A comparative risk assessment was conducted to evaluate the risk associated with a Steam Assisted Gravity Drainage (SAGD) well blowout. The main comparison was between an isolated (double barrier) completion and an open (single barrier) completion used in conjunction with an effective blowout response plan. The target application was a SAGD pilot project in the Orinoco Belt in Venezuela.
The overall approach for the risk assessment included the investigation of the blowout flowing potential of the SAGD wells pair through reservoir modelling, the estimation of the probability of a blowout using fault-tree analysis, and the evaluation of the possible consequences (life safety, environmental and economic) of such blowout using various quantitative consequence models. Details of this approach are discussed in this paper, along with the results specific to the target application.
Results of this work can provide guidance for similar operations where decisions regarding completion options and blowout response plans are required. One key result was that, for this specific SAGD pilot project, a blowout response plan must be able to reduce the blowout duration substantially (from 3 days to 1 day for environmental risk, and from 3 days to 2 hours for economic risk) for the environmental and economical risks associated with a open completion to be comparable to those of an isolated completion.
Meher, Rajendra Kumar (Oil & Natural Gas Corp. Ltd.) | Suyan, Kalyan Mal (Oil & Natural Gas Corp. Ltd.) | Dasgupta, Debasish (Oil & Natural Gas Corp. Ltd.) | Deodhar, S. (Oil & Natural Gas Corp. Ltd.) | Sharma, Vinod (Oil & Natural Gas Corp. Ltd.) | Jain, Vinay Kumar (Oil & Natural Gas Corp. Ltd.)
Cementation of In-situ combustion (ISC) wells is a challenging affair as wells are often associated with weak and unconsolidated formation, nevertheless cement rise upto surface is desired to prevent casing failure. Furthermore the cement sheath is also required to withstand extreme stresses due to high temperature cycling experienced during in-situ combustion process.
In heavy oil fields of western India, due to the problem of inadequate placement time and flash setting when in contact with portland cement, the portland cement-silica blends were used for cementation of ISC wells instead of alumina cement blends. But this resulted in insufficient cement rise due to losses during cementation and the set cement failed to contain the strength and permeability in course of ISC process causing charging of sub-surface shallower layers.
For mitigating these problems, non-alumina based thermally stable lightweight lead slurry and a ductile high temperature resistance tail slurry have been developed and implemented for cementation of ISC wells, the details of which alongwith successful case histories are presented in this paper.
In the formulated thermally stable slurries there was neither reduction in strength nor increase in permeability even after thermal cycling upto 6500C. The lightweight slurry composition (S.G.1.60) reduced the hydrostatic head to effect cement rise upto surface. Since these formulations are devoid of alumina cement, all the associated field problems were totally eliminated. Superior cement bondage in comparison to earlier results confirmed the successful field validation.
This approach and the development is a unique solution of the problems in cementation of ISC wells, making it suitable for use as an effective alternative to earlier practices. Field implementation of this development has successfully arrested charging of shallower zones which was endangering the ISC process in fields of western India.
Simulation of an in situ combustion process (ISC) was done for a fractured system at core and matrix block scales. The aim of this work was to: 1) To predict the ISC extinction/propagation condition(s), 2) understand the mechanism of oil recovery and 3) provide some guidelines for ISC upscaling for a fractured system. The study was based on a fine grid, single porosity, multi-phase and multi-component simulation using a thermal reservoir simulator. The following results were obtained:
a) Firstly the simulator was validated for 1-D combustion using the corresponding analytical solutions. 2-D combustion was validated using experimental results available in the literature. It was found that the grid size should not be larger than the combustion zone thickness in order the results be independent of grid size. b) ISC in fractured system was feasible under certain conditions: The extinction/propagation of ISC was strongly dependent on the oxygen diffusion coefficient while the matrix permeability played an important role in oil production. c) Effect of each production mechanism was studied separately whenever it was possible. Oil production is governed mainly by gravity drainage and thermal effects; possible pressure gradient generation in the ISC process seems to have a minor effect. d) The nature of ISC at core scale was different between a single block and multiple blocks (oil production rate, saturations distribution, shape of the combustion front). The characteristics of different zones (i.e. combustion, coke, oil) at block scale were studied and some preliminary guidelines for usscaling are presented.
