bluuebunny/crossref_metadata_2025 huggingface dataset:
Technology Focus: Bit Technology and Bottomhole Assemblies (December 2018)
Authors: Mensa-Wilmot Graham
Published: December 2018

Technology Focus

Rock characterization, with regard to determination of mechanical and geologic properties, is critical for performance drilling. This consideration ensures appropriate offsets analysis. Additionally, it promotes several benefits in project planning and execution, with regard to bottomhole-assembly (BHA) design and compliance analysis, drive-system evaluations, bit selections, hydraulics considerations, drilling-parameter ranges, and anticipation of operational dysfunctions. Performance drilling, when deployed holistically, contributes to cycle-time and project-cost reductions.

In most instances, hardness is considered to be the most critical rock property in bit-selection discussions. Field performances, and results from this classification, have not been consistent with this claim. Recent research shows that, in addition to hardness, other rock properties, such as lithology types, heterogeneity, and abrasiveness, have equal importance in bit evaluations. Consequently, the discussion must move from rock-strength analysis to rock-drillability analysis, which is more inclusive.

BHAs must achieve their expected functional roles without creating vibrations or conditions that compromise project success. Vibration events commonly have been tied to BHAs or drill bits. Efforts aimed at addressing vibration challenges through bit and BHA changes have not produced the desired results. Researchers have identified additional influences (e.g., drilling parameters, drilling fluid types, rock-drillability factors, stabilizer types and geometries, reamers, wellbore trajectory, and drive systems) that also serve as vibration sources. Consequently, strategies or solutions aimed at addressing vibration challenges must target their sources to ensure effectiveness of such solutions.

Performance consistency, aided by effective bit-wear predictions, promotes cycle-time reduction. Improvements in rock-drillability analysis, bit selection, BHA design, drilling-parameter selections, and vibration remediation, coupled with the industry’s advancements in downhole-tool development and data analytics, must ensure appropriate monitoring and prediction of bit wear. Research must delve into the different bit-failure modes—wear and impact, different wear stages, and the totality of factors that drive the wear process.

Recommended additional reading at OnePetro: www.onepetro.org.

IADC/SPE 189697 Real-Time Downhole Data Resolve Lithology-Related Drilling Behavior by Christopher Viens, Nabors Drilling Solutions, et al.

SPE 187445 Real-Time Bit-Wear Prediction Using Adaptive Data Analytics by Vikrant Lakhanpal, University of Houston, et al.

SPE 188427 Experimental Investigation of the Effects of Rotational Speed and Weight on Bit on Drillstring Vibration, Torque, and Rate of Penetration by Vimlesh A. Bavadiya, University of Oklahoma, et al.
Controlled Source EM to Monitor Steam Injection in the Ratqa Heavy Oil Reservoir
Authors: Cuevas Nestor , El-Emam Adel Hassan , Al-Jenaie Jarrah , Hafez Mohamed , Ceci Federico , Pezzoli Mauro
Published: December 2018

Numerical studies are presented to evaluate the sensitivity of surface and surface to borehole Controlled Source Electromagnetic (CSEM) methods, to monitor the evolution of a steam plume injection in EOR for the Ratqa heavy oil reservoir, in North Kuwait.

A surface CSEM dataset collected over a pilot area in 2011 was used to determine a baseline 3D model of electrical resistivity at reservoir depth. To this end, the data underwent constrained 3D inversion, incorporating a-priori information from resistivity well logs and seismic horizons and focusing the inversion within the reservoir. The resulting 3D model provided high resolution of the lateral and vertical distribution of electrical resistivity within the reservoir, which was further verified by comparison with direct interpolation of well log data available over the entire area of the survey. Perturbations of the reservoir resistivity were then introduced by arbitrarily lowering the resistivity in a thin disk defined around a test wellbore, such as to represent a steam plume homogeneously expanding away from the borehole. Datasets were then numerically simulated to determine the expected response of EM measurements performed by surface deployed receivers and excited by sources deployed both on the surface and in the borehole, within the reservoir section. It was found that surface CSEM data could be used to recover the resistivity anomaly produced by the steam injection, provided that the injected steam generates a plume with a radius > 60. Smaller plumes produce a surface response which was close to the measurement's noise level expected in a 4D time-lapse survey. A STB-EM configuration was found to yield a strong sensitivity of the response even for radius of the plume < 20m.

At the outset the analysis presented here shows that resolution of surface based deployments is low, but they can be used to determine large scale variations within the reservoir. Novel and recently developed STB-EM technologies can yield the resolution required of the length scales variations expected in EOR processes.
Benchmarking Of Heavy Oil Fields: A Tool for Identification of Opportunities for Total Cost and Production Optimization
Authors: Ortiz-Volcan J. L. , Al-Khamees W. , Ahmed K.
Published: December 2018

This paper presents a practical method for benchmarking heavy oil fields as a tool for identification of opportunities for total cost and production optimization. The method combines actual data from typical heavy oil fields to define reservoir, well and surface complexity indices, for categorizing a subject field and a total cost breakdown model to map potential risks that could cause total cost to increase, potential project/process delay and poor production performance.

