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.

Petroleum in general is found in sub-surface reservoir formation amongst pores existent in the formation. For several years due to lack of information regarding production and technology, free-flowing, low viscosity oil has been produced known as conventional crude oil. Fortunately, in recent times, due to advancement of technology, high viscosity with higher Sulphur content-based crude has been produced known as heavy oil. There are also exists significant difference in volatile materials as well as processing techniques used for the two types of crude. ( IEA, 2005 ; Ancheyta et al., 2007 ). The oil viscosity is a huge problem in regard to heavy oil as both recovery and processing charges increase proportional to Sulphur content and viscosity of the crude. Heavy Oil can be used by definition internationally to describe oil with high viscosity (Although the Oxford dictionary might have several variations of the same, within the contents of this paper, we refer to heavy oil as high viscosity crude). Heavy oil generally contains a lower proportion of volatile constituents and larger proportion of high molecular weight constituents as compared to conventional crude oil (often referred to as light oil, we shall describe the characteristics of the types of oil further in the introduction). The heavy oil just doesn't contain a composition of paraffins and asphaltenes but also contains higher traces of wax and resins in its composition. These components have larger molecular structures leading to high melting and pour points. This makes the oil a bad candidate for flow profiles and adversely affects the mobility of the crude. ( Speight, 2016 ). It is crucial to know the heavy oil constitution as it affects: Recovery: Low viscosity and high melting points Processing: Higher Resin, Sulphur and aromatic content Transportation: Low Viscosity These all together impact the economics related to E&P (Exploration and Production) of heavy oil resources. These resources generally have a higher of production associated with them and are one of the first candidates to be affected by reduction of crude prices as seen in 2014 and early 2015. Crude oil can generally be classified into its types by using its API values that are generally obtained through lab testing. Table B1 provides a few popular crude types and their associated API Values.

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 km 2 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.

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.

One of the key strategic directions in Kuwait Oil Company (KOC) 2040 vision is the optimization of the portfolio to capitalize on opportunities and rationalize non-core and unprofitable assets. In this context as conventional low risk oil assets are becoming more mature, compensating for the associated oil production requires building a new efficient portfolio with new higher risk opportunities for filling this future gap. KOC as a National Oil Company (NOC), will have to work within the boundaries of available resources established in the National Development Plan (New Kuwait 2035) which sets the nation's long-term development priorities focus on diversified economy to reduce the country's dependence on oil export revenues in an environment with increasingly limited resources. A robust corporate portfolio management framework is necessary for dealing with a combination of existing assets undergoing operations and new opportunities that shall mature to become projects or programs related to tertiary recovery (EOR), production optimization (IOR) and development of non-conventional assets, all of which have higher uncertainties, risks and total cost per barrel. KOC 2040 vision identified four strategic dimensions that focus on delivering an efficient corporate portfolio: processes, operating model, organization structure and capabilities. The corporate portfolio management will have to deliver the maximum value prioritizing the opportunities, considering internal constraints on capabilities and resources, standardizing governance processes and then maturation of selected opportunities with sufficient subsurface definition (Front End Loading), for business capital investment decisions. The portfolio management will be assisted by unified models in economics, risks, reserves, production and capital allocation. Achieving the efficient corporate portfolio will require the preparation of a Master Change Management Project which will address the four strategic dimensions. Implementing this master change management project in an NOC, will face resistance or hesitation because of a deeply rooted culture. This paper proposed a framework to implement corporate portfolio management in KOC that can accommodate the challenges and align the processes with incremental changes across the dimensions instead of disruptive changes. The proposed framework allows the combination of several strategic objectives with certain economic values to produce the efficient portfolio by: 1) adapting current processes to worldwide best practices for opportunity assessment, including improved reservoir management practices as a fundamental step to identification of optimal opportunities that add value in the corporate portfolio, and 2) application of capable software to reduce complexities to manageable levels. As there is not a general corporate portfolio management model that can be replicated across oil companies, this paper is a contribution to resolve the implementation dilemma in real-life business, particularly for NOCs.

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.