Jet pumping has been considered as an efficient artificial lifting technique for deep oil production due to its simplicity and lack of moving parts. If light oil is used as power fluid, jet pumping becomes one of the preferred artificial lift methods for the deep-heavy-oil reservoirs by dramatically reducing both viscosity of the reservoir fluid and the pressure loss along the production string. In practice, the amount of light oil required as the power fluid can be as high as three times of the reservoir fluid, among which only a small portion of the light oil is actually needed for viscosity reduction. In this paper, a novel technique has been developed and successfully applied to significantly reduce the amount of light oil usage in a deep-heavyoil reservoir. More specifically, two approaches are developed and compared. As for Approach A, the oil well is produced with jet pumping driven by light oil first, and then the produced fluid is reinjected into the well as the power fluid. This process keeps circulating until viscosity of the produced fluid is too high to be utilized for jet pumping. As for Approach B, partial produced fluid is combined with the light oil at any reasonable ratios, and subsequently the produced fluid-light oil mixture is reinjected into the well as the power fluid. In the latter approach, viscosity of the mixture keeps increasing and will reach its equilibrium value in a few days, and thus, stable production will be achieved as well. Theoretic models are developed to determine the viscosity of the power fluid for each circulation and the maximum cycle number for the former approach as well as the equilibrium viscosity of the mixed power fluid and the optimum ratio of light oil to the produced fluid-light oil mixture for the latter approach. Field applications show that the reservoir fluid produced from deep heavy oil wells is increased by three times and that the amount of light oil can be reduced by more than 60% for either approach.
Deep-heavy-oil reservoirs, usually referred to those with depth of more than 3000 m (Christ and Petrie 1989), are different from the conventional heavy oil reservoirs. In general, reservoir fluid can flow more easily in the formation as well as around the bottomhole in a deep heavy oil well at a higher temperature. However, during its path along the production string, viscosity of the reservoir fluid increases dramatically due to heat loss and release of the dissolved gas, which results in great pressure drop along the wellbore. Thus, artificial lifting methods need to be adopted to pump the reservoir fluids to the surface.
Among the artificial lifting techniques, jet pumping has been proven to be an efficient method in producing oil from deep heavy oil reservoirs (Cunningham 1957; Petrie et al. 1983a; Petrie et al. 1983b; Petrie et al. 1984; Tjondrodiputro et al. 1986; Tjondodiputro et al. 1987). Jet pump is a venturi-type device where a high-pressure power fluid is used to accelerate to reach a higher velocity and thereby create a lower pressure area into which reservoir fluids will flow (Mueller 1964). Because of its small size, simplicity, lack of moving parts, a jet pump can be installed in the wellbore at a deep location. It also has a strong ability to pump fluids with high viscosity and/or serious corrosivity (Petrie et al. 1983c). For heavy oil production, light oil can be used as the power fluid because it reduces viscosity of the reservoir fluid and the pressure drop in the production string as well (Qu et al. 2000). The reduction of the pressure drop is mainly ascribed to instantaneous and thorough blending of the light oil and the reservoir fluid in the jet pump throat (De Ghetto et al. 1994).
Wenlong, Guan (PetroChina Co. Ltd.) | Shuhong, Wu (PetroChina Co. Ltd.) | Jian, Zhao (Tuha Oil Field, PetroChina Company Limited) | Xialin, Zhang (PetroChina Co. Ltd.) | Jinzhong, Liang (University of Petroleum) | Xiao, Ma (University of Petroleum)
L Block is a super-deep heavy oil reservoir with the degassed oil viscosity of 9,680~12,000mPa.s @50, 2800~3300 m deep with normal pressure system and 80~95 in the reservoir. The GOR is 12m3/m3 and the initial bubble point pressure is only 4MPa. High oil viscosity and low flowability result in low production and rapid decline of primary development. This paper will review mechanisms, feasibility and pilot test of utilizing natural gas huff and puff to enhance production in L Block. Firstly, the paper will detail the lab experiments which include the conventional PVT and unconventional PVT. The conventional PVT shows that the natural gas dissolved in the oil can greatly decrease oil viscosity by 1~2 orders of magnitude and enhance the flowability in one hand, in other hand, it can large the volume coefficient and add the elastic energy. The unconventional PVT shows that the heavy oil can effectively entrap the gas for more than several hours because of its high viscosity. There exists a pseudo bubble point pressure far lower than bubble point pressure in the manmade foamy oil, which is relative to the depressurization rate. Under the condition, the elastic energy could be maintained in a wider pressure scope than natural depletion without gas injection. Secondly, the paper will introduce a special experiment apparatus which can simulate the process of gas huff and puff in the reservoir. The huff and puff experiment shows that in this process the foamy oil can be seen and most of oil flows to the producer in pseudo single phase, which is one of the most important mechanisms of enhancing production. Finally, the paper will brief the pilot test of single well, which shows that the oil production is increased to 5~6 m3/d from 1~2m3/d by natural gas huff and puff and the stable production period is prolonged to 91days in the first cycle and 245 days in the second cycle from 5~10 days before huff and puff.