The benchmarking process consists of four steps: 1) classification of a subject field using Front End Loading (FEL) and complexity indices that account for: a) reservoir structural, stratigraphic, rock, fluid, energy, static and dynamic complexity, b) well complexity and c) surface processes complexity; 2) selection of analog fields within the range of indices; 3) use of causal maps to identify causes of uncertainty and risks that impact capital expenditures (CAPEX), operational expenditures (OPEX), production losses and cycle time; and 4) a total cost stochastic model is used to generate graphs providing the position of the subject field vs. analogs.

A total undiscounted cost breakdown structure provided information on the most critical cost drivers, where significant impact corresponded to OPEX. Causal maps described typical total cost drivers for surface and subsurface. Seven most significant groups of risks are modeled to visualize the impact on cost, production losses, cycle time and health, safety and environment with recommended mitigation actions ranked by cost benefit.

A database provides information about cost of production (Capex, Opex) from heavy oil fields undergoing cold production and thermal enhanced oil Recovery well-known heavy oil production areas from Venezuela, Canada, USA and Middle East.

Heavy oil fields undergoing thermal enhanced oil recovery indicated typical ranges for Opex from 2 to 22 USD/bbl and Total Cost ranges from 10 to a maximum of 40 $/bbl. A key observation is that cost of fuel and power is the largest single OPEX cost for thermal enhanced recovery accounting for about 50%. Significant production losses are associated to failures due to corrosion and blowouts is the most significant HSE risk.

The proposed method helps benchmarking total costs in heavy oil fields, which is a task that requires lot of efforts in researching available reliable sources from technical papers, regulatory agencies, and oil industry.

Understanding causes of high cost per barrel and their relationship with uncertainties and risks for heavy oil field, is a formidable tool for multidisciplinary cost optimization as it provides a common language that understood by all disciplines involved.
Laboratory Experimental Study on New Polymer in Xinjiang Lukeqin High Temperature and High Salt Reservoir
Authors: Wang M. , Xiao Q. , Gou Y. , Deng F. , Wang B. , Zhang D.
Published: December 2018

The Lukeqin Triassic reservoir in Xinjiang, China, is a heavy oil reservoir with high temperature and high salinity. The formation conditions are harsh. With the deepening of oilfield development, the reservoir enters into a high water cut period and faces the problem of stable oil and water control in the middle and late stage of development. In addition, the heavy oil reservoir has complex characteristics, such as deep, thin, thick and so on, so it can not be converted to conventional thermal recovery mode. Therefore, a solution to the reservoir conditions is urgently needed. In order to improve the mobility ratio of water drive, a new type of high temperature resistance and high salinity polymer SWP322 has been developed. In this study, the compatibility, viscosity, temperature resistance, salt resistance and shear resistance of the polymer in Lukeqin reservoir were evaluated and compared with that of HPAM. Finally, the formation conditions of Lukeqin reservoir are simulated to test the percolation and oil displacement ability of the new polymer SWP322 under the conditions of high temperature and high salinity. Experiments show that the polymer has a temperature resistance of 100°C and a salinity resistance level of 2.0×105 mg/L. The experimental results show that the polymer SWP322 has a lower dissolution rate at room temperature than HPAM, but its temperature resistance, salt resistance, shear resistance, and temperature resistance are far better than those of HPAM. With the increase of temperature and salinity, the apparent viscosity of HPAM decreased rapidly, while SWP322 was almost independent of temperature and salinity, and the viscosity retention rate was more than 99%; at the same time, the viscosity retention rate of SWP322 after core shearing also reached 98.6%, which proves that SWP322 is superior to HPAM in its resistance to temperature and salt, and excellent shear resistance also helps to maintain the viscoelasticity of the polymer in the formation. Increase oil displacement efficiency. In terms of seepage capacity, the flow resistance of SWP322 is much better than that of HPAM, and the resistance coefficient and residual resistance coefficient are all more than 5 times that of HPAM; in the process of simulated oil displacement, the displacement efficiency of water flooding is 30.43%, while the flooding efficiency of first polymer flooding and subsequent water flooding is 16.6% higher than that of water flooding; the oil displacement efficiency of double-pipe polymer flooding is 13.19% higher than that of water flooding; the oil displacement efficiency of single tube and double tube flooding system is 16.1% and 23.2% higher than that of water flooding, respectively.
Augmented AI Solutions for Heavy Oil Reservoirs: Innovative Workflows That Build from Smart Analytics, Machine Learning And Expert-Based Systems
Authors: Castineira David , Zhai Xiang , Darabi Hamed , Valle Manuel , Maqui Agustin , Shahvali Mohammad , Yunuskhojayev Alisher
Published: December 2018

Many heavy oil fields have recently seen exponentially higher volumes of data being made available from omnipresent connectivity. Existing data platforms have traditionally focused on solving the problem of data storage and access. The more complex problem of true knowledge discovery and systematic value creation from all this massive amount of data is less frequently addressed. There is a new, novel workflow that tackles the problem of building intelligent data analytics in heavy oil fields. This multidisciplinary solution builds from Augmented AI, i.e., a combination of artificial intelligence/machine learning and domain knowledge or expertise.

