For thermal in-situ oil sands production, it is conventional to think that an emulsion pipeline remains essentially oil-wet. Ideally, an oil coating distributed on the pipe by the produced water-in-oil emulsion from a well pad is expected to give the needed corrosion protection for the operating life of the pipeline. Practically however, there are conditions under which this ideal scenario becomes no longer feasible, even for low API gravity heavy oil. These parameters affecting protection include but are not limited to water cut, well pad processing, steam cycle phenomena, reservoir characteristics, pipeline operating temperature, partitioning characteristics of the acid gases and their effects on water chemistry and passivation as well as other field operational practices.
From the experience of two case histories at a thermal in-situ oil sands project, this paper elaborates on many of the field parameters and how they influence the integrity of pipeline infrastructure by studying the various corrosion phenomena at play. Corrosion mitigation recommendations for these pipelines will also be presented.
Consideration of corrosion mechanisms in thermal oil recovery facilities should be divided into two categories, conditions with and without microorganisms present; the former is called microbiologically influenced corrosion (MIC). Constant monitoring of these facilities for MIC and controlling them when present is essential to corrosion management. If corrosive microorganisms are present in significant amounts, the probability of failure is high despite the presence of other corrosion mitigating factors including assumptions about oil-wetting, passive scale formation or the efficacy of a chemical inhibition program. This paper deals with non-microbiological corrosion issues and considers the following factors in the context of thermal oil production:
Wu, Yi (E&P Research Institute of Liaohe Oilfield Company, CNPC) | Wang, Zhongyuan (E&P Research Institute of Liaohe Oilfield Company, CNPC) | Han, Bing (E&P Research Institute of Liaohe Oilfield Company, CNPC) | Li, Xiaoman (E&P Research Institute of Liaohe Oilfield Company, CNPC) | Zhou, Guangxing (E&P Research Institute of Liaohe Oilfield Company, CNPC) | Wang, Ziji (E&P Research Institute of Liaohe Oilfield Company, CNPC)
Steam Assisted Gravity Drainage (SAGD) is a widely used thermal recovery method for heavy oil and bitumen. S-13832 reservoir in Liaohe oil field in China is reaching economical limit after several cycles of cyclic steam stimulation (CSS). To improve the recovery, toe-to-heel air injection (THAI) had been field tested, however with unfavorable results. In this study, we analyze the alternative SAGD process and show it as most promising follow-up for CSS in S1-3832 reservoir.
We first conduct comprehensive summary of reasons for the previous THAI trial failure, including lack of knowledge for shale layer distributions, difficulties in control spreading of combustion front and blockage of wellbore. Then, numerical simulation has been performed to investigate the feasibility and advantage of using SAGD process in S1-3832. A fine-grid reservoir model with shale layers carefully characterized for reservoir heterogeneity and oil-water distributions modeled. Finally, history match of the field is carried out and dominant influencing factors for SAGD recovery were determined in order to establish an optimum reservoir development strategy.
Vertical injector-horizontal producer and vertical injector-vertical producer hybrid well configuration is adopted in the type pattern simulation model. Key parameters such as perforation locations, steam quality, production-injection ratio, injection rate and SAGD transition time are optimized. It is observed that steam chamber shape is irregular due to the presence of shale layers in some locations. Based on shale layer characteristics of the reservoir, perforation positions together with injection and production rates are adjusted to improve the conformance in these areas. According to these findings, a practical development strategy is designed. Ultimately, the simulation results show the production rate, accumulative oil-steam ratio and other indicators satisfy the requirement of economic development, with incremental recovery factor of 39%in the SAGD stage.
The optimum development plan has been successfully implemented for more than 1 year now, with monitored temperature showing steam chamber growth in favorable manner in the entire reservoir, even in area above shale barriers. With thermal communication achieved, production rate increases progressively, indicating a smooth transition to SAGD mode. This work has demonstrated SAGD as effective recovery process in S1-3832. It also provides technical guidance for designing follow-up processes to CSS for similar reservoirs.