The use of optical fibers in the oil and gas industry is becoming more viable for several permanent monitoring applications, such as distributed temperature sensing (DTS) and optical pressure transducers. However, long-term performance of fibers, especially at elevated temperatures, is still an issue yet to be fully resolved. This problem is critically important in steam-assisted gravity drainage (SAGD) applications, where wells operate in extreme conditions of high temperatures, often exceeding 250oC, as well as in high pressures within a hydrogen-rich environment.
Optical fiber performance is seriously affected by many factors, including:
• Hydrogen ingression
• Thermal resistance of the materials
• Mechanical resistance of the fiber
Exposure of optical fibers to hydrogen changes the performance of the fibers through what is referred to in the industry as "hydrogen aging?? or "hydrogen darkening.?? Hydrogen darkening is increased absorption or light loss due to various chemical species in the glass fiber resulting from the presence of hydrogen.
Value of DTS in SAGD Applications
It is known that temperature monitoring in SAGD wells is of significant importance because it provides a good understanding of the temperature distribution along the horizontal section. Conventionally, thermocouples have been used to measure and monitor the temperature along the horizontal section, and are typically installed at heel, middle and toe of the section. Since thermocouples (TC) inherently provide temperature data at these discrete points, temperature information between the TCs is
usually interpolated to understand the temperature distribution. As a result of this interpolation, there could be sections of the wellbore that would require more data from different sources for a detailed analysis instead of just being able to visualize the temperature behavior. Hence, there is a need for a tool that can provide temperature data along the entire length of the horizontal section. In addition, the installation must be simple in order to keep it safe and cost-effective. The optical fiberbased DTS technology has been applied in the past successfully and it is known that the optical fiber-based DTS technique provides temperature data along the entire length of the fiber. This temperature data provides information;, e.g., what sections of the lateral are operating at "sub cool,?? and enabling users to:
• Quickly identify anomalies
• Immediately implement corrective action
• Allow for better steam utilization
Numerical simulation of thermal recovery processes like steam injection often involves localized phenomena such as saturation and temperature fronts due to hyperbolic features of governing conservation laws, Treating more efficiently convective terms could help to diminish spurious oscillation and/or numerical dispersion and better tracking of discontinuity shocks . But in regions near the shock numerical dispersion can only be removed by the use of very fine uniform grids with many grid blocks. To avoid expensive solution of such a finely girded domain, we develop a moving mesh approach combined with higher order up-winding schemes.
Numerical solver here have been employed is Finite volume method. A MMPDE(moving mesh PDE) is solved associated with physical PDE's of steam injection process in order to relocates the mesh nodes to concentrate them in regions of sharp discontinuity and Equi-distribute a measure of error-estimate (monitor function) over the meshes. Solution will advance more rapidly on course meshes and fluxes at the coarse-fine grid interfaces are refined to guarantee mass conservation. . Since the region surrounding the sharp discontinuity and requiring high resolution consists of only a small fraction of the entire domain, prescribed locally time stepping results in a great saving in computational time. Specific features of moving mesh methods like monitor-function smoothing, control of mesh widths and readjustment of solutions further to mesh movement are addressed. Numerical experiments are carried out to demonstrate the efficiency and robustness of the proposed method in 1-D and 2-D.However numerical results for moving coordinates are compared with those obtained from simulation on non-adapted mesh framework. Preferences of higher-order solvers over lower-order ones in terms of shock capturing is being investigated. .Although we have limited our modeling to steam flooding process, but simulation demonstrates main features of our approach, applicable to other EOR processes such as VAPEX, SAGD, and In Situ Combustion Process.
The large expansion in future Canadian extra heavy oil in situ thermal production (e.g. SAGD) projects will dramatically increase the demand for natural gas, the current predominant fuel used for the associated steam generation.
For thermal (SAGD) applications, depending on the Steam Oil Ratio (SOR), approximately 40,000 T/day of steam CWE (Cold Water Equivalent) is injected to produce 100,000 bpd of bitumen, requiring some 100 M SCF/day of natural gas to be fired in Once Through Steam Generators (OTSG's.)
Potential natural gas shortages and related price volatility dictate that operators consider alternative fuels for the projected near future growth in Alberta's in situ thermal production.
This paper targets the use of bitumen from upstream sites and derivative residues from upgrading activities as the most convenient alternative fuel sources for thermal operators of established ‘horizontal type' gas fired OTSG's.
Past attempts to adapt / convert existing gas fired OTSG's to heavy liquid firing were unsuccessful because the conversions were made in haste, without properly addressing and resolving the many fundamental technical challenges involved. In consequence extensive operating problems and resultant poor reliability caused the trials
to be abandoned. Furthermore at that time a cost saving benefit in displacing gas burn against heavy liquid was not consistently evident to support the further investment required.