Our solution has been proven effective in a Latin American heavy oil field and is presented here. We built an integrated view of the reservoir through a series of smart metrics and KPIs. This was accomplished by integrating expert-based knowledge with the analysis of geological data, reservoir behavior and production and operational performance. Our analytics-based solutions were designed from the perspective of reservoir management, and consequently, they could assimilate production and cost/economic analysis with geological information (e.g., well logs and/or existing geological models) and reservoir performance (metrics for pressure, voidage, fractional flow, reservoir contact, etc.). From here, KROs (key recovery obstacles) were identified for this heavy oil field, and robust field development opportunities (i.e., behind-pipe opportunities and/or new well targets) were methodically proposed based on an innovative saturation mapping approach. Our solution exploited existing cloud economics at scale, sustained advances in hardware capabilities (including GPUs running machine learning workloads) and iterative improvements in algorithmic learning techniques.

Ultimately, we will demonstrate a smart analytics-based solution that can be systematically implemented in heavy oil reservoirs for robust diagnostics and comprehensive field development opportunity identification. The proposed methodology intelligently combines both field experience with data-driven and machine learning methods.
Industry First; Rigless ESP Enables Wellbore Access to Perform a Coiled-Tubing Clean Out.
Authors: Dornan Grant , Autry Sydney , Fox Pete , Krysinski Marina , Nutter Greg , Cheblak Samer
Published: December 2018

The Access ESP system, a Thru Tubing Conveyed Electrical Submersible Pump (TTCESP), also referred to as a rigless ESP system, was installed in a well that had a history of producing significant amounts of sand and fine solids. During production of the wellbore fluids, solids accumulate in the well bore and lower completion restricting the inflow and well performance below the ESP, requiring a clean out intervention with a coiled-tubing operation to clear the restriction and return the well to full performance.

This paper records the retrieval and replacement of the rigless ESP to access the wellbore and perform a coiled-tubing clean out of the lower completion wellbore without the use of a heavy workover rig. The rigless ESP retrievable assembly components were removed through tubing, in a live well intervention, using a slickline unit, and coiled tubing unit. The application of the AccessESP system provided significant benefits and demonstrated its potential application for any ESP operation that necessitates frequent well interventions, has high rig costs, or resides in locations with limited rig availability.

The rigless ESP retrievable assembly is made up of four segments that are retrieved individually. Beginning from the uphole end of the retrievable ESP assembly, the first segment is the tubing stop, next a tubing packoff with a standing valve, then the complete pump assembly from pump discharge, pump, and pump intake, and on the downhole end is the motor assembly which includes the seals, motor, downhole gauge, and plugarm wet connector assembly. When these four components of the retrievable ESP assembly have been pulled from the well thru-tubing, there is open access to the lower completion wellbore.

An isolation sleeve was installed to protect the wet connector dock in the rigless ESP permanent completion from mechanical damage during the coil-tubing clean out process. After the clean out was completed the isolation sleeve was retrieved and the four components of the rigless ESP assembly were reinstalled and the well was placed back on production. The intervention and methods described herein confirms the viability of the access to the lower completion and wellbore and to perform slickline and coiled tubing well work interventions with the rigless ESP system.
Once through Steam Generator Integrity OTSG
Authors: Al-Ajmi Ghassab , Abulkair Sayed , Mejbel Barzan , Alrasheedi Mahmoud , Al-Awadi Abdulla , Wahba Ehab , Osman Mohammed , Abdulaziz Reda
Published: December 2018

Kuwait Oil Company (KOC) intends to develop Lower Fars Heavy Oil field on the north of Kuwait that requires steam generation.

The Lower Fars Heavy Oil (LFHO) Development Project is targeted at a large heavy oil accumulation of approximately 7 to 15 billion barrels oil-in-place located in a desert area of some 1, 200 km2 in North Kuwait. The development of this heavy oil resource is important to Kuwait's production strategy.

The LFHO reservoir has been partitioned into Well-Blocks; Phase 1 of the LFHO Development Project consists of two such Well-Blocks, which are intended to achieve a target plateau of 60,000 BOPD over a ten-year period from start of operations. This rate will increase after ten years, with future phases ramping up production up to a final plateau of 270,000 BOPD.

Reservoir engineering work performed to date indicates that phase 1 areas can best be developed by two or three cycles of cyclic steam stimulation (CSS) followed by continuous steam flood (SF) with steam quality of 55% (wells) to 80% central processing facility (CPF). The steam will be generated by multiple Once-Trough Steam Generators (OTSG) located in a central processing facility (CPF).