Steam-assisted-gravity-drainage (SAGD) processes become effective only after thermal and hydraulic communication between an injection and production well has been established during the startup operation of the well pair. Conventional steam-circulation startup operations typically take 2 to 3 months to achieve interwell communication, but reductions in the startup time can have a favorable impact on project economics. Enhancement of interwell permeability using fluid-injection (water, or steam, or solvent) strategies to promote geomechanical dilation of the oil sands has been proposed as a startup technique. These fluid-injection processes will produce complex interactions of thermal, geomechanical, and multiple-phase flow behavior in the interwell formation region. Understanding better the role that these interactions play in establishing well-pair communication will provide opportunities to improve SAGD recovery performance.
A triaxial experimental program has been designed and executed to explore whether cold-water injection would be sufficient to induce enhancements in effective permeability to water from geomechanical dilation mechanisms. Sample preparation techniques were modified to allow the preparation of reconstituted, very dense water-wet/bitumen sand specimens with different fluid saturations and almost identical porosities. Reclaimed/cleaned tailings sand from oil-sands mining operations was used to prepare artificial specimens, which are representative of McMurray Formation oil sands. A water-wet or bitumen sand core plug was then tested in an environmental chamber to simulate reservoir boundary conditions in terms of stress state, temperature, and pore pressure. A set of experiments was carried out in a triaxial cell under either initial isotropic or initial anisotropic stress state. Experimental results highlight the promising potential to dramatically enhance effective permeability to water and porosity in the dilated zone using cold-water injection at modest levels of stress anisotropy. The experimental results also provide support for the development of numerical models used in predicting SAGD startup performance and proactive utilization of the dilation as startup process for in-situ oil-sands development.
Thermal recovery methods, in particular technology based on steam injection, are used extensively around the world for heavy oil and bitumen production. Because of the unconsolidated nature of the majority of such deposits, sand control is required. Design effectiveness of sand control depends on the reservoir type, production technology and operational practices. The industry is facing many challenges such as low oil prices, tight environmental regulations, the need to lower risks while assuring well integrity and longevity and project economics. All of that requires special technical solutions for thermal well design, including sand control.
The paper provides an overview of sand control for thermal heavy oil and bitumen production operations, factors affecting sand control design for thermal projects, sand control devices and industry trends. Laboratory observations and field data are discussed. The impact of steam on different quality heavy oil and bitumen deposits in relation to sand control is discussed in detail. Efficient sand control design for thermal production operations requires a multidisciplinary approach and is an integral part of the well longevity and project economics. Better understanding of the impact of reservoir quality, thermal formation damage and operational practices on well performance is required to assure success of a thermal project.
Experimental data have shown that the solubility of water in the oleic (L) phase (xwL) can be significant at elevated temperatures. However, xwL was not properly considered in prior studies of steam-assisted gravity drainage (SAGD) and expanding-solvent (ES)-SAGD. The main objective of this research is to present a detailed study of compositional mechanisms in SAGD and ES-SAGD simulation by considering xwL.
The phase-behavior models used in this research are carefully created on the basis of experimental studies presented in the literature. Mechanistic simulation studies are then conducted for SAGD and ES-SAGD. Coinjectants used in ES-SAGD simulations range from propane through n-decane.
Results show that xwL enhances bitumen production in both SAGD and ES-SAGD, mainly because xwL results in reduction of L-phase viscosity. The enhancement is more significant when the chamber-edge temperature is higher, because xwL increases with temperature. The enhancement of bitumen production observed in the case studies is 7.66% for SAGD, 4.08% for n-C6-SAGD, and 4.85% for n-C8-SAGD for a fixed period of operation at 35 bar. It is important to consider xwL in SAGD and ES-SAGD simulations, because the performance of ES-SAGD relative to SAGD tends to be overestimated without considering xwL.
