A.K. Singhal

Overview of Short-Distance Oil Displacement Processes

With the advent of horizontal wells, a distinct change is tacitly taking place in our approach to improved recovery of heavy oil: from displacing mobilized oil in a flood pattern from injector to producer over long distances of the order of hundreds of metres, to short-distance oil displacement (SDOD) processes (typically over a few metres). Due to the high viscosity of oil, its displacement to a producer site located a long distance away is usually inefficient. In these cases, the required pressure drop may be very high, and/or the mobility ratio between injectant and oil exceedingly large. Either gravity override or very intensive channeling may take place, resulting in extremely low volumetric sweep efficiency and hence, generally marginal or poor economics. Using horizontal wells, travel distances for the mobilized oil to reach the producer can be shortened. SDOD processes are aimed at mobilizing oil and producing it immediately, via the shortest path, into a horizontal producer. SDOD processes can utilize horizontal producers and injectors, or combinations of horizontal producers and vertical injectors. Based on the displacement fronts position relative to the horizontal section of a producer, SDOD processes could be divided into two categories: 1. Those with a displacement front quasi-parallel to the horizontal producer. 2. Those with a displacement front quasi-perpendicular to the horizontal producer. While the first type of SDOD process uses two parallel horizontal wells (one for injection and the other one for production), the second type uses a vertical injector and a horizontal producer with the toe of the producer located in the proximity of the shoe of the injector. In the first type of process, production occurs throughout the entire horizontal section. In the second type, the swept zone extends and moves from the toe towards the heel, utilizing reduced sections of the horizontal well for production. Steam Assisted Gravity Drainage (SAGD) and Vapour Extraction (VAPEX) processes belong to the first type. Toe-To-Heel (TTH) displacement processes are of the second type. These TTH displacement processes can be applied in a non-thermal mode, such as Toe-To-Heel Waterflooding or a thermal j mode such as THAI (Toe-To-Heel Air Injection) along with its variant, CAPRI, aimed at in situ oil upgrading. An analysis of all SDOD processes (SAGD, VAPEX, and TTH displacement processes) was performed, focusing on their relative merits in terms of override or underride due to gravity segregation, injectant channeling due to reservoir heterogeneity, and injectant/oil mobility ratio causing instabilities. These negative factors are very important in defining the efficiency of the long-distance oil recovery techniques, but they are substantially less important during the SDOD processes. Therefore, in many situations, the efficiency of heavy oil exploitation via SDOD IOR/EOR processes is usually better than alternate recovery schemes. Finally, basic concepts behind different TTH displacement processes are examined in light of available laboratory and simulation results. Also, various aspects of SDOD process implementation in the field along with practical considerations are discussed.

Basic Investigations on Enhanced Gas Recovery by Gas-Gas Displacement

The paper presents basic data on Enhanced Gas Recovery (EGR) by gas-gas displacement for nearly depleted natural gas reservoirs, by injecting waste gases. The soundness of the concept of gas-gas displacement for enhancing gas recovery was investigated via laboratory investigations, compositional modeling and economic analyses. Paramount Resources is field testing the concept in their GRIPE Project in the Athabasca region of Alberta, to enhance production from a gas bearing stratum overlying the oil sand

Preliminary considerations on application of steamflooding in a toe-to-heel configuration