The Once through steam generation (OTSG) will use for generating steam utilizing treated boiler feed water to improve recovery of hydrocarbon from a reservoir.

Integrity process for steam generation equipment considered on Project various stages e.g. equipment selection, design, fabrication, inspection and testing.

Integrity process also considered during operation process of OTSG units within a defined integrity operating window (IOW) to establish and maintain a controlled process environment which would enable boiler feed water to be converted into steam in a safe, environmentally responsible manner without upsets and planned shutdown.
Effect of Pressure and Temperature of Steam in Parallel Vertical Injection Wells on Productivity of a Horizontal Well During the SAGD Process: A Numerical Case Study
Authors: Sun Fengrui , Yao Yuedong , Li Guozhen , Qu Shiyuan , Zhang Shikun , Shi Yu , Xu Zhengming , Li Xiangfang
Published: December 2018

Great breakthrough has been made in heavy oil EOR mechanism under water injection at different state. New findings from both experimental and theoretical studies provide strong support for the broad application prospect of steam in heavy oil EOR. In this paper, a series of studies are carried out on productivity of a horizontal well with several vertical steam injectors during the steam-assisted-gravity-drainage (SAGD) process.

In this paper, a novel topic is discussed on the effect of steam state on oil productivity during the SAGD process. The injection wells are three parallel vertical wells and the production well is a horizontal well. The numerical method is adopted to reveal the physical aspect mechanisms. Some meaningful conclusions are listed below.

(a) The usefulness of superheated steam in heavy oil recovery lays in its chemical reactions with heavy oil and rock minerals. The effect of physical heating on oil recovery efficiency is weak. (b) The oil production rate at the starting stage, from 0 day to 30 day, is oscillating with time due to the fact that the preheating stage is neglected. The connectivity between injectors and producer is poor without a necessary step of preheating. (c) The direction of oil recovery is from well-bottom of the injector to the well-head and then to the places between the injectors. (d) Chemical reactions may play an important role in oil recovery efficiency if the final recovery efficiency by injecting steam with higher steam quality is several order of magnitude than that by injecting steam with lower steam quality.

We carried out the pilot study on the effect of steam state on heavy oil EOR during the SAGD process with several vertical injectors. More importantly, the pilot study conducted in this paper provide the very basis for the application of superheated steam for oil companies and following academic research in the field.
Pore Scale Simulation of Surfactant Flooding by Lattice Boltzmann Method
Authors: Wei Bei , Hou Jian , Wu Dejun , Wang Huiyu , Liu Hao
Published: December 2018

Surfactants play an important role in the widely used enhanced heavy oil recovery methods such as surfactant-polymer flooding and alkali-surfactant flooding. In this study, we focus on the effects of surfactant during surfactant flooding and provide a pore scale simulator of surfactant flooding based on the Lattice Boltzmann (LB) method.

We introduce a dipole to present the amphiphilic structure of surfactants in the Lattice Boltzmann model, and characterizes microscopic fluid interactions at the kinetic level. There are three velocity distribution functions to present the oil, water, and surfactant species, and every distribution follows the discrete Boltzmann-BGK equation. There is also an additional dipole vector representing the orientation of amphiphile, so that the interactions related with surfactants depend not only on particle relative distances but also on their dipolar orientations.

The simulation results show that surfactants can reduce the oil-water interfacial tension and recover more oil trapped by capillary force. Moreover, surfactants are able to emulsify the flooding system, forming O/W emulsions or bi-continuous micro-emulsions. Higher surfactant concentration leads to smaller oil droplets in emulsions. In addition, the phase distribution morphologies in porous media are much different in different wetting conditions. By associating the fluid-solid interfacial tension with the surfactants adsorption concentration on walls, we characterize the wettability alteration mechanism in LB model accurately. The oil recovery can be improved by changing the wettability from oil-wet to water wet, increasing the surfactant concentration, and enhancing the adhesion parameters. However, the adsorption onto walls leads to unnecessary waste and could decrease the surfactant concentration in bulk phase.

The study provides an effective pore scale tool to simulate the surfactant involved interfacial flows in porous media. In addition, we can use it to study the flow mechanisms and remaining oil distributions during surfactant flooding.
Downhole Receiver Based Technology for Geophysical Monitoring of Super-Viscous Oil Deposits Development by Steam Injection
Authors: Sudakov Vladislav , Khasanov Damir , Stepanov Andrey , Nurgaliev Danis , Usmanov Sergey , Amerkhanov Marat , Lyabipov Marat
Published: December 2018

The authors consider the technology for monitoring of shallow super-viscous oil (SVO) deposit development process aimed to determine the heated zones distribution corresponding to the drainage areas to enhance the efficiency of development process based on steam injection. The main objective of the work is to develop the monitoring approach based on downhole receivers and interpret the results of surface geophysical survey conducted with the use of downhole receiver tools.