A guideline is presented to leverage xwL to improve bitumen production in ES-SAGD. As discussed in our prior research, solvent becomes effective in diluting bitumen and reducing the steam requirement only when it sufficiently accumulates near the chamber edge. New results show that water can act as a diluting agent until solvent sufficiently accumulates near the chamber edge.
Extraheavy-oil (XHO) reservoirs in South America represent some of the largest hydrocarbon accumulations (>500 billion bbl) in the world. Primary production (PP) that uses long horizontal wells is a commercially proved technology for XHO reservoirs. The expected ultimate recovery with primary production is generally less than 12% of original oil in place (OOIP), and thermal enhanced oil recovery (EOR) is critical for increasing recovery to 30–60% OOIP. Economic and environmentally viable thermal development of these reservoirs will require the use of horizontal steam injectors. Our results reveal that continuous steam injection (CSI) with a horizontal injector placed vertically above a horizontal producer (CSI-HIHP) is a very effective method for XHO reservoirs, with high peak-oil rate and significantly high recovery. This study, the first of its kind for an XHO reservoir, outlines an integrated work flow to evaluate the production potential of a large XHO greenfield with PP followed by thermal exploitation. The work flow, based on a probabilistic framework [involving design of experiment (DOE), proxy methods, and Monte Carlo simulations], evaluates reservoir performance for the whole life cycle of the field under a range of uncertainties, and quantifies the impact of key parameters affecting the reservoir performance. XHO reservoirs usually have significantly higher pressures than typical conventional heavy-oil reservoirs, where CSI has been applied commercially. Therefore, pressure in these reservoirs must be reduced before CSI can begin. Cyclic steam stimulation (CSS) after the initial stage of PP can be used to accelerate pressure reduction in the reservoir, while providing additional recovery. Our results demonstrate that geological features such as shale baffles have a significant impact on delaying pressure reduction during PP and CSS. Under a broad range of conditions investigated in this study, PP for 1 year followed by CSS for 4 years has been found to be successful in reducing pressure to the target pressure for CSI. High pressure drop in the horizontal steam injector can cause pressure near the toe region of the injector to be lower than the producer pressure. This results in poor steam injection and poor steam-chest development in that region, thus greatly reducing the efficiency of the thermal-recovery process. We quantify pressure drop in a horizontal steam injector and its impact on the thermal performance and suggest a novel well configuration that uses two injectors for every long producer during CSI. The proposed configuration with a sequential development plan can significantly improve economics of the projects. A novel probabilistic work flow for a full-field (FF) development plan (PP, CSS, and CSI) of XHO reservoirs provides robust production forecast during the entire life cycle. The work flow developed and the insights obtained would be very valuable in preparing effective exploitation plans and optimal facility design, a key economic variable in large projects of developing giant XHO reservoirs.
When compared with steam-assisted gravity drainage (SAGD) operations in the McMurray Formation, Athabasca Oil Sands, SAGD projects in the Clearwater Formation at Cold Lake did not perform as expected, likely because of reservoir properties. This paper will use the Orion SAGD case study to: (1) investigate the impacts of reservoir properties on the SAGD thermal efficiency by field evidences; (2) identify key geological parameters influencing each well pad; and (3) summarize major geological challenges for Orion SAGD expansion.
Wireline log data were interpreted to characterize reservoir properties, which were used to build 3D models. 3D visualizations and 2D cross sections of the reservoir revealed spatial distribution and heterogeneity of each property. SAGD production performance was analyzed using: (1) temperature profiles that monitored the growth of the steam chamber; (2) cumulative steam-oil ratios (CSORs); and (3) oil production rates (OPRates), which are direct indicators of thermal efficiency.