With the advent of horizontal wells, a distinct change is tacitly taking place in our approach to the improved recovery of heavy oil-from displacing mobilized oil in a flood pattern from injector to producers over long distances on the order of hundreds of metres to short-distance oil displacement (SDOD) processes (typically over a few tens of metres). SDOD processes comprise Steam Assisted Gravity Drainage (SAGD), Cyclic Steam Stimulation (CSS) and Toe-to-Heel (TTH) Displacement Processes, which comprise Toe-to-Heel Air Injection (THAI), with its variant catalytic THAI (CAPRI), and Toe-to-Heel Waterflooding (TTHW). Presently SAGD is commercially used, while THAI has been under field testing for 3 years; testing of CAPRI is scheduled to start in 2010. TTHW has been under field testing both in the US and Canada for more than 4 years. Steamflooding in a TTH configuration (TTH steamflooding) uses vertical wells as injectors and horizontal wells as producers, arranged in a staggered line drive, with producers having their toes close to the shoes of vertical injectors; the horizontal section of producers is located at the base of the pay. The vertical wells are used for initiating the steam front, which subsequently is anchored at the toe of the horizontal producer; it is then propagated towards the producers heel. In TTH steamflooding, the existing deficiency of conventional steamflooding schemes in terms of low vertical sweep is overcome by the beneficial use of gravity. To investigate the potential of TTH steamflooding, some laboratory tests were conducted. The objective was to assess the feasibility of TTH steam and thermo-solvent flooding (steam+propane co-injection) by carrying out 3D model experiments using heavy oil with a viscosity of 15,000 cP. Laboratory results showed that the concepts of TTH steamflooding and TTH steamflooding with solvent are feasible. All in all, stability of TTH steamflooding was relatively good, while the stability of TTH steamflooding with the addition of nitrogen or propane was much better. Significant improvements in design and operation of these processes were needed in order to promote override during the early phase, and obtain a stable and efficient process. The improvements included a cold (gas fingering) and a hot (steam-based) communication phase-, and controlling lateral spread of steam by using two additional vertical control wells (positioned laterally but close to the heel of the horizontal producer) for conducting a limited steamflood. Nitrogen was injected along with steam in the conventional steamflood; propane replaced nitrogen in TTH steamflooding with solvent. With these improvements, rise of steam chamber to the top occurred much earlier, and a favourable tilt-forward-angle of the thermal front was quickly obtained. TTH steamflooding with solvent proved superior to the TTH steamflooding, as the channeling of steam through the horizontal well was much better controlled, and the oil recovery was considerably faster. With these improvements, the oil recovery increased from 50 - 54% to 75 - 77%, and the operation became smoother. Presently, the process can be considered only for reservoirs where oil has some mobility under reservoir conditions. In order to develop the full potential of TTH steamflooding, technology means are needed for controlling channeling through the horizontal producer (this control Occurs naturally in the THAI process); at present there are a few methods which seem promising.

Field Foam Applications in Enhanced Oil Recovery Projects: Screening and Design Aspects

An in-depth analysis was conducted for over forty foam applications in Enhanced Oil Recovery (EOR) projects, and numerous production well treatment operations involving the use of foam in cyclic steam operations and in gas miscible floods, to derive insights on screening and design aspects in such applications. Foam can be used to solve conformance problems caused by either a thief zone or gravity override; The proper identification of the cause, as well as of the production well(s) affected is basic to the definition of the problem. Either blocking/diverting foams or in-depth mobility control foams can be placed through the injection wells. On the other hand, foam treatment in production wells is done mainly to mitigate an override problem. The most important factors in foam assisted EOR projects were determined to be: (a) manner of foam placement in the reservoir (injection of pre-formed foam, co-injection foam and SAG or surfactant alternating gas foam), (b) reservoir pressure and c) permeability. While pre-formed foam are effective mainly in the treatment of the production wells, the co-injection foam and SAG can be employed for solving specific sweep efficiency problems in EOR projects. It is concluded that for designing a steam-foam project (which is essentially a low pressure foam application) a foam quality in the range 45% to 80% should be considered. In this kind of application, a co-injection foam is to be employed and the additives (surfactant and non-condensable gas) are to be injected intermittently (on and off), superimposed on a continuous steam injection. Injection cycles as short as 7 days (2 days-on and 5 days-off) should be considered. Under suitable conditions, an oil rate increase of 1.5 to 5 times, a decrease in water cut by 20 %, and an incremental oil recovery of 6%-12% OOIP can be achieved with such an implementation. At high pressure, such as in gas miscible flooding (CO 2 and hydrocarbon gas ), foam application can result in excessive mobility reduction factors, and injectivity reduction. Due to this reason, alternate injection of surfactant solution and gas (SAG foam) is favoured over a co-injection mode of placement. Recommendations for laboratory tests in support of a proper design of the field pilot are presented.