The downhole monitoring tools (receivers) are used to improve the sensitivity of the method and to decrease the environmental influence. Each tool includes 3 geophones located in metal case and is connected with the surface by wireline. The tools are set in the bottom hole of evaluation wells and the wells are abandoned. There are several factors influencing the seismic wave velocities (temperature, pressure, saturation etc). To provide more adequate interpretation geophysical methods with different nature are were to use in complex. The surface monitoring methods considered include shallow seismic prospecting and electrical prospecting.

The results of periodical geophysical investigation are the maps of seismic wave propagation delay from surface source to the downhole receivers, electrode resistivity maps and interwell resistivity maps for different moments of time.

Basing on the change of seismic wave ray velocity the heated regions are identified and the type of fluid saturation estimated with the use of resistivity mapping. The results obtained were used for the development planning including the injection pipe positioning.

The interpretation results in terms of heated zones location obtained in the area of study was compared with the direct temperature measurements by periodical optical fiber thermometry conducted in horizontal producer wells.

The possibility of steam injection process monitoring by surface geophysics with downhole receiver tools is shown basing on the real field case of shallow super-viscous oil deposit.

The relations between geophysical fields considered and reservoir characteristics (temperature, saturation, pressure) are discussed.

The work was supported by the Ministry of Science and Higher Education of the Russian Federation (project No. 02.G25.31.0170) and by the subsidy allocated to Kazan Federal University as part of the state program for increasing its competitiveness among the world's leading centers of science and education.
New Technologies Enhance Efficiency of Hydraulic Fracturing Stimulation in Heavy Oil Reservoirs
Authors: Cai Bo , Duan Guifu , He Chunming , Gao Yuebin , Li Yang , Xu Zhihe , Jiang Wei
Published: December 2018

X oil field was located in eastern China. The lithological component of formation is fine sandstone. The typical characteristics are low-permeability and low-porosity with high viscosity, resin and asphaltene contents, the detail characteristics as follows:1)Shallow buried depth (650~850m); 2)Low permeability and low porosity(the average permeability is 1.0×10−3μm2 and the average porosity is 10%); 3)High oil viscosity,asphalt and wax content (15.2 API,24.3%and17.8%,respectively);4)Ultra-low temperature(45~53°C) with high solidify point(nearly 30°C);5) High content of clay (from 14 to 23%)and high content of velocity-sensitive minerals such as illite, almost 80 percent of wells need hydraulic fracturing treatment, therefore, hydraulic fracturing stimulation is an important technology for this tight heavy oil formations. Over the past two decades, conventional fracturing treatment has far away from satisfaction as a result of high viscosities, poor flow properties and high solidify point in compared to conventional oil. Therefore, a systematic technologies are put forward in this paper, the highlights are:1) Systematic fine formation evaluation prior to fracturing design which contains mineral gradients, nuclear magnetic resonance, rock mechanics, in-situ stress profile, X-CT scanning and so on; 2) A new finely processed pre-pad fluid is developed, and the asphalt and wax content can be reduced through completely miscible between oil and fluid interaction; 3) Low polymer concentration fracturing fluid and variable viscosities are utilized in different treatment stages. The concentration is only 0.2%-0.28% and residue content is 82mg/l reduced 45% and 35% that of the past fracturing fluid,4)Many fracturing treatment parameters are changed such as proppant's type and size, fracturing fluid's type, tip screen-out (TSO)fracturing in order to improve fracture conductivity, liquid nitrogen injection to pad fluid with multi-stage slurry injection schedule, and pumping rate as well, which makes it not only to ensure the successful treatment but also to maximize fracturing treatment potential; 5) Counter measures are applied systematically such as systematic quality control, optimization shut-in time for improve propped profile and flow back, post-treatment management, etc.

More than 120 treatments with new technologies in X tight heavy oil field have been performed with encouraging results,95% efficiency with accumulated incremental oil of 110,500 tons and the average post-fracturing rate reach to 10.5m3/d increased more than 50% that of the past well stimulation under the same formation conditions.

The novel hydraulic fracturing technology provides a new way to maximize recovery efficiency with in low-permeability heavy oil reservoirs. It also has important strategic significance for development and exploration promotion of these unconventional reservoirs.
Implementation of Well Performance Management System WPMS Leads to Significant Cost, Time Reduction
Authors: Al-Barazi Naser , Elekhteiar Hazem Mohamed , Swapnil Bhamare , Sujit Bhatevara
Published: December 2018