Results show that impermeable barriers and low-permeability zones were detrimental to steam injectivity and steam chamber growth, as observation wells in Pilot Pads 1 and 3 did not detect any steam saturation. High-permeability zones favored high steam injectivity and mobility, especially in Pad 105. Steam chambers were irregularly shaped by high shale-content zones, as two sharp spikes displayed on the temperature profile in Pad 103. Low oil-saturation zones and thin net-pays increased the CSORs, as seen in Pads 106 and 104. Impermeable barriers are almost horizontal, making no difference on well pad orientation by their dip angles. Lack of porosity variation made it difficult to identify the impact of porosity on each well pad.
The relatively extensive distribution of impermeable barriers between and above well pairs, as well as the relatively large area of low oil saturation and thin net-pay, were identified as major geological challenges.
Steam-assisted gravity drainage is the method of choice to extract bitumen from Athabasca oil-sand reservoirs in Western Canada. Under reservoir conditions, bitumen is immobile because of high viscosity, and its typically high level of saturation limits the injectivity of steam. In current industry practice, steam is circulated within injection and production wells. Operators keep the steam circulating until mobile bitumen breaks through the producer and communication is established between the injector and the producer. The “startup” phase is a time-consuming process taking three or more months with no oil production. A variety of processes could be used to minimize the length of the startup phase, such as electromagnetic (EM) heating in either the induction (medium frequency) or radio-frequency ranges. Knowledge of the size of the hot zone formed by steam circulation and of the benefits of simultaneous EM-heating techniques increases understanding of the startup process and helps to minimize startup duration. The aim of the present work is to introduce an analytical model to predict startup duration for steam circulation with and without EM heating. Results reveal that resistive (electrothermal) heating with/without brine injection cannot be a preferable method for mobilizing the bitumen in startup phase. Induction slightly decreases startup time at frequencies smaller than 10 kHz, and at 100 kHz it can reduce startup time to less than two months.
Over the last 30 years, laboratory testing has been conducted to investigate the geotechnical properties of Clearwater clay shales from the Clearwater formation in northeast Alberta, Canada. These properties are important for characterization of the overburden zones above in-situ oil-sands mines and for assessment of caprock integrity in steam-assisted-gravity-drainage (SAGD) projects. In general, caprock-integrity assessments include caprock geological studies, in-situ stress determination, constitutive-property characterization, and numerical simulations, which allow operators to ensure that steam-injection pressure does not cause any risk to the confinement of steam chambers. The aim of this study is to identify and provide the representative parameters that can enhance understanding of the geotechnical behaviour of the Alberta Clearwater formation clay shale. Moreover, it illustrates how the results can be used to extract constitutive model parameters for modelling the behaviour of this class of material. The parameters are also used for complex reservoir-geomechanical simulation for caprock integrity. These parameters are also compared with other Cretaceous clay-shale counterparts in North America.
The Cold Lake project, located in Alberta, Canada, is the world's largest heavy oil in situ thermal development, with production of about 24,000 m3/d (150 kB/d) of oil from more than 4500 wells. In 2009, Cold Lake produced its one billionth barrel (160 million m3) of heavy oil.
The world class Cold Lake hydrocarbon resource is characterized as a bitumen deposit, featuring in situ viscosities in excess of 100,000 mPa-s. Early depletion plans envisioned a thermal recovery process similar to the steamflood technologies employed to recover heavy oil in California's San Joaquin Valley. The order of magnitude difference between Cold Lake and California in-situ viscosities, however, severely limits steam injectivity below fracture pressure, necessitating the development of a Cold Lake specific cyclic steam stimulation (CSS) process throughout the 1980s.
Continual process optimization combined with infill drilling has resulted in a progressive increase in expected bitumen recovery from 13% to greater than 40% of effective bitumen in place (EBIP). A multi-disciplinary reservoir management effort conducted over the last several years has provided the view that Cold Lake recovery levels may potentially be increased to over 65% by adapting steamflood principles to mature CSS areas of the reservoir:
As cyclic process efficiency declines due to lack of steam confinement, steamflood technologies become an attractive recovery scheme in mature Cold Lake reservoir by capitalizing on large scale inter-well communication while focusing on gravity drainage: