Patent Application
20120234535
This application claims priority to Canadian Patent Application 2,734,170 filed on Mar. 15, 2011 entitled METHOD OF INJECTING SOLVENT INTO AN UNDERGROUND RESERVOIR TO AID RECOVERY OF HYDROCARBONS, the entirety of which is incorporated by reference herein.
The present disclosure relates generally to the recovery of in-situ hydrocarbons. More particularly, the present disclosure relates to the use of a cyclic solvent-dominated recovery process (CSDRP) to recover in-situ hydrocarbons including bitumen.
At the present time, solvent-dominated recovery processes (SDRPs) are not commonly used as commercial recovery processes to produce highly viscous oil. Highly viscous oils are produced primarily using thermal methods in which heat, typically in the form of steam, is added to the reservoir. Cyclic solvent-dominated recovery processes (CSDRPs) are a subset of SDRPs. A CSDRP is typically, but not necessarily, a non-thermal recovery method that uses a solvent to mobilize viscous oil by cycles of injection and production. Solvent-dominated means that the injectant comprises greater than 50% by mass of solvent or that greater than 50% of the produced oil's viscosity reduction is obtained by chemical solvation rather than by thermal means. One possible laboratory method for roughly comparing the relative contribution of heat and dilution to the viscosity reduction obtained in a proposed oil recovery process is to compare the viscosity obtained by diluting an oil sample with a solvent to the viscosity reduction obtained by heating the sample.
In a CSDRP, a viscosity-reducing solvent is injected through a well into a subterranean viscous-oil reservoir, causing the pressure to increase. Next, the pressure is lowered and reduced-viscosity oil is produced to the surface through the same well through which the solvent was injected. Multiple cycles of injection and production are used.
CSDRPs may be particularly attractive for thinner or lower-oil-saturation reservoirs. In such reservoirs, thermal methods utilizing heat to reduce viscous oil viscosity may be inefficient due to excessive heat loss to the overburden and/or underburden and/or reservoir with low oil content.
References describing specific CSDRPs include: Canadian Patent No. 2,349,234 (Lim et al.); G. B. Lim et al., “Three-dimensional Scaled Physical Modeling of Solvent Vapour Extraction of Cold Lake Bitumen”, The Journal of Canadian Petroleum Technology, 35(4), pp. 32-40, April 1996; G. B. Lim et al., “Cyclic Stimulation of Cold Lake Oil Sand with Supercritical Ethane”, SPE Paper 30298, 1995; U.S. Pat. No. 3,954,141 (Allen et al.); and M. Feali et al., “Feasibility Study of the Cyclic VAPEX Process for Low Permeable Carbonate Systems”, International Petroleum Technology Conference Paper 12833, 2008.
The family of processes within the Lim et al. references describe embodiments of a particular SDRP that is also a cyclic solvent-dominated recovery process (CSDRP). These processes relate to the recovery of heavy oil and bitumen from subterranean reservoirs using cyclic injection of a solvent in the liquid state which vaporizes upon production. The family of processes within the Lim et al. references may be referred to as CSP™ processes.
With reference to
Generally, the present disclosure relates to a method of controlling a cyclic solvent-dominated recovery process (CSDRP) for recovering viscous oil from a subterranean reservoir of the viscous oil. The cyclic solvent process involves using an injection well to inject a viscosity-reducing solvent into a subterranean viscous oil reservoir. Reduced viscosity oil is produced to the surface using the same well used to inject solvent. The process of alternately injecting solvent and producing a solvent/viscous oil blend through the same wellbore continues in a series of cycles until additional cycles are no longer economical. To improve the efficiency of the solvent, the injection includes at least one restriction duration, where injection is restricted, between two continuous injection periods.
In a first aspect, there is provided a method of controlling a cyclic solvent injection and production process to aid recovery of hydrocarbons from an underground reservoir, the method comprising: (a) injecting a volume of fluid comprising greater than 50 mass % of a viscosity-reducing solvent into an injection well completed in the reservoir; (b) halting injection into the injection well and subsequently producing at least a fraction of the injected fluid and the hydrocarbons from the reservoir through a production well; (c) halting production through the production well; and (d) subsequently repeating the cycle of steps (a) to (c); wherein step (a) comprises at least one restriction duration, where injection is restricted, between two continuous injection periods, for improving the efficiency of the solvent.
Other aspects and features of the present disclosure will become apparent to those ordinarily skilled in the art upon review of the following description of specific embodiments of the invention in conjunction with the accompanying figures.
Embodiments of the present invention will now be described, by way of example only, with reference to the attached Figures, wherein:
The term “viscous oil” as used herein means a hydrocarbon, or mixture of hydrocarbons, that occurs naturally and that has a viscosity of at least 10 cP (centipoise) at initial reservoir conditions. Viscous oil includes oils generally defined as “heavy oil” or “bitumen”. Bitumen is classified as an extra heavy oil, with an API gravity of about 10° or less, referring to its gravity as measured in degrees on the American Petroleum Institute (API) Scale. Heavy oil has an API gravity in the range of about 22.3° to about 10°. The terms viscous oil, heavy oil, and bitumen are used interchangeably herein since they may be extracted using similar processes.
