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Brown, Joel (Chevron) | Kumar, Raushan (Chevron) | Barge, David (Chevron) | Lolley, Chris (Chevron) | Lwin, Al (Chevron) | Al-Ghamdi, Saleh (Chevron) | Bartlema, Ruurd (Chevron) | Littlefield, Brian (Chevron)
Summary The 1st Eocene is a multibillion-barrel heavy-oil carbonate reservoir in Wafra field in the Partitioned Zone (PZ) between the Kingdom of Saudi Arabia and Kuwait. A large-scale steamflood pilot has been successfully completed in the 1st Eocene reservoir. The large-scale pilot (LSP) was the first multipattern steamflood in a carbonate reservoir in the Middle East, and consisted of sixteen 2.5-acre inverted 5-spot patterns with associated steamflood and production facilities. The primary objective of the LSP was to identify and mitigate technical and economic risks and uncertainties in carbonate steamflooding to assist in the broader Wafra full-field steamflood development (FFSFD) decisions. The key technical uncertainties related to the steamflooding in the 1st Eocene reservoir were identified, categorized, and prioritized. These were then used as a basis to create surveillance and subsurface response plans. Success measures were developed to assess success in steamflooding this carbonate reservoir. These success measures were derived from the key metrics that were prerequisites for the FFSFD. The pilot met all the success measures, thereby mitigating the key technical uncertainties, and opened the path to FFSFD. This paper describes the elements of pilot planning and the results achieved during pilot execution. The emphasis, specifically, is on the achievements against the success measures set for the project; the insights into the pilot behavior from detailed analysis of production, pressure, and temperature data; and the progress made in identifying and mitigating key uncertainties in carbonate steamflooding.
Abstract Steamflooding technology introduction into hydrocarbon recovery operations often brings with it unwanted unavoidable mineral scaling challenges. In this example, steamflood generated calcium carbonate scale caused downhole equipment failure during cyclical steamflood stimulation (CSS) operations. The precipitated scale was effectively removed via mineral acid tubing wash, however mineral acid use for ad-hoc scale dissolving duty added significantly to the corrosion burden of well production tubing strings already regularly exposed to aggressive high concentration mineral acid during near wellbore matrix stimulation treatments. Scale inhibitor squeezing was proposed as a proactive alternative to mineral acid for downhole scale mitigation, and is the subject of this case history. The Middle Eastern heavy oil (HO) field has experience in employing scale inhibitors for topside scale control, but has limited experience in scale squeezing, and no experience of scale squeezing cyclical steam flooded wells. The initiative therefore presented some interesting challenges with respect to the Scale inhibitor selection (thermal stability concerns, compatibility and calcium carbonate efficacy concerns), where to place the scale squeeze in the CSS treatment programme, the squeeze design and its placement within the CSS well, and introduction and execution of routine well scaling health monitors for assessing the performance of the scale squeeze across the full CSS life-cycle. Detailed bullheaded scale squeeze designs were prepared for two pilot HO field CSS wells that had experienced CaCO3 scaling. Once prepared, the squeeze treatments were quickly scheduled and executed without significant issue - either during treatment application or post-squeeze/steamflood return. The well brine monitors (brine ion composition, residual scale inhibitor and suspended solids) revealed interesting trends during the surveillance phase, but most importantly showed that the scale squeezes performed according to design and successfully maintained the wells free of CaCO3 scale, up to and including the 266 days post-steamflood, at which point routine well produced water sampling was discontinued. After 360 days (at the final review meeting) the field operators advised that both squeezed wells were still in operation and had experienced no scaling downtime.
Ross, T. S. (New Mexico Institute of Mining & Technology) | Rahnema, H.. (New Mexico Institute of Mining & Technology) | Nwachukwu, C.. (New Mexico Institute of Mining & Technology) | Alebiosu, O.. (ConocoPhillips Co) | Shabani, B.. (Oklahoma State University)
Abstract Steam injection—a thermal-based enhanced oil recovery (EOR) process—is used to improve fluid mobility within a reservoir, and it is well known that it yields positive results in heavy-oil reservoirs. In theory, steam injection has the potential of being applied in light-oil reservoirs to enable vaporization of in-situ reservoir fluids, but field developments and scientific studies of this application are sparse. Conventional displacement methods like water-flooding and gas-flooding have been applied to some extent, however, oil extraction in such reservoirs relies on recovery mechanisms like capillary imbibition or gravity drainage to recover oil from the reservoir matrix. Furthermore, low-permeability reservoir rocks are associated with low gravity drainage and high residual oil saturation. The objective of this study is to evaluate the potential of steam injection for light (47°API) oil extraction in naturally-fractured reservoirs. It is theorized that this method will serve as an effective tool for recovery of light hydrocarbons through naturally-fractured networks with the benefit of heat conduction through the rock matrix. This research investigates the application of light-oil steamflood (LOSF) in naturally- fractured reservoirs (NFR). A simulation model comprised of a matrix block surrounded by fracture network was used to study oil recovery potential under steam injection. To simulate gravity drainage, steam was injected through a horizontal well completed in the upper section of the fracture network, while the production well was completed at the bottom of the fracture network. The simulation included two different porous media: (1) natural fractures and (2) matrix blocks. Each of these porous media was assumed to be homogeneous and characterized based on typical reservoir properties for carbonate formations. This study also analyzed the impact of different recovery mechanisms during steam injection for a light-oil sample in NFR, with reservoir sensitivity examined, based on varying amounts of vaporization, injection rate, permeability, matrix height and capillary pressure. Of these, vaporization was found to be the dominant factor in the application of LOSF in NFR, as described in detail within the results.
