higher temperature by injecting supercritical water, obtaining a larger heated radius. Meanwhile, toe-point injection could abate the problem of early channeling and unequal steam absorption caused by heel injection in extremely long horizontal wellbore or reservoir of serious heterogeneity, which results in a higher recovery rate.

In this paper, a novel topic is discussed on the effect of different parameters on oil productivity during the single horizontal well production process, using discrete horizontal well model. The recovery process is completed through a single horizontal well--the supercritical water is injected into the reservoir through the tubing, while oil is produced to the surface through the annulus. Some meaningful conclusions are listed below.

(a) Under the same production policy, the recovery ratios of supercritical water are generally higher than those of steam, indicating that, besides its chemical reactions with heavy oil and rock minerals and fracture initiation ability, the effect of physical properties (high pressure and high temperature) on oil recovery efficiency also play an important role in the usefulness of supercritical steam in heavy oil recovery. (b) The relative well height in the reservoir has significant influence on the production performance, whose impact varies as the production methods change. Consequently, the optimum well position ns under diverse production methods are different. (c) The direction of oil recovery is from toe point to the heel point. The matching between well height and the growth of steam chamber and water puddle decides the production performance.
Effective Matrix Acidizing Based in Chelating Agents: A Case Study in Romanian Heavy Oil Reservoirs
Authors: Panait Emil , Isac Constantin , Marton Csaba , Dos Santos Arlinda , Girardi Stefano
Published: December 2018

Heavy and extra-heavy crude oil reservoirs hold physicochemical characteristics that can frequently turn their operation into a technical and economic challenge. Typically, heating techniques are used to decrease oil viscosity. Areas with steam injection are susceptible to developing formation damage mechanisms such as scale precipitation that gradually restricts the flow of fluid towards the wellbore and ultimately decreases overall well productivity and/or injectivity. Acidizing treatments to either remove obstructing scale or to further increase near wellbore permeability are handled with caution: heavy oil is very sensitive and interaction with such conventional acids include asphaltene precipitation, sludge and emulsions.

Suplacu de Barcau is a shallow, heavy oil reservoir (16°API average) located in the northwestern part of Romania. It has been successfully operated with aid of both in-situ combustion and steam injection since 1960. Scaling tendency of condensed water from steam and its incompatibility when mixed with formation water frequently ends in scale build-up in injector and producer wells respectively. Identifying a fluid able to clean-out the scale deposits while being fully compatible with sensitive heavy oil, involved extensive screening a compatibility testing protocols. A formulation based on the chelating agents N,N, Glutamic Acid Diacetic Acid (GLDA) and Diethylene Triamine Pentaacetic Acid (DTPA) were found not only to effectively dissolve the plugging materials, but remarkably it was also noticed that it reduced significantly the oil viscosity, which made this formulation the most appropriate treatment for field application.

A number of 10 producer wells treated with the GLDA and DTPA based fluids delivered promising results by increasing oil rates by 3- 6 times of increase, significant improving steam coverage and penetration, decreasing drawdown and skin and ultimately enhancing the mobility of asphaltic oil. This paper describes the stimulation approach followed from diagnosis, fluid screening and selection, treatment design, job execution and results. Furthermore, the outcome of this stimulation campaign has shattered the myth that this type of stimulation does not work in hard oil.
Urban Planning in North Kuwait: Collaborating Across All Assets to Optimize Developments and Exploit Synergies
Authors: Warrlich Georg M. , Al-Dohaiem Khalid , Al-Boloushi Ahmed , Abdelrahman Hesham , Kumar Vaidyula S. , Al-Rashdan Saad , Schrameyer Sandor , Cheers Mike , Hulshof Bart , Al-Haqqan Hamad , Reijnders Gert Jan , Al-Rabah Abdullah
Published: December 2018

The Northern part of Kuwait is a highly active development area for deeper gas, intermediate-depth conventional oil and shallow heavy oil. All these developments have overlapping footprints in an already congested area, requiring different development concepts for gas, water flood and steam respectively. Additionally, different Assets manage the respective reservoirs. Integrated Urban Planning across all Assets therefore becomes a vital requirement for realizing all concurrent future developments regarding land use, and enabling close collaboration to leverage synergies among the Assets, utilizing both organizational and new technology-based solutions, in order to maximize value for Kuwait Oil Company (KOC).

In North Kuwait Urban Planning is a joint effort between KOC and Shell, with initial focus on establishing an agreement for work methods, effective communications, and protocols with all stakeholders. Next all "as-built" infrastructure and current plans were combined and reviewed. This formed the basis to identify and resolve conflicts, recognize opportunities for reduced land requirements and optimize the development synergies. The approach is underpinned with new technologies, tools, best practices, and concepts like multi-well pad developments, area discounting, exclusion zones, and shared infrastructure and road access corridors, based on global analogue developments.

In this paper example field ‘A’ is discussed as it has stacked reservoirs of shallow heavy oil, intermediate conventional oil and deep, sour gas. It requires significant urban planning focus to avoid conflicts and enable synergies. In field A, the shallow heavy-oil development requires large number of wells in a dense well-spacing versus fewer wells targeting the intermediate-depth conventional oil and deeper gas reservoirs, which requires large "safety zones" around well sites. In both cases, common infrastructure like roads, power distribution, flow line and trunkline corridors also need to be considered jointly.

Urban Planning collaboration between assets with distinct development challenges can help in creating safe co-development opportunities, thus maximizing value for KOC.
Evaluation of the Scaling Resistance of Different Coating and Material for Thermal Operations
Authors: Fattahpour Vahidoddin , Mahmoudi Mahdi , Roostaei Morteza , Cheung Stephen , Gong Lu , Qiu Xiaoyong , Huang Jun , Velayati Arian , Kyanpour Mohammad , Alkouh Ahmad , Strom Raymond , Fermaniuk Brent , Zeng Hongbo , Luo Jing-Li
Published: December 2018

Several alloys and coating techniques have been used by industry for their anti-corrosion and anti-fouling properties in the industry. One of the major problems in thermal operation is related to silica and calcium carbonate scale. In this study, we intend to better understanding the relative scaling resistance performance of different coatings and alloys exposed to typical formation water in thermal operations. This paper provides a study on failed samples collected from various projects in Western Canada. Moreover, a review of research work on scaling properties of different materials in thermal applications will be presented.

Different failed screens were collected from various projects in Western Canada. Thin section analysis, X-ray diffraction (XRD), scanning electron microscopy (SEM) joined with energy dispersive X-ray spectroscopy (EDX) were performed on collected failed pipeline samples to determine the composition of the scale material. Obtained results revealed that the main scaling materials are silicates and carbonates. Chert, clays and carbonates act as cement to bind sand grains (mainly quartz).

Later, a review was performed on an ongoing investigation regarding the materials and coatings for improving the anti-scaling properties. Bulk scaling tests, Atomic Force Microscopy (AFM), and in-situ field trials were used to investigate the anti-scaling properties of two RGL proprietary grade materials, proRC05, and proRS06, as well as electroless nickel (EN) coating. Carbon steel L80, carbon steel 4140 and EN30B alloy steel were used for comparison. The microstructural change of the material surface was studied using complementary techniques (e.g., XRD, SEM, and EDX). The tests have been performed under a complex chemical environment that represents the chemistry of the near screen condition in thermal operation, to assess the relative performance of different coatings. Among proRC05, proRS06, 4140 carbon steel and EN30B alloy steel, the anti-scaling performance follows the order of proRC05 > proRS06 > 4140 carbon steel > EN30B alloy steel. Comparison between EN-coated and uncoated samples shows that the EN-coated carbon steel L80 provides better anti-corrosion and fouling resistance performance with a small amount of iron oxides and silica foulants. Field trials of EN-coated technology have been also proven to be effective.