In situ is a Latin phrase for “in the place” and, in the context of hydrocarbon recovery, refers generally to a subsurface hydrocarbon-bearing reservoir. For example, in situ temperature means the temperature within the reservoir. In another usage, an in situ oil recovery technique is one that recovers oil from a reservoir within the earth.
The term “formation” as used herein refers to a subterranean body of rock that is distinct and continuous. The terms “reservoir” and “formation” may be used interchangeably.
As used herein, a “restriction duration” is a time during which injection is restricted, where “restricted” includes fully restricted, that is, where injection does not occur. This concept is explained further herein.
As used herein, a “continuous injection period” is a time during which injection occurs continuously although not necessarily at the same rate. This concept is explained further herein.
During a CSDRP, a reservoir accommodates the injected solvent and non-solvent fluid by compressing the pore fluids and, more importantly in some embodiments, by dilating the reservoir pore space when sufficient injection pressure is applied. Pore dilation is a particularly effective mechanism for permitting solvent to enter into reservoirs filled with viscous oils when the reservoir comprises largely unconsolidated sand grains. Injected solvent fingers into the oil sands and mixes with the viscous oil to yield a reduced viscosity mixture with significantly higher mobility than the native viscous oil. Without intending to be bound by theory, the primary mixing mechanism is thought to be dispersive mixing, not diffusion. Preferably, injected fluid in each cycle replaces the volume of previously recovered fluid and then adds sufficient additional fluid to contact previously uncontacted viscous oil. Preferably, the injected fluid comprises greater than 50% by mass of solvent.
On production, the pressure is reduced and the solvent(s), non-solvent injectant, and viscous oil flow back to the same well and are produced to the surface. As the pressure in the reservoir falls, the produced fluid rate declines with time. Production of the solvent/viscous oil mixture and other injectants may be governed by any of the following mechanisms: gas drive via solvent vaporization and native gas exsolution, compaction drive as the reservoir dilation relaxes, fluid expansion, and gravity-driven flow. The relative importance of the mechanisms depends on static properties such as solvent properties, native GOR (Gas to Oil Ratio), fluid and rock compressibility characteristics, and reservoir depth, but also depends on operational practices such as solvent injection volume, producing pressure, and viscous oil recovery to-date, among other factors.
During an injection/production cycle, the volume of produced oil should be above a minimum threshold to economically justify continuing operations. In addition to an acceptably high production rate, the oil should also be recovered in an efficient manner. One measure of the efficiency of a CSDRP is the ratio of produced oil volume to injected solvent volume over a time interval, called the OISR (produced Oil to Injected Solvent Ratio). Typically, the time interval is one complete injection/production cycle. Alternatively, the time interval may be from the beginning of first injection to the present or some other time interval. When the ratio falls below a certain threshold, further solvent injection may become uneconomic, indicating the solvent should be injected into a different well operating at a higher OISR. The exact OISR threshold depends on the relative price of viscous oil and solvent, among other factors. If either the oil production rate or the OISR becomes too low, the CSDRP may be discontinued. Even if oil rates are high and the solvent use is efficient, it is also important to recover as much of the injected solvent as possible if it has economic value. Depending on the physical properties of the injected solvent, the remaining solvent may be recovered by producing to a low pressure to vaporize the solvent in the reservoir to aid its recovery. One measure of solvent recovery is the percentage of solvent recovered divided by the total injected. In addition, rather than abandoning the well, another recovery process may be initiated. To maximize the economic return of a producing oil well, it is desirable to maintain an economic oil production rate and OISR as long as possible and then recover as much of the solvent as possible.
The OISR is one measure of solvent efficiency. Those skilled in the art will recognize that there are a multitude of other measures of solvent efficiency, such as the inverse of the OISR, or measures of solvent efficiency on a temporal basis that is different from the temporal basis discussed in this disclosure. Solvent recovery percentage is just one measure of solvent recovery. Those skilled in the art will recognize that there are many other measures of solvent recovery, such the percentage loss, volume of unrecovered solvent per volume of recovered oil, or its inverse, the volume of produced oil to volume of lost solvent ratio (OLSR). The Solvent Storage Ratio (SSR) is also a common measure of solvent efficiency. The SSR is a measure of the solvent fraction unrecovered from the reservoir divided by the in situ oil produced from the reservoir. SSR is more explicitly defined as the ratio of the cumulative solvent injected into the reservoir minus the cumulative solvent produced from the reservoir to the cumulative in situ oil produced from the reservoir. A lower SSR indicates lower solvent losses per volume of in situ oil recovered, and thus, better total solvent recovery per volume of in situ oil produced. Therefore, a lower SSR would indicate an improvement in solvent efficiency.