Kuwait is in the process of developing the deeper heavier oil reservoirs as part of Kuwait's national oil production strategy and KPC strategy 2040. This is in order to increase the oil production capacity for the next decade. The enhanced recovery of heavy oil assets needs a high level of expertise, optimum technologies and techniques, which are tailored to the distinctive challenges of the reservoirs and performed in a cost effective manner to optimize output and maximize economic benefits and rate of returns. Several wells are perforated in the zones of interest of the reservoir within the study area, which is currently under production using Progressing Cavity Pumps and is under natural production phase. The low productivity oil producers are completed in the Burgan reservoir. This reservoir is characterized by very high viscous crude oil around 15,000 cp, with a low gas-oil ratio (10-30) and with little or no primary drive mechanisms. The project requires overcoming certain challenges the following challenges are identified as the key challenges: Limited fluid mobility which is due to the high viscosity of the oil. Absence of drive support associated with the dissolved gas, the depth of the well, and the oil and its compositional gradient reservoir. Non-thermal well completion of the well, and the perforation design policy that was implemented. Lack of fluid/rock characterization and being in an oil-wet system. In the design of this project, the suggested method to be used is a non-thermal optimization process "chemical treatment ". The chemical treatment will be implemented as the chosen technology for a well that ceased producing in 2009. This method which has been applied globally and has also been proven to have less impact on the environment as per KOC HSE policy. The selected environmentally friendly method has three important mechanisms, which are as follows: Acts as a Wettability alteration agent. Acts as a Viscosity reducer agent. Acts as an Asphaltene inhibitor agent. KOC successfully conducted a pilot in 2016 and after the well was put back on to the production phase an increase of 300 bbl/day (net oil) was attained. The return of investment (ROI) of this pilot was a key economic calculation in answering the economic benefits of this procedure and in validating the project. As well showing the economic benefits of the projects value and its impact on the margin. The return of investment (ROI) was captured within day of production, with the total profit for the first 34 days was 438,885.52 USD.

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.

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.

A waterflood study has been performed on a high viscosity saturated oil deposit with bottom water aquifer and complex geometry driven by regional tectonic stress and numerous shale breaks. The commercial production is on-going for the last 2 years with medium length (1,000 m) horizontal wells and start facing formation pressure decline. The foremost challenge was to check if injection pressure is transmitted through the oil pay without leaking into the bottom water aquifer. The next question was whether the full net pay is engaged in pressure support under water injection. The last question was to check on permeability anisotropy. The transmissibility between wells have been assessed with multi-well retrospective testing (MRT) of permanent downhole gauges (PDG) historical data records which are a part of standard ESP telemetry. The fluid mobility and hydrodynamic average thickness between water injector and oil producers have been estimated with cross-well pulse-code pressure pulsations (PCT) based on pre-designed rate variation sequence [ 1 – 8 ]. The pulse-code sequence was designed in full-field 3D dynamic model to ensure capturing response in two contrast scenarios: with pressure propagating via aquifer and via oil pay, which have a high degree (30:1) of fluid mobility contrast. The data processing and interpretation was performed in PolyGon™ software [ 18 ] using the pulse-code decomposition for PCT tests and multi-well deconvolution for MRT tests. The cross-well mobility in injector-producer pairs from PCT was indicating that pressure was fairly propagating via oil pay. The effective thickness of PCT-scanned area turned to be in-line with net oil column thickness from 3D geological model. The MRT-scanned area was showing much lower transmissibility than 3D geological model prediction which was interpreted as the most part of the oil pay in this area has intermittent connectivity due to severe shale breaks development. This gives strong indication on searching the way to commingle production from isolated reservoir elements in this area [ 8 – 14 ]. The areal analysis of permeability in PCT-scanned and MRT-scanned areas has indication for 1:2 permeability anisotropy transversal to the regional stress direction which should be reconfirmed by a dedicated study.

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.

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.

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 operations More operational and hands-on training formats needed in the blended training frameworks Assessment processes , pre- and post-learning events, to measure the value of training Strategic career planning as a planning requisite for the optimization of training Soft 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.

Kuwait Oil Company (KOC) is operating two Heavy Oil fields. Field A aims at production by Cyclic Steam Stimulation (CSS), followed by steam flood. Field B envisages primary recovery through cold production, followed by non-thermal Enhanced Oil Recovery (EOR). This requires drilling and completion of large number of wells. Implementing Well, Reservoir and Facilities Management (WRFM) and Smart Field approach will be a key requirement for operation excellence in these fields. Currently both fields have some wells in production, mostly as single isolated wells or wells in 5-acre/ 10-acre spacing. These pilot projects aimed at de-risking the commercial phase, which is to follow in the coming years. These wells are the training ground for young KOC staff to learn how to work in integrated teams using WRFM processes. WRFM processes are tailor-made for KOC's operating environment. These processes include Digital Oil Field based on Exception Based Surveillance (to flag out only those wells and facilities outside of their operating envelope and/or optimization window) and Production System Optimization. This would help to eliminate operational bottlenecks, leading to optimization in manpower to deal with large number of wells. It is expected to be achieved by combining existing best practices of International Oil Companies (IOC) with existing KOC applications, leveraging successful global practices. The paper shall highlight the timeline, activities and organizational changes underway to effect the transformation from existing operation to a larger and more complex development that includes continuous drilling, completion and well intervention (CWI) and facilities installation occurring simultaneously. The implementation of WRFM Processes along with Digital field will achieve the production and operation goals by reducing well, artificial lift, and facility downtime. This innovative production optimization system by enabling efficient decision-making process shall lower the cost per bbl. and reduce down time by implementing automated surveillance workflow.