This work provides a detailed review on recent attempts on evaluating the anti-scaling properties of various materials and coatings to minimize the silica and calcium carbonate scale. Furthermore, field trials were reviewed for evaluating the scaling and corrosion properties in thermal production. The results of this study will help engineers select material for projects in which silica and calcium carbonate scaling could be a significant issue.
Designing of a Groundwater Production Scheme for the Northern Oil Fields, Kuwait
Authors: Al-Enezi Huda , AlMuhaimeed Imad , Al-Mutairi Meshaal , Al-Senafi Mohammed , AlKhalid Asem , AlFahad Khalid
Published: December 2018

The Kuwait Oil Company's (KOC's) future development plans propose an increase in the production and utilization of groundwater reserves in the northern oil fields, where new groundwater gathering centers are to be constructed for water handling processes. In order to preserve the natural resources of the country, and realizing the fragility of the fresh/brackish/saline coexistence in the groundwater resources of northern Kuwait, the Water Research Center (WRC) of the Kuwait Institute for Scientific Research (KISR) conducted this study on behalf of KOC. The main objective of the project was to design, locate and set a production schedule of groundwater wells to produce 10,000 m3/d with salinity less than 10,000 mg/l for a specific period of time. This study will enhance the potential of utilizing brackish water at the project area while maintaining minimum mixing between brackish and saline groundwaters. To fulfill its objectives, this study conducted data collection followed by designing and constructing several production and observation wells that were used for a program of pumping and recovery tests. During this field work, a campaign of groundwater sampling and water level measurements were conducted. The water samples were analyzed in the appropriate laboratories for physical, chemical, and biological parameters according to international standards. Then, another stage of numerical modelling took place to simulate the movement of saline and brackish waters putting all the newly drilled wells into operation. The results showed that it is possible to extract 10,000 m3/day from the project area with a salinity ranging between 3,500 and 10,000 mg/l indicating brackish water quality. The groundwater in the study area is of sodium chloride and sodium sulphate type, and no organic contamination of groundwater was detected in the study area. However, the study also shows that it is not possible to extract water from certain locations because the salinity will be elevated above the design limit of 10,000 mg/l.
Wellbore Trajectory Optimization Using Rate of Penetration and Wellbore Stability Analysis
Authors: Abbas Ahmed K. , Alameedy Usama , Alsaba Mortadha , Rushdi Salih
Published: December 2018

Drilling deviated wells is a frequently used approach in the oil and gas industry to increase the productivity of wells in reservoirs with a small thickness. Drilling these wells has been a challenge due to the low rate of penetration (ROP) and severe wellbore instability issues. The objective of this research is to reach a better drilling performance by reducing drilling time and increasing wellbore stability.

In this work, the first step was to develop a model that predicts the ROP for deviated wells by applying Artificial Neural Networks (ANNs). In the modeling, azimuth (AZI) and inclination (INC) of the wellbore trajectory, controllable drilling parameters, unconfined compressive strength (UCS), formation pore pressure, and in-situ stresses of the studied area were included as inputs. The second step was by optimizing the process using a genetic algorithm (GA), as a class of optimizing methods for complex functions, to obtain the maximum ROP along with the related wellbore trajectory (AZI and INC). Finally, the suggested azimuth (AZI) and inclination (INC) are premeditated by considering the results of wellbore stability analysis using wireline logging measurements, core and drilling data from the offset wells.

The results showed that the optimized wellbore trajectory based on wellbore stability analysis was compatible with the results of the genetic algorithm (GA) that used to reach higher ROP. The recommended orientation that leads to maximum ROP and maintains the stability of drilling deviated wells (i.e., inclination ranged between 40°—50°) is parallel to (140°—150°) direction. The present study emphasizes that the proposed methodology can be applied as a cost-effective tool to optimize the wellbore trajectory and to calculate approximately the drilling time for future highly deviated wells.
Cost Optimization Study of Soak Period and Production Cycles of Cyclic Steam Injection in Lower Fars Heavy Oil LFHO Reservoir
Authors: Alshammari Awadh T. , Alajmi Haifaa M. , Marquez Sharoh G. , Farhart James L. , Al-Otaibi Faisal S.
Published: December 2018

