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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.
Qu, Shiyuan (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum) | Jiang, Hanqiao (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum) | Li, Junjian (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum) | Hu, Jinchuan (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum) | Sun, Fengrui (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum) | Qiao, Yan (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum) | Dong, Mingda (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum) | Chen, Wenbin (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum) | Zhou, Yu (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum)
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.
Saikia, Pabitra (Kuwait Oil Company) | Al-Rashdan, Saad (Kuwait Oil Company) | Taqi, Fatma (Kuwait Oil Company) | Al-Dohaiem, Khalid (Kuwait Oil Company) | Al-Rabah, Abdullah (Kuwait Oil Company) | Tyagi, Aditya (Kuwait Oil Company) | Choudhary, Pradeep (Kuwait Oil Company) | Ahmad, Khalid (Kuwait Oil Company) | Kharghoria, Arun (Kuwait Oil Company) | Malik, Satinder (Shell Kuwait Exploration and Production B.V.) | Zhang, Ian (Shell Kuwait Exploration and Production B.V.) | Cheers, Mike (Shell Kuwait Exploration and Production B.V.)
Free gas along with heavy oil production affects the progressive cavity pump (PCP) performance. This necessitates the strategy to perforate away from the free gas zone. To be able to do this, it requires an integrated approach to evaluate and map the spread of the free gas accumulation in the field. The paper shall present how this resulted in improved well performance with less free gas interference.
The methodology included the understanding of the production data, sub-surface geology and petrophysics; reservoir heterogeneity and free gas presence from wireline logs, core data and isotope analysis of gas collected during mud-logging and creation of maps and cross-sections showing both vertical and aerial spread of free gas accumulation. This was then integrated with existing production and well management practices, along with numerical simulation results. Such in-depth analysis helps to bring significant changes in well completion strategy and is a vital contribution to the WRFM strategy.
Unlike in conventional fields where depth is more and buoyancy pressures are large, gas can easily displace oil to accumulate in structural highs, in shallow heavy oil fields, free gas accumulation is a result of combination of structural and stratigraphic entrapment process. Vertical migration and lateral migration of gas is likely restricted by non-reservoir facies. As a result a consistent gas-oil contact (GOC) may not be present across large distances. Gas oil contact separates heavy oil by possible structural spill point and lithological boundary, dipping from south to north. Structurally higher areas are prone to localized gas accumulation. The completion stand-off from the gas base has a direct correlation with gas production. So the well management and production practice is to increase the stand-off from gas base to top perforations in future wells and to perform gas shut-off job in current wells to avoid free gas production.
The novelty of the current approach is that it will proactively help in completion strategy to reduce future free gas production, subsequent loss in natural reservoir energy and maintain the oil production target.
The cost per barrel is higher for Heavy Oil developments, and particularly thermal developments than for Conventional. Specific attention needs to be paid to the cost of Heavy Oil developments to ensure economic viability. The current cost basis for the heavy oil project shows that energy costs constitute some 45% of Unit Technical Cost and more than 65% of the OPEX per barrel. An OPEX cost improvement plan has been conceptualized to reduce the cost per barrel. Hence, the improvement plan focusses on Alternative Energy sources for steam generation.
In addition to the cost optimization, those initiatives will contribute heavily in achieving HH the Emir of Kuwait vision to cover 15% of Kuwait’s peak load with renewable energy by 2030". Based on current field development plans a feasibility study was carried out to determine the maximum practical and economic fraction of energy that can be contributed by renewables in heavy oil development. The bulk of the work was executed developing a model to study the supply-demand balance, as well as the gas prices ranges within the alternative energy solutions are viable.