Al-Bazzaz, Waleed (Kuwait Institute for Scientific Research) | Kamel, Abdulrahim (Kuwait Institute for Scientific Research) | Talal, Abbas (Kuwait Institute for Scientific Research) | Buresli, Khalifa (Kuwait Institute for Scientific Research)
Eocene-Wafra is a heavy oil reservoir that is producing 17-21 ̊API oil. This carbonate-dolomite reservoir has substantial amounts of heavy oil and has low primary recovery of 3%, which is a candidate for steam recovery. However, current high quality steam recovery campaign is facing serious technical challenges such as expensive cost of production, inefficient recovery yield, and limited supply of fresh water for the injection, which make other unconventional recovery plans more attractive to increase the recovery. This study will address a dry heat recovery mechanism of a synthetic reservoir media with real Eocene dead oil samples. The main objective of this study is finding the optimum recovery rate using dry heat instead of expensive, inefficient and limited supply water of conventional steam recovery. Another objective is to predict the heavy oil recovery at several temperatures based on its viscosity reduction. In addition, Study the effect of copper and iron heating elements on the oil recovery. And finally, study the effect of progressive elevated temperature on oil quality recovered, such as density and composition.
Twenty reservoir sample experiments are dry-heated in order oil and water is extracted simultaneously. The fractionated liquids are collected in volumetrically calibrated glasswares. The unconventional dry-heat method subjects the reservoir to zero water injection. Several designed conventional temperatures are as follows: 25 ̊C, Reservoir temperature, 100 ̊C, early steam condition, 200 ̊C, super saturated steam, and 300 ̊C, industrial steam limit. There are also several dependent recovery variables such as, type of metal rods, metal rods diameter, recovery time, and density upgrading, investigated in terms of quantity and quality.
The optimum recovery yield is encouraging with up-to 70% based on repeated experimental physical attempts. In addition, conclusions of recovery profiles were confirmed preference of copper recovery efficiency in regards to time, temperature and quality of crude.
Zhang, Fangfu (Rice University) | Hinrichsen, Charles J. (Chevron) | Kan, Amy T. (Rice University) | Wang, Wei (Chevron) | Wei, Wei (Chevron) | Dai, Zhaoyi (Rice University) | Yan, Fei (Rice University) | Liu, Ya (Rice University) | Bhandari, Narayan (Rice University) | Zhang, Zhang (Rice University) | Ruan, Gedeng (Rice University) | Tomson, Mason B. (Rice University)
Summary Steamflooding is a widely used technique for heavy-oil recovery. Scale control during steamflooding, however, can be challenging because the high temperature of the steamflood can decompose thermally unstable inhibitors and/or lead to the precipitation of metal-inhibitor pseudoscale. In this paper, we present the analysis of the scaling risk and scale inhibition for a pilot steamflood project in a Middle Eastern oil field. The formation of this field is a dolomite formation interbedded with anhydrite (CaSO4) streaks. Anhydrite has been observed to be the predominant scale form. Anhydrite scale was presumably formed by the increased production-system temperature resulting from steamflooding and/or the mixing of steam condensate with connate water at equilibrium with calcium sulfate minerals at lower temperature and higher solubility. Anhydrite is inherently difficult to control because of its high solubility and the high-temperature (HT) conditions under which it forms. Compared with barite and calcite, only limited knowledge has been acquired for anhydrite control. To predict the scaling tendency and inhibitor need in different wells of this field with different supersaturation levels and temperatures, a scaling-risk model has been developed. To build such a model, detailed and revised laboratory procedures have been developed to study nucleation and precipitation kinetics of anhydrite at 125–175°C, different supersaturation, different water composition, and long reaction time. Predictions of this scaling-risk model suggest a saturation index (SI) of 0.8 as a critical SI for anhydrite control at >125°C. For example, when the SI is above 0.8, anhydrite will be difficult to control in the presence of threshold inhibitor. Model predictions were benchmarked with the water-chemistry data from a total of more than 20 wells from this field, and were found to be consistent with field observations of scale occurrence in different wells. With the recommended inhibitor concentrations, anhydrite scale has been controlled in this field, which provides validation that the proposed scaling-risk model is a powerful tool to optimize the scale-treatment plan for anhydrite.