The cyclic steam stimulation (CSS) and injection process is a thermal recovery process consisting of three main stages: steam injection, steam soak and production of the heated oil. Before a stimulated well is put into production, a soak period is required to allow the injected steam to heat the oil around the wellbore and reduce its viscosity so that it will become more susceptible to flow. In actual operations, the soak period could vary from days to weeks, or even months. Prolonged soak period causes the well productivity to decline because of the continuous heat loss to the formation. On the other hand, insufficient soak period prevents effective transfer of the heat from the wet steam into the formation. For this reason, it is desirable to determine the optimal soak period that will maximize oil production and net profit during cyclic steam injection. The injection period at the beginning of the cycle, as well as its ensuing production period is also investigated to verify which stage in the CSS process is most influential in assuring higher recovery.

In this study, a thermal, numerical reservoir oil simulator is utilized to evaluate the effect of varying the injection volume, soak period and production period with a view to improving crude oil recovery in Ratqa-North Kuwait Lower Fars Heavy Oil (LFHO) reservoir. Further economic studies are then pursued to determine the effectiveness of cyclic steam injection operations whilst maintaining a safe operational environment ensuring cap-rock integrity and also avoiding localized pockets of higher pressure and temperature (heaving).

The key findings from this study was that the maximum injection period (60 days), minimum soak period (5 days) and minimum production period (90 days) are required for every cycle, in order to maximize recovery and optimize the cost.
The Function of Baffles within Heavy Oil Reservoir and their Impact on Field Development: A Case Study from Kuwait
Authors: Benham Philip , Freeman Mike , Zhang Ian , Choudhary Pradeep , Spring Laurent , Warrlich Georg , Ahmed Khalid , Shen Chonghui , Sanwoolu Ayodele , Jha Madan , Al-Haqqan Hamad , Al-Boloushi Ahmad , Al-Rabah Abdullah
Published: December 2018

A heavy oil field (Field X) in Northern Kuwait is in the early stages of development but it is clear from production pilots that tight units (baffles) of variable lithology, thickness and continuity, within the reservoir will play a key role in influencing steam conformance and recovery efficiency. The high well/core density of the field’s production startup area allows re-evaluation of baffles in light of cross-discipline integration of pilot production data, petrophysical data and detailed core review.

A process was followed to update and calibrate all core descriptions against logs, follow a consistently picked set of petrophysically defined markers, compare visually defined lithofacies with log defined ones, and then map out key surfaces. The key next step is to define appropriate reservoir properties by facies/rock types, apply these to understanding pilot behaviour and predict steam conformance for Well, Reservoir and Facilities Management (WRFM) and the next phases of the wider field development planning. The field’s baffles play a role far beyond just understanding steam conformance, they are a first barrier for cap rock integrity and their presence/absence will also influence the path and rate of the aquifer influx.

The petrophysical redefinition (Baffle Quality Index) of a "semi-stratigraphic" interval - which will stop or slow steam migration depending on its quality and lateral extent - has enabled efficient communication about the baffle, and allowed the wider team of petroleum engineers from a number of subsurface disciplines to focus on dynamic properties impacting recovery – steam conformance, aquifer influx, windows between isolated reservoir units – and then evolve the development strategy, effectively respond to WRFM issues, optimize observation and infill well placement and increase UR in a cost effective way.
Sand Production Assessment & Sand Control Selection for Steam Flood in South Oman
Authors: Al Shizawi Wafa , Al Zadjali Ruqaiya , Mahajan Sandeep , Bellmann Lars
Published: December 2018

A thermal steam project has been successfully implemented in a Petroleum Development Oman (PDO) field in the South of Oman. The thermal project developed the crest of the field which has mainly formation A. The thermal response has been favorable as witnessed by the incremental oil recovery. The steam flood is now planned to be expanded further to the South where it will encounter the same formation as currently developed at the crest & to the North where it will encounter two new formations (B & C). The new formations have limited field data on sand production; therefore a sand prediction evaluation for both cold & thermal production conditions is required for these new formations. In this paper we describe the analysis of the sand control potential and the selection process of the sand control technology.