Enhanced Gas Recovery: Factors Affecting Gas-Gas Displacement Efficiency

This paper is part of a series of papers on the results of Enhanced Gas Recovery (EGR) research conducted at the Alberta Research Council during 2003 to 2007. In this Joint Industry Project (JIP), the soundness of the concept of gas-gas displacement for enhancing gas recovery was investigated via laboratory investigations, compositional modelling and economic analyses. The results of Phase I gas-gas displacement tests conducted at relative high pressure and temperature (6.2 MPa and 70°C) in 4 cm diameter 30 cm long Berea core were recently reported (1,2) . In the second phase (2004-2005) of the JIP, the main targets were low pressure volumetric (closed) reservoirs in advanced stages of exploitation and also gas bearing strata overlaying oil sand intervals. Pressure maintenance of a depleting gas reservoir by waste gas injection can serve to: 1) arrest the decline in gas production rate, prevent premature well abandonment and increase ultimate recovery; 2) discourage the advance of an aquifer (if present) into the gas zone; and 3) in the case of Gas-Over-Bitumen situations, mitigate declining reservoir pressure during natural gas production to enable exploitation of the underlying oil sands. One example of a field application of this EGR technology was the GRIPE Project operated by Paramount Resources during 2005 and 2006. A series of gas-gas displacement tests were conducted at room temperature and at pressures between 0.7 and 3.5 MPa in the presence of connate water in 5 cm diameter x 2 m long sand-packs. Experimental parameters, such as nature of the injection gas, displacement pressure and displacement rate were systematically varied to study their effect on the displacement efficiency. Numerical simulations of the experimental results were also conducted to gain a better understanding of the interrelationship between the different variables. The laboratory results showed that during low velocity displacement of methane by flue gas in a homogeneous linear sand-pack, molecular diffusion has a dominating effect on the recovery of marketable methane. Reasonable values of molecular diffusion coefficient for different gas-gas displacement conditions were obtained by matching the experimental test results with the numerical simulation. In spite of anticipated adverse effects of mixing between displaced and displacing gas due to molecular diffusion under low pressure and low flow velocity conditions, incremental recoveries of marketable methane under the experimental conditions were encouraging and suggest that EGR by gas-gas displacement can prolong the productive life and increase natural gas recovery from many volumetric gas reservoirs.

Role of Operating Practices on Performance of Waterfloods in Heavy Oil Reservoirs

Identification of operating conditions that have been beneficial or injurious to overall performance of past waterfloods in heavy oil reservoirs is the first essential step towards optimization of similar projects in the future. Comparative analyses of performance of various waterfloods in a given region (deposited under similar conditions) can be very instructive to identify such conditions. Insights on performance of waterfloods in heavy oil reservoirs were derived from a comparative evaluation of recent performance history of three selected waterfloods. These waterfloods involved increasing, decreasing and steady water injection rates. It was seen that aggressive injection rates lead to increased oil rates, but at rapidly increasing water cuts. Decreasing water injection rates, on the other hand, lead to low oil rates, but with water cuts increasing relatively more gradually. There is, therefore, an economically optimal water injection rate strategy for each specific situation.

Conditions Favourable to Infill Drilling in Waterfloods in Sandstone Reservoirs Containing Medium/Heavy Oils

Production histories of four waterfloods, each with several infill wells, were examined to identify conditions favourable to in-fill drilling in sandstone reservoirs containing heavy/medium oils under waterflood. The dominant role of reservoir heterogeneity was inferred from the nature of performance of newer and older infill wells. Due to these heterogeneities, some of the mobile oil contained within the reservoir is not drained by the older wells, but infill wells could drain a portion (up to 25%) of this oil. Based on the cases studied, conditions favourable for infill wells were: a) Current oil rates of older wells greater than 3 m 3 /d and watercut less than 75%. b) Original Oil-in-Place (OOIP)/well for the reduced spacing greater than 80 E3m 3 and total recovery factor (primary + waterflood) greater than 25%. It is recommended that these criteria be validated by further technical and economic studies.