Abstract Steam injection (including cyclic steam and SAGD) has long been recognized as the favored recovery method for heavy oil, with applications in many fields around the world in particular in California and Canada. More recently, polymer flooding has also become a relatively well accepted method to increase production and recovery in heavy oil fields. Numerous successful pilots have been reported these last few years and field expansions are currently ongoing in Canada, Oman, China and Albania for instance but surprisingly enough, there has been to the best of the author's knowledge no such application in the US. Both steam and polymer injection have their advantages and their limitations and simple screening criteria have been developed by several authors, however there has never been a detailed comparison of the two methods and this is what this paper proposes to do. The pros and cons of both steam injection and polymer flood are reviewed in light of fundamentals and field experience: reservoir depth, thickness, oil viscosity, expected recovery, water usage and economics of both processes (in particular capital requirements) are all addressed. Guidelines are then provided for the selection of the right process given the reservoir conditions and the capital constraints. Results show that while steam injection can achieve much higher recovery than polymer flood and is also applicable in much higher oil viscosity, polymer flooding is not limited by depth or reservoir thickness, has lower operating costs and is also less capital intensive. Thus, there is a large opportunity to develop heavy oil reservoirs using polymer where steam injection is not possible. Delamaide and Euzen (Delamaide & Euzen, 2014) estimated that in the US alone, over 5 billion bbl of oil could be targeted by this technique. This paper will provide guidance to engineers who need to select the optimum Enhanced Oil Recovery method to apply in given heavy oil fields, going beyond the standard screening criteria. It will also increase awareness on the possibilities of polymer flooding in some reservoirs, with a significant potential target not only in the US but also worldwide.
Abstract This paper describes an HSE integrated risk assessment performed by a multidisciplinary team for a Steamflood pilot program in a shallow geologically complex multi layered super-giant heavy oil green field in Kuwait, undergoing first phase of development using field tested Cyclic Steam Stimulation (CSS) during first few years then followed by Steamflood (SF). In the first step of HSE integrated risk assessment methodology, the team stablished the most likely production scenarios during CSS and SF for selected well pattern types and sizes, components of surface infrastructure and production operation modes. To determine the safe distance between wells during drilling operations under current conditions, the team performed a consequence analysis. For each scenario the team defined ranges (minimum and maximum) for well production and injection rates, fluid composition, wellhead temperature, gas oil ratios and other key parameters using data and information from reservoir model, pilots and well designs. To account for the lack of data typical in a green field, the team reviewed well blowout failure modes and frequencies from analog heavy oil fields worldwide. Through internal workshops and using data from analogs, the team did the identification, classification, analysis and ranking of hazards and risks, ending up with a risk breakdown structure (RBS) and a risk assessment matrix (RAM). To identify root causes and their mitigation actions the team prepared cause and effect relationships maps and loss causation models for those risks related to HSE. The outcomes of the assessment are a risk register, quantitative risk assessment, detailed reports and guidelines for the Steamflood pilot program as support to prepare HSE procedures. The team identified 66 risks; classified and ranked them using a risk breakdown structure (RBS) and a risk assessment matrix (RAM) and then selected 28 risks with cause and effect relationships with HSE. The cause and effect relationships maps helped defining the 7 most significant groups of risks (likelihood and impact) in the short, medium and long term: 1) Well blowouts, 2) H2S & CO2, 3) Pattern Type & Size, 4) Heat Management, 5) Non Wanted Fluids & Solids, 6) Reservoir Description and 7) Human Factors. By using loss causation models for each of the seven group of risks, the team established the root causes and risk mitigation options. From the consequence analysis, the conclusion was that 45 meters is the minimum safe distance required between heavy oil wells considering three event scenarios of potential failure cases and the consequences. Finally, to account for the need of critical data related to the most critical HSE risks, the team visualized a Steamflood field test using a small pattern area to reach quickly steam breakthrough and gather a minimum of the needed data in less than 1 year. The HSE integrated risk asssessment methodology presented in this paper is applicable to similar heavy oil green fields to identify potential failure modes associated with well blowouts and other hazards during all phases of thermal operations using data from the subject field or from analogs.