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.

A comprehensive numerical and analytical assessment of water coning in a heavy oil field in Northern Kuwait is presented in this study. Several wells were investigated in light of possible coning affect. Based on the lessons learned from the field data and modeling efforts, a coning envelope is generated and possible mitigation actions are explored. The complex geologic and stratigraphic architecture of the reservoir with underlying oil-water contact presents a unique challenge to achieve water-free oil production in this field. The field produces average 15 0 API crude of 50-100 cp at 100° F. Production data from wells from different structural locations were history-matched using numerical simulations on single well models (including type well models). Model runs were extended to estimate critical liquid rate to avoid coning. Additionally, critical rates assessed from several analytical models were compared against those from the numerical simulations. Critical liquid production rates for different areas of the field have been assessed based on the coning envelope generated. Further works showed that the critical rate is also a strong function of operational, reservoir and fluid parameters as well as completions standoff from current oil-water contact (OWC). Since the current oil API is very close to that of water, the critical rate is not a strong function of the density difference of the reservoir fluids, however, difference in the fluid viscosities displayed a some degree of impact on the coning rate. Operational results also showed that average of 15 ft standoff from the existing OWC is critical to avoid imminent coning. This presents an important opportunity for efficient completion decisions of a candidate well. The most significant new finding is that two analytical models evaluated during this study indicated that these models have limited capability to assess the critical rate from the heavy oil reservoir, and appear to have high degree of sensitivity to oil viscosity. This paper provides an integrated approach to assess and manage water cone in a heavy oil recovery project. Generated coning envelope provides a tool for a proactive strategy for rate management including opportunities for strategic well completion decisions. Another noteworthy assessment is that the existing analytical models have significantly limited capability to model water coning behavior in a heavy oil reservoir.

Wettability contact angle characterization will be investigated by 2D technologies and a deterministic model is developed. Deterministic approach is a robust technique using 2D image capturing and image analyses that are applied on a Kuwaiti silty sandstone reservoir to accurately quantify, mathematically as well as physically, wetting contact angle trends in the rock sample. And, then, generate all possible pore contact angles. Wettability contact angle quantification utilizes imaging method and recovery model with deterministic systems is a novel approach. Prediction of recovery schemes is crucial for reservoir development and management. Since contact angle initial state is captured and well described, measurement will no longer be random or follow stochastic solution. In this study, heavy oil recovery prediction model is also developed by constructing mathematical model based on statistical grouping and averaging for all measured pore-walls available in the rock sample. Pore parameters such as pore-area, pore-count, and pore-wall and pore shape distribution are all captured and measured experimentally and data can be accurately generated. Previously, contact angle is always based on linear assumptions and its direct quantification is vaguely established. In this study, quantifying wetting contact angle follows morphological approach that has greater confidence.

A heavy oil field in Northern part of Kuwait has developed which requires appropriate disposal of produced formation water. Some important questions for water disposal well planning include: Where to inject? Where to inject? What is the maximum operation pressure (MOP)? How far away the disposal wells should be spaced? How much water can be inject in each well? Integrated subsurface evaluation performed to address above questions. Seismic data provide a good overview lof the structuration and imporatant insight where sweet spots for injection may be found. Wireline logs and core information are used to derive petrophysical properties, characterize fracture, and gather geomechanical information. Injectivity tests established the injection rate and confirmed the estimated minimum horizontal stress. Analogue water injection data from nearby fields are used to provide information on the dynamic behavior of the reservoir, to reduce uncertainties owing to the limited injection rate data available. The integrated analysis of the relevant, available subsurface data reveals that the Tayarat formation has significant variations in lithologies, mineralogies, and mechanical properties. Important information such as the receiving zone thickness, fracture orientation, injection rate, and storage capacity have been derived. Based on this information, we have made important recomemndations on disposal well spacing and maximum operational operating pressure (MOP).

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.

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.