A Multiwell drilling campaign was undertaken to enhance the production of a heavy oil field. Well deliverability within the target time was very difficult, as the wells were designed with a challenging profile with a DLS of 13° per 100ft at a very shallow MD of +/- 1600ft. Immediate Optimization of the entire Drilling campaign was required from the inititation of the project to meet the production requirements. Monitoring and optimization of drilling performance was required through a systematic and unique improvement cycle divided into phase's viz. PLAN, DO, CHECK and IMPROVE. As all the offset wells were vertical, there was no data available for benchmarking initial drilling performances of these challenging well profiles. Once a few wells were drilled, the data was analyzed for benchmarking, technical shortcomings were clearly identified and the lessons learnt were implemented in the next planning stage. Risk assessment was done for every section based on the Non Productive Time data analysis of the few initial wells. Monitoring performances and applying corrective measures for improvement resulted in complete Optimization of the Drilling Campaign. Once performance baselines were established, an immediate impact of 10% was achieved in the subsequent batch of wells. Non Productive time and Invisible Loss time were reduced by a significant amount. Good performances were appreciated at the end of the project. Drilling Optimization lead to reduction in average drilling days per well from 12 days to around 8 days. This resulted in completion of the entire drilling campaign safely, well ahead of target time, saving not only rig operating cost, but also enabling early production. This also resulted in reduction of overall cost per foot of the wells drilled in the campaign. Effective communication of all the lessons learnt and benchmark performances to the grass root level by organizing large scale workshop on the rig site, involving all the Drilling Engineers, rig contractor crew and service partners. Technical discussions with all service partners’ together, leading to implementation of lessons learnt while drilling a challenging profile of 13°/ft DLS well.
Pressure Transient Analysis for Heavy Oil and Low Transmissivity Formations
Authors: Alcantara Ricardo , Paredes Jorge Enrique , Briones Mario
Published: December 2018

The performance of Pressure Transient Analysis (PTA) in heavy oil and low transmissivity formations is different from the conventional reservoirs, so the main objective of this work is to describe the pressure transient behavior in these low mobility-low transmissivity systems considering their impact on the main issues involved in, such as fluid viscosity, flow capacity, total compressibility and petrophysical properties.

In this analysis, we present various well tests from many low transmissivity oilfields and some other heavy oil reservoirs in Mexico that produce from distinct depositional environments in sandstones and carbonates at different depths, onshore and offshore, with the objective of comparing and analyzing the pressure transient response with respect to time and the designing and execution of well tests in these types of systems. The main aspects related to the pressure transient behavior in low-mobility and low-transmissivity formations were analyzed, especially for the time required to reach the Infinite Acting Radial Flow regime (IARF) and subsequently, the pseudo-steady or steady state, where some properties are of paramount importance such as fluid viscosity, porosity, permeability, total compressibility, capillary pressure and net pay.

The evaluation of the critical factors that rule the pressure transient behavior in low-transmissivity formations and heavy oils allows to identify certain patterns in transmissivity variations, determination of mean reservoir pressure, identification of reservoir heterogeneities and the corresponding influence of net pay on carbonates mainly. Furthermore, we suggest a series of recommendations about how to deal with this type of reservoirs when designing, executing and analyzing well tests for a better reservoir characterization through Pressure Transient Analysis (PTA).
Strategic Competencies for Non-Conventional Heavy and Extra Heavy Oil Fields: Identification, Definition and Measurement
Authors: Ortiz-Volcan Jose Luis , Al-Khamees Waleed , Ahmed Khalid
Published: December 2018

The ability to deliver oil production capacity by 2040 will highly depend on availability of strategic competencies to support the timely and reliably development of non-conventional oil fields that require intensive application of improved oil recovery technologies throughout all stages of the field life cycle. This paper presents a practical approach for identification, definition and measurement of strategic competencies required to develop and produce non-conventional heavy and extra heavy oil assets.

An activity-based strategic competency model was developed considering a typical heavy oil project with 94 activities organized in 7 field life cycle phases: 1) Data acquisition for uncertainty reduction, 2) static modeling, 3) dynamic modeling, 4) field development planning, 5) well and facilities engineering, 6) execution and 7) operations and monitoring. Each phase undergoes activities with relative duration followed by decision gates with relative contribution of technical disciplines grouped in functions. Ranges of weights in percentages and duration in months are calibrated using analog fields or typical projects, as input for stochastic modeling to account for uncertainty.

The application to non-conventional heavy and extra heavy oil fields in Kuwait, allowed identification of 55 technical competencies classified under 12 functional competency groups under four major categories: Subsurface-reservoir, subsurface-well, surface facilities & production operations and asset integration & planning. These technical competencies were mapped with three scenarios for intensity of work: minimum (low), medium (likely) and maximum (full) to conduct critical activities on annual basis during the 7 phases of the heavy oil field life cycle. Local experience in Kuwait as well as worldwide analog for heavy oil development provided foundation to validate strategic competencies and to calibrate the model, and then used as strategic workforce planning tool to support the preparation of heavy oil project proposals. The model also allowed for stochastic modeling of person-hours and total cost of the work force, including the associated competency development and assurance costs, which shall be included in both Capital and Operational Expenditures as part of the economic model for evaluation of heavy oil development opportunities.

The presented approach is a practical project-planning tool for mapping all required competencies and intensity of work force for more reliable Front End Loading (definition) of heavy oil field development business plans or for existing fields undergoing operations. The phased model allows easier planning and flexibility to conduct exercises with estimates of work force for a range of potential business scenarios.
Refining Technology and Processing Developments
Authors: Al-Azemi Hamed
Published: December 2018

Heavy crude oil production in world over is increasing gradually, resulting in higher atmospheric residue yield. Main product qualities such as high sulfur content, metals (Ni, V) & Conradson Carbon Residue (CCR) content in heavy crude & its distillation products pose challenges to refinery operation.