Hence only ‘new design' OTSG units can be sensibly considered for alternative heavy liquid fuels, also, retaining natural gas as a fuel option gives the Oil & Gas Operator a Multi Fuel OTSG, and some choice in the fuel market place.
This paper presents the methodology, the issues associated with bitumen / residue burning and the related technical solutions in development for this Multi Fuel OTSG product - natural gas firing being retained as an option and for start up.
The concepts and details of the largest transportable OTSG modules are considered, based on manufacturer TIW Western Inc's (TIWW) established gas fired designs, addressing changes necessary for heavy liquid fuel firing.
Combustion, furnace and convection section configurations and materials of construction have been selected for optimal performance / availability, whilst taking due accounts of fouling, cleaning and erosion issues, and both high and low temperature corrosion factors.
Canadian oil sands in the province of Alberta are a hydrocarbon source for North America. By the year 2015, the oil sands will be producing in excess of 3 million barrels/day of crude oil. A number of companies operate Upgraders that convert the bitumen that is extracted from the oil sands into light sweet crude oil. Steam is required to heat utilities at the Upgrader facility.
In one major oil sands extraction site, well water is being used as feed water for the boilers producing this steam. Reverse Osmosis (RO) systems were designed and installed to produce high quality water required for this application. The pretreatment system was designed with conventional multimedia technology. The RO system required feed water with silt density index (SDI) of 3 or less. Due to ineffectiveness of the conventional pretreatment system, the SDI of the RO feed water was in the range of 12-20. This resulted in severe fouling of the RO membranes and production losses.
In order to optimize the performance of the RO membrane system, a pressurized microfiltration membrane system was delivered and commissioned within 5 days to replace the existing pre-treatment system. The new unit contained an automated PVDF hollow fiber microfiltration membrane system mounted in a trailer. SDI values in the range of 1.0-2.5 were immediately observed in the feed water to the RO system. The end user has enjoyed significant cost savings and ease of operation as a result of this innovative technology. This paper describes the details of the installation and the superior performance data gathered at the end user site.
A. Oil Sands Deposits.
The Oil and Gas Journal has reported nearly 175 billion barrels of reserves from oil sands in Alberta, Canada in 2005, (1) making it one of the largest oil reserves in the world. They are located in three distinct areas in northern Alberta—the largest deposits are along the Athabasca River and there are smaller deposits in Cold Lake and Peace River. Current production of approximately 1 million bbl/day of crude oil from bitumen is predicted to increase to over 3 millon bbl/day by Y2015. With oil prices now in excess of $80/bbl, there are nearly 100 oil sands projects totaling about $100 billion in capital investment. Tax incentives are no longer necessary to encourage oil sands investments.
B. Extraction Methods.
Currently, two-thirds of the bitumen output is produced by strip mining (2) and a quarter by in-situ methods such as Steam Assisted Gravity Drainage (SAGD). But since 80% of the recoverable bitumen is buried too deep for strip mining, the in-situ methods are expected to dominate the scene in the coming years. In the SAGD process, two horizontal wells are drilled into the oil sands, one near the bottom of the formation and another one, typically 5 meters above it. These wells can extend up to a kilometer in all directions. Steam is injected into the upper well. The heat decreases the viscosity of the bitumen, which allows it to flow into the lower well, from where it is produced.
A simulation study was carried out to examine the effects of changing the landing position of the short production tubing string relative to the heel of a SAGD production well. A homogeneous discretized wellbore model with the riser section was used in this study. Generally, a reservoir is modeled independent of the wellbore. However, this study models the reservoir and wellbore simultaneously to understand the interactions between them.
This paper outlines two independent case studies, which are outlined below:
1. The first study involved shortening the short production tubing string relative to the heel of the well. It was found that as the short tubing string was pulled back from the heel of the well the bitumen production rate decreased, and the amount of steam produced through the short production tubing string increased.
2. The second case study outlines the impact of extending the short production tubing string past the heel of the well on bitumen production and SOR. From this case study, it was found that as the short production tubing string was pushed past the heel of the well, the bitumen production rate stayed the same, but the steam injection rate decreased which consequently decreased the SOR. It was also observed that a lower pressure differential between the injector and producer well was established when the short production tubing string was extended.
The results for this study will assist SAGD producers to re-evaluate the position of the short production tubing string, and find the most economical position for this string. This paper creates the foundation for further simulation efforts to incorporate a discretized model with the build section coupled to the reservoir. This will allow production engineers to optimize bitumen production by simultaneously simulating the reservoir and wellbore strings together.