To optimize the fuel gas consumptions two options were studied by utilizing the alternative energy solutions (solar steam and cogenerations) to generate steam instead of conventional boilers. On the power optimization side the study focused on the solar photovoltaic and wind energy. The lowest cost solution is to use direct solar steam and allow the steam injection at a variable rate - this may require some upgrades to allow fully- automatic flow control throughout the steam distribution system. With this method (and a typical weather year) solar fractions of approximately up to 40% may be possible. It may be possible to increase this further if the requirements for minimum steam flow in the steam distribution network can be reduced. With the use of thermal storage, the solar fraction can be increased to approximately 60-80%, however steam from storage is likely to cost significantly more than direct steam, especially as direct molten-salt coupled with oilfield- quality water has not yet been proven commercially.
As renewable power alone will not be able to meet the full demand of Heavy Oil field development, hence the utilization of cogeneration will be a feasible solution in order to supply the required steam demands in addition to solar and also to supply the required power in addition to solar PV. The redundant power generated by the cogeneration may be supplied to the Electrical Grid. The economics analysis illustrates that all renewable options considered have positive NPV. The economics for both PV and wind are robust, where maximum deployment is advised, subject to grid connection constraints. For solar steam, the economics are partially affected by the once-through steam generators (OTSG) CAPEX already spent, but still show positive NPV. Anticipated costs reductions for solar steam technology as a consequence of greater deployment of the technology over the next few years could further improve the NPV. Including the cogeneration, solar steam and less conventional steam generators in the future projects will maximize the NPV of the heavy oil.
This paper reviews the fluid contact analysis of the Marmul Gharif South Rim (MM GSR) heavy oil field in the South of the Sultanate of Oman. The field is highly compartmentalized by several faults into 17 blocks in total with a large variation in well density within those blocks. The reservoir in this field is the shaly-sand Gharif formation, in which the Middle and Lower Gharif are separated from each other by either a paleosol or competent shale. The hydrocarbon in these sands has an observed viscosity variation as a function of height above free water level (HAFWL) due to biodegradation. This variable viscosity has been observed in a large number of oil samples with higher viscosity close to the oil-water contact (OWC). The sands tend to be vertically discontinuous in the wells, so that direct observation of the OWC on logs is very rare, causing most well logs to yield only water up to (WUT) or oil down to (ODT). Accurate pressure gradients are difficult to obtain due to the low density contrast of heavy oil against the fresh formation water. Consequently, the OWC is not readily identified in certain blocks. This has resulted in either over-estimating oil volumes when substituting WUT or under-estimating volumes when substituting ODT in specific blocks of the field. In addition these cases also result in a lack of reliable constraints for estimating high and low case oil contacts.
A viscosity based approach was used to overcome gaps in the fluid contacts data-set and provide essential information for future field development. The approach utilizes the viscosity data in each block to determine representative base case contact along with shallow and deep cases. The results of this analysis were confirmed by production data and are consistant with the ODTs from horizontal wells.
The resulting fluid contact is then used as an input to the saturation height function which is used later as an input to calculate in-place volumes.
Viscosity based contact provides a more robust fluid contact definition in areas where traditional methods resulted in data gaps. The paper presents a detailed methodology of this approach.
The results of this work are an essential component of optimizing the understanding of the fluid contact in the field, which helps to develop the field efficiently by drilling the oil producers and water injectors in more optimum locations.
The uneven distribution of the production influx from the reservoir into the wellbore has been identified as the main issue in the management of production in heavy oil wells. This occurs due to a drastic difference between the mobility of oil and water i.e. water flows faster than oil in these reservoirs. This can be exacerbated by reservoir heterogeneities resulting in very high water production rate requiring large water treatment facilities which may be limited in offshore developments, resulting in reduced oil production.
Advanced well completions utilizing Inflow Control Devices (ICDs) and Autonomous Inflow Control Devices (AICDs) have proven to be robust solutions for these problems. Both devices help to enhance the performance of heavy oil wells by delaying the water production, however, AICDs are more capable to reduce the water production and increase oil production even after water breakthrough.