The assessment of the potential for sand production and the requirement for sand control was based on a combination of a) actual field data such as sand production, well performance & completion data; and b) a sand prediction model for the hot and cold operating production conditions utilizing rock-mechanical data. In addition, core sieve analysis data were used to determine the Particle Size Distribution (PSD), which was used to select the sand control type and screen slot width.

The sand evaluation study demonstrated that for formation A has only the probability of transient sand failure under hot operation conditions. The wells will therefore be completed without sand control. On the other hand, formations B & C have a risk of catastrophic sand failure under both cold and hot operation conditions. A completion with thermally compliant sand control is a must for formation B. In case of formation C the selection of sand control is challenging as the sand distribution shows a high percentage of fines. In this case sand control is obtained through selective perforation, excluding the sand prone intervals. The impact of blanking the high GR intervals on inflow is expected to be low as the average the permeability for these intervals is low.

The implementation of the selected Stand Alone Screens for sand control in formation B will be the first thermal application of these screens in PDO.
Sand Control Strategy for Unconsolidated Sandstone Heavy Oil Reservoir in Kuwait
Authors: Reda Mahmoud , Erhama Abdulaziz , Henderson Kerry , Al-Mulla Yousef , AlMuhanna Tamadhor
Published: December 2018

Production deferment due to wellbore sanding issues is a major risk for heavy oil field development. The heavy oil reservoir in Kuwait is a multi-stacked unconsolidated formation, which is prone to sanding. Currently there are two steam flood pilots in inverted 5-spot pattern configuration with pattern areas of 5 and 10 acres. The wells were operated for two cycles of Cyclic Steam Stimulation (CSS), before their conversion to steam flood.

Different Sand Control equipment is field tested in some pilot wells to optimize production in this viscous oil-saturated unconsolidated sandstone reservoir. This paper will discuss the operational challenges and the difference in the performance of cold production and after thermal CSS cycles of the installed Stand-Alone Sand Screens (SAS), which were retrofitted in the pilot wells. The mesh size of the SAS was designed based on the particle size distribution and well operating condition.

A comprehensive reservoir and well surveillance program was conducted to monitor and gather necessary data to characterize the reservoir and well performance in the pilot wells equipped with sand control equipment. The primary objective was to determine the optimal sand control strategy, moving forward in to the commercial phase of field development.

This paper will discuss the learnings from the pilot wells. The various SAS used were partially successful in mitigating sand production. More piloting with advanced sand controlling technologies at both laboratory and field levels may be required to reach to the optimum design for the field-specific cases.

The well trials using SAS was mainly to assess the screens regain permeability (skin) versus crude oil production while minimizing sand movement within the wellbore. This helped to improve the artificial lift pump run life and minimize sand debris from entering the pump.
Reducing Operating Costs through Accurate Measurements
Authors: Marshall Craig
Published: December 2018

Heavy oils are characterised depending on their density rather than their viscosity [1]. Although there are various definitions for what constitutes heavy oil it is commonly agreed that the majority contain impurities such as asphaltenes, waxes and carbon residue. The API gravity definition, a common definition used in the oil and gas industry worldwide, states that heavy oil has an upper limit of 22°. Figure 1 shows the upper and lower limits of various categories of oil as stated in the API gravity definition.

Confirmed world oil reserves are split approximately into 70% high viscosity and 30% (low viscosity) conventional light oils. High viscosity oils are regarded as a vital energy resource for the foreseeable future, with significant yields forecast at 100 years or more.

A literature review conducted by NEL and Oxford University highlighted the issues facing application of conventional flow meters to high viscosity fluids [2]. Following on from the review, an initial experimental test programme [3] was instigated using a selection of conventional flow meters applied in viscous fluids. The overall conclusion from this work reinforced the notion that liquid flow meters cannot simply be relocated from low to high viscosity service without suitable characterisation or modification, nor can calibrations conducted in a low viscosity medium necessarily be applied to heavier crudes without appropriate compensation.