Abstract Saudi Arabian Chevron (SAC) is continuously investing in human resource development and technology as an integral part of its business operations. Newly hired graduates go through a variety of training and performance management programs to enable them to be globally competitive members of the Chevron workforce. A comprehensive and structured manpower development program called “Horizons” is implemented within Chevron to accelerate the development of new graduate hires. A key enabler for delivering on SACs graduate development commitments is through its newly inaugurated Technology Center. The Technology Center is acting as the center of excellence for manpower development and technology transfer to SAC. The Horizons program consists of three key elements; a) technical training; b) rotating job assignments; and c) mentoring. Technical training, with a mix of both cross-functional and discipline specific topics, is designed to improve competencies of new graduates. Rotating job assignments allow participants to gain practical experience and petrotechnical skills by becoming involved in a variety of hands-on projects. The mentoring program assigns each young employee with a senior technical professional to enhance competency through knowledge sharing and to guide the career planning and development process. The SAC Technology Center provides technical support to the assets through various projects, including technology deployment, static and dynamic modeling, reservoir management and drilling and completions technology. A key objective in all of the Technology Center projects is to provide opportunities for the young national talent to learn through enganement in ongoing projects. This paper highlights key components of the accelerated development program and technology transfer process implemented in Saudi Arabian Chevron by the Technology Center. With a structured and focused approach to the development of national talent, SAC feels it will be able to achieve effective and reliable transfer of the Chevron corporate culture and knowledge to meet the future human resource needs of the Company.
Abstract The recovery of 1,600,000 cp bitumen from very heterogeneous carbonate reservoirs in the Grosmont unit in Albert is a great challenge. Steam injection alone may not be efficient due to the heterogeneous nature of the reservoir caused by natural fractures at different scales. Recent cold solvent studies showed limited recovery because of low diffusion coefficient and by-passing matrix oil. The hybrid use of steam and solvent could be an option to overcome some of these challenges. We adapted the previously introduced SOS-FR (Steam-Over-Solvent Injection in Fractured Reservoirs) method and conducted twelve experiments using preserved core samples from the Grosmont formation. The temperature used can be qualified as hot water injection thereby reducing the cost of heating the reservoir. The method applied in this study is based on soaking rather than continuous injection. The samples were immersed in hot water (90 °C) first to mimic low temperature pre-steaming to condition the reservoir for solvent injection. This was followed by a solvent soaking period under varying conditions (duration, solvent type, etc.). Heptane and the distillate obtained from a heavy oil upgrading facility were used as solvents. Finally, the core samples were soaked in hot water again. Oil recoveries varied between 40% and 90% OOIP with a mean value of 68%. Asphaltene precipitation as a percentage of OOIP was measured between 6.5wt% and 33wt%. The oil recovery and asphaltene precipitation depended on the solvent type, the solvent exposure duration, the position of matrix rock (horizontal or vertical), and the duration and number of solvent/hot water cycles. Most importantly, the last phase (hot water immersion) yielded substantial recovery of solvent diffused into matrix oil by applying a temperature value close to the boiling point of the solvent. The solvent retrieval was extremely fast and varied between 62% and 82% of the solvent diffused into the core during solvent exposure. Experimental observations look promising for further applications as indicated by the high recovery values. The important aspects are that the solvent from readily available distillates used for transportation of heavy oil are very responsive and the temperature requirement for final hot water injection applied to retrieve solvent was less than 100 °C. Solvent retrieval was extremely quick and reasonably high which is more likely to make the process economic.
Summary The First-Eocene heavy-oil reservoir (1E) in the Wafra field is a candidate for steamflooding because of its world-class resource base and low-estimated primary recovery. However, industry has little experience in steamflooding carbonate reservoirs, which has prompted the staging of several 1E steamflooding tests, the latest of which is the large-scale pilot (LSP) started in 2009. To assist in facilities design, to help understand expected performance in a very heterogeneous reservoir, and to provide input to early-decision analyses, numerical thermal simulation was used to generate probabilistic forecasts. When adequate pilot history was available, the model was validated with probabilistic methods. The LSP model contained 1.5 million cells, which allowed the maintenance of adequate resolution and proper boundary conditions in the pilot area. Parallel computation enabled a probabilistic workflow to be implemented with this large thermal model. In this paper, we highlight the methodologies and inputs used to generate the probabilistic forecasts and validate the model. Major results of this work include the following: In contrast to many greenfield forecasts, the LSP forecasts were conservative, likely because of the unique aspects of the forecasting methodology, proper selection of uncertainty ranges, and the relatively high density of input data for model construction; wide variations in production metrics were forecast, indicative of a highly heterogeneous reservoir; results indicated that the validated model adequately captured the global or statistical pilot heterogeneity, enabling proper capture of steamflood flow/drainage mechanisms; and despite this heterogeneity, forecast oil-recovery levels were comparable with those observed in steamfloods in sandstone reservoirs.