Kuwait Integrated Petroleum Industries Company (KIPIC) has Al-Zour Refinery (ZOR) which is designed to process a wide range of crudes; 30° to 14° API such as Kuwait Export Crude (KEC), Kuwait Heavy Crude (KHC), Eocene and Lower Fars for supplying LSFO to power plants and marketing high-quality products) for export as per international specifications. ZOR Complex has the world's largest Atmospheric Residue Desulfurization (ARD) units, which is the heart of Al-Zour Refinery. ZOR Project today is in advanced stage of Detailed Engineering, Procurement and Construction (EPC) phase.

This paper addresses the features and challenges experienced during the design of residue hydro-treating facilities for heavy oil processing in ZOR and especially ARD with respect to environmental and economic considerations. The road map of this paper starts by apprising its preliminary studies (external agencies studies & licensor pilot test), and challenges in developing a responsive design changes in the project in line with strategy of crude production plan to meet the objective of processing different types of heavy crude in KUWAIT.
The Application of CO2 Assisted Cyclic Steam Stimulation
Authors: Liu Ning , Zhang Yan , Wang Guodong , Xin Kunlie , Wang Xiaodong , Zhao Zihan , Zhao Fan , Zhang Jing
Published: December 2018

D block is a heavy oil reservoir that was first developed in 1997 with the method of Cyclic Steam Stimulation (CSS). After nearly 20 years’ development, several technical challenges have shown: the reservoir pressure decreased from 7.4MPa to 2.9MPa, and the Steam Oil Ratio (SOR) increase from 2.86 to 3.56. As a result, the traditional CSS method seems to be uneconomic.

In view of the problems shown above, CO2 assisted CSS was tested in this oilfield and has shown great success as follow: The steam injection pressure increased from 5.7 MPa to 6.9 MPa and the SOR decreased from 3.45 to 2.86. Besides the underground success, CO2 was separated from the associated gas and then reinjected into the reservoir. This process can reduce the emission of CO2 so that it is both a economic and green method. In addition, according to the field performance, this paper seeks to establish a better understanding of the possible mechanisms involved in the CO2 assisted CSS.
Loss Circulation Materials Testing Methods: Literature Review
Authors: Al-Arfaj Mohammed , Amanullah Md. , Al-Ouhali Raed
Published: December 2018

Loss of circulation is a major source of non-productive time (NPT) in the drilling operations worldwide. Different types of loss circulation materials (LCM) have been developed and used to minimize mud losses and mitigate the associated problems. Before a new type of LCM is deployed in the field, it needs to go under extensive laboratory testing with simulated downhole conditions to measure its performance. Therefore, a number of LCM testing methods have been introduced to test the effectiveness of those materials with the ability to have a high-temperature high-pressure (HTHP) environment.

Review of published information indicates different research studies with emphasis on various critical factors to come up with different testing methods and apparatus to evaluate the performance of LCM's under a set of experimental conditions. Some testing methods have the capability of doing the testing at high temperature and/or high pressure while others are built of transparent materials and have the advantage of allowing the researcher to monitor and visualize the invasion depth, fluid level drop, deposited thickness, plugging mechanism…etc. In addition, depending on the size of the apparatus and simulated openings, which frequently are slotted disks, each apparatus has a maximum limit in terms of the particle size of LCM it can handle. Practical considerations should be taken into account when designing a testing cell such as the size of the cell, simplicity and portability, data acquisition system, etc. Large testing cells require large quantities of LCM pills mixed with drilling fluids and, therefore, requiring to mix large quantities of drilling fluids for each test run. Hence, this test should be conducted for selective studies of LCM performance. Cleaning of the test apparatus after each test is an important factor as well to be considered in the design to make it more user-friendly and avoid any detrimental impact on subsequent test results.
Implementation and Assessment of Production Optimization in a Steamflood Using Machine-Learning Assisted Modeling
Authors: Sarma Pallav , Lawrence Ken , Zhao Yong , Kyriacou Stylianos , Saks Delon
Published: December 2018

Data Physics reservoir modeling and optimization was described in detail in a prior paper (SPE-185507) and can be conceptualized as a physics-based model augmented by machine learning. In brief, the production, injection, temperature, steam quality, completion and other engineering data from an active steamflood are continuously assimilated into the Data Physics model using an Ensemble Kalman Filter (EnKF), which is then used to optimize steam injection rates to maximize/minimize multiple objectives such as net present value (NPV), injection cost etc. using large scale evolutionary optimization algorithms. The solutions are low-order and continuous scale, rather than discretized, therefore modeling, forecasting and optimization are significantly faster than traditional simulation.