This paper examines the heavy oil/water production control by ICDs and AICDs and discusses the flow loop test data (single and multiphase flow) to describe the performance of devices for various fluids under downhole conditions. Using an example model, the reasons for the superiority of AICD over ICDs is investigated under different scenarios. An optimisation workflow was used to optimise the well completion design i.e. the size and number of devices plus packer placements and numbers.
The results of several field applications of AICDs, from retrofitting the existing completions of the wells with very high water cuts (e.g. 98%) to brand new wells in heavy oil fields, will be discussed. AICD completion as a proactive-reactive device was found to be the most efficient completion at controlling the water production from high productive zones or the fractures, compared to the wells equipped with ICDs and other conventional completions while increasing oil production.
This paper provides insights about inflow control device applications in heavy oil wells and provides a comprehensive guideline on the selection of appropriate completions for the wells in these challenging reservoirs.
Choudhary, Pradeep (Kuwait Oil Company) | Freeman, Mike (Kuwait Oil Company) | Al-Boloushi, Ahmed (Kuwait Oil Company) | Benham, Philip (Shell Kuwait Exploration and Production B.V) | Sakia, Pabitra (Kuwait Oil Company) | Tyagi, Aditya (Kuwait Oil Company) | Ahmad, Khalid (Kuwait Oil Company) | Jha, Madan (Kuwait Oil Company) | Zhang, Ian (Shell Kuwait Exploration and Production B.V) | Warlich, Georg (Shell Kuwait Exploration and Production B.V) | Al-Rabah, Abdullah (Kuwait Oil Company)
The shallow depth unconventional reservoir in Northern Kuwait is essentially a monoclinal structure. Sediments have undergone significant shallow depth diagenesis, which resulted in selective oil/water accumulation, controlled mainly by lithological variations. Thus, the reservoir can be classified as stratigraphic-dominant trap. A correlation approach required addressing these variations, which can also be well understood by non-geologist, and the scheme should be appropriate for selection of perforation intervals.
Reservoir sands are in the form of multi-stacked distributary/fluvial channels. Subsequent to sediment deposition, moderate to intense diagenesis took place. The diagenesis resulted in formation of cemented baffles under low reservoir pressure (250psi) regime. For demarcation of bed boundaries, mapping and modelling purpose the reservoir sand, shale, baffles, gas, water, water above oil, this petrofacies classification method is proposed. The method is well capable of defining the various bed boundaries with fluid/gas content in it with confidence. The method developed after extensive core, core data and log calibration and study. More than one thousand wells correlated.
The classification method is simple, yet robust to characterise reservoir vs. non-reservoir variations and oil/gas vs. water quite effectively. Cementation activities typically noticed on top/bottom of the units but many times in between the reservoir sand also. We are able to correlate cemented layers across the area. The cementation also gives rise to water perched above oil phenomenon due to relatively higher capillary pressure in the zone. Oil is migrated post-cementation and occupied reachable pore spaces. Oil also has undergone significant biodegradation because of favourable temperature and restricted nutrient supply. As a result, thin layers of thermal/biodegraded gas also formed locally. The method allows for surface related categorisation representing clean sand, cemented sand, shale, gas/oil/trapped water zones.
This unconventional reservoir is being developed with thermal application. Thickness of baffles, barrier, gas, water zones are critical in selection of perforation interval for steam application. This classification method is part of perforation selection for first phase of development and modelling purpose, and it was applied to hundreds of wells, many of them are undergoing production operations successfully.
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 highquality 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.
Taqi, Fatma (Kuwait oil company) | Ahmed, Khalid (Kuwait oil company) | Saika, Pabitra (Kuwait oil company) | Tyagi, Aditya (Kuwait oil company) | Freeman, Michael (Kuwait oil company) | Ren, Zubiao (Kuwait oil company) | Zhang, Ian (Shell) | Muhammad, Diri (Shell) | Warrlich, Georg (Shell) | Al-Rabah, Abdullah (Kuwait oil company)
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?
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 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.