The goal of steamflood modeling and optimization is to determine the optimal spatial and temporal distribution of steam injection that will maximize future recovery and/or field economics. Accurately modeling thermodynamic and fluid flow mechanisms in the wellbore, reservoir layers, and overburden can be prohibitively resource-intensive for operators who instead often default to simple decline curve analysis and operational rules of thumb. Data Physics allows operators to leverage readily-available field data to infer reservoir dynamics from first principles.

This paper updates the case study from the previous paper and presents the results of actual implementation of an optimized steam injection plan based on the Data Physics framework. The case study is from a shallow, heavy oil field in the San Joaquin Basin of California, and demonstrates the practical application of Data Physics modeling and the ability to explore future injection plans. The model of the field was fit to historical data in June 2017, after which an optimization was performed and a forward-looking production forecast was established associated with a target plan chosen by the operator. This plan was then implemented in the field over the last year. This paper provides a comparison between the field implementation and the model prediction, which allows for model validation and highlights opportunities for further improvement.

For completeness, this paper includes a summary of the modeling and optimization problem and results from the previous paper.
Generation of BFW Using Bacteria Containing Reject Streams from Municipality Sewage Plant - Kuwait and Related Challenges to Meet Set BFW Spec
Authors: Ghouti Rachid , Kuijvenhoven Cornelis , Al-Anzi Ealian H , Al-Hasan Meshari M
Published: December 2018

The South Ratqa heavy oil field, located in the Northern part of Kuwait, will be developed thermally with the first phase of the development expected to become on stream in 2019. The water source to make up steam is coming from the Municipality Sewage Plant Sulaibiya (SWWTP) located in Kuwait City. The Sulaibiya plant is handling sewage water which is locally treated to make it suitable for further use. In the treatment process, RO units are used, and the reject stream of those RO units was identified as water source for the steam plant in the South Ratqa field.

In total six steps are required to cover the full treatment scheme of the Boiler Feed Water (BFW) plant, namely: (a) Water Clarifier and sludge treatment, (b) Multimedia and Ultra filtration, (c) Ion Exchange, (d) double Reverse Osmosis, (e) Ozone and Ultra Violet treatment and (f) finally De-aerator. Currently, the plant is being constructed as part of the first phase of the South Ratqa thermal development. Control of bacteria was identified early in the design phase to be crital to ensure successful operation of the BFW plant with minimal down time. Bacteria control will be done at two locations: Upstream of the BFW plant: chemical control of bacteria growth with chlorine addition.Within the BFW plant: mechanical bacteria control using a combination of ozone addition and UV.

Upstream of the BFW plant, chlorine will be added in the Sulaibiya plant located 123 km from the South Ratqa field. The project team realized that the added chlorine at this plant would not be enough to fully limit bacterial growth throughout the 123 km pipeline and more importantly, the growth in the 3 storage tanks upstream of the BFW plant. It was then decided to add extra chlorine injection capacity in the BFW plant just before the storage tanks. A suitable test protocol was developed to define the required extra chlorine demand resulting in a residual chlorine level between 0.5 and 2 mg/l entering the BFW plant and taking into account the extra residence times in the process.

The extra injection capacity is currently under design. With the help of this extra chlorine addition bacteria growth will be under control and the required high BFW plant availability can be achieved.
From Outcrop to Producing Reservoirs: Applying Jal Az Zor Outcrop Studies to A Multi-Disciplinary Development Approach In Kuwait Heavy Oil Fields
Authors: Benham Philip , Cheers Michael J. , Freeman Michael , Choudhary Pradeep , Tanoli Saifullah , Warrlich Georg , Capello Maria , Al-Rabah Abdullah A.
Published: December 2018

The previous generation of integrated reservoir models for KOC's heavy oil fields in North Kuwait brought insight which enable implementation of development decisions. With field maturation, additional well data and emerging production trends drive a need to update models to ensure relevance for serving the evolving business objectives of sustaining and maximizing incremental production.

This subsurface analysis has been augmented through study of the Jal-Az-Zor escarpment (north of Kuwait City) where stratigraphic equivalents of the reservoir crop out. Field analogues permit direct observations of the reservoir characteristics and heterogeneities that influence production behavior and ultimately project economics. They can resolve questions on spatial continuity of the key reservoir flow units by bridging the scale gap between seismic and well data which directly link to OPEX & CAPEX expenditure through optimal well spacing & design, injection steam/water conformance and BSW management.

It is relatively rare to have available such closely linked field-outcrop analogue data which is so readily accessible. The Jal-Az-Zor Escarpment represents an important cost-effective resource which is only just beginning to be leveraged in an integrated way to benefit field development and operations.

Applications for the field observation data set include but are not restricted to: Lateral and vertical continuity/variability of the reservoir, baffle and barrier lithologies.Role of diagenesis and its control on reservoir quality.Recognition of thin but critical units that need to be retained in the model e.g. high (or low) perm streaks.Appreciation of Microscopic to Field scale heterogeneities compared with well spacing.Field to Core/Log calibration to improve interpretationMultidisciplinary engagement