As used herein, “improving solvent efficiency” means (a) improving the OISR, or (b) improving the SSR, or (c) improving both the OISR and the SSR.
The solvent may be a light, but condensable, hydrocarbon or mixture of hydrocarbons comprising ethane, propane, or butane. Additional injectants may include CO2, natural gas, C3+ hydrocarbons, ketones, and alcohols. Non-solvent co-injectants may include steam, hot water, non-condensable gas, or hydrate inhibitors. Viscosifiers may be useful in adjusting solvent viscosity to reach desired injection pressures at available pump rates and may include diesel, viscous oil, bitumen, or diluent. The injection of a solvent slurry may provide further means to reach the desired injection pressure by viscosifying the injectant, reducing the effective permeability of the formation to the injectant, or a combination thereof. The solids suspended in the solvent slurry could comprise biodegradable solid particles, salt, water soluble solid particles, or solvent soluble solid particles. Viscosifiers may be in the liquid, gas, or solid phases. Preferably, viscosifers would be soluble in either one of the components of the injected solvent and water and transition to the liquid phase in the reservoir before or during production, reducing their ability to increase the viscosity of the produced fluids and/or decrease the effective permeability of the formation to the produced fluids. In addition to providing a means to reach the desired injection pressure, the viscosifiers may also reduce the average distance solvent travels from the well during an injection period. Viscosifiers may also act as solvents and therefore may provide flow assurance near the wellbore and in the surface facilities in the event of asphaltene precipitation or solvent vaporization during shut-in periods. Carbon dioxide or hydrocarbon mixtures comprising carbon dioxide may also be desirable to use as a solvent.
In one embodiment, the solvent comprises greater than 50% C2-C5 hydrocarbons on a mass basis. In one embodiment, the solvent is primarily propane, optionally with diluent when it is desirable to adjust the properties of the injectant to improve performance. Alternatively, wells may be subjected to compositions other than these main solvents to improve well pattern performance, for example CO2 flooding of a mature operation.
In one embodiment, the solvent is injected into the well at a pressure in the underground reservoir above a liquid/vapor phase change pressure such that at least 25 mass % of the solvent enters the reservoir in the liquid phase. Alternatively, at least 50, 70, or even 90 mass % of the solvent may enter the reservoir in the liquid phase. Injection as a liquid may be preferred for achieving high pressures because pore dilation at high pressures is thought to be a particularly effective mechanism for permitting solvent to enter into reservoirs filled with viscous oils when the reservoir comprises largely unconsolidated sand grains. Injection as a liquid also may allow higher overall injection rates than injection as a gas.
In some embodiments, it may be desirable to inject a fraction of the injectant in the solid phase in order to mitigate adverse solvent fingering, increase injection pressure, or keep the average distance of the solvent closer to the wellbore than in the case of pure liquid phase injection. In one embodiment, less than 20 mass % of the injectant enters the reservoir in the solid phase. Alternatively, less than 10 mass % or less than 50 mass % of the injectant enters the reservoir in the solid phase. In one embodiment, once in the reservoir, the solid phase of the injectant would transition to a liquid phase before or during production to prevent or mitigate reservoir permeability reduction during production.
In an alternative embodiment, the solvent volume is injected into the well at rates and pressures such that immediately after completing injection into the injection well during an injection period at least 25 mass % of the injected solvent is in a liquid state in the underground reservoir. Injection of the injectant as a vapor may be preferred in order to enable more uniform solvent distribution along a horizontal well, particularly when variable injection rates are targeted. Vapor injection in a horizontal well may also facilitate an upsize in the port size of installed inflow control devices (ICDs) that minimizes the risk of plugging the ICDs. Injecting as a vapor may increase the ability to pressurize the reservoir to a desired pressure by lower effective permeability of an injected vapor in a formation comprising liquid viscous oil. In one embodiment, a non-condensable gas is injected to achieve a desired pressure, followed by injection of a solvent. Alternating periods of a primarily non-condensable gas with primarily solvent injection may provide a means of maintaining the desired injection pressure target. The primarily gas injection period may offset the pressure leak off observed during primarily solvent injection to reestablish the desired injection pressure. Furthermore this alternating strategy of gas to liquid solvent injection periods may result in non-condensable gas accumulations in the previous established solvent pathways. The accumulation of non-condensable gas may divert the subsequent primarily solvent injection to bypassed viscous oil thereby increasing the mixing of solvent and oil in the producing well's drainage area. In another embodiment, an injectant in the vapor phase, such as CO2 or natural gas, may be injected, followed by injection of a solvent. In another embodiment, depending on the pressure of the reservoir, it may be desirable to significantly heat the solvent in order to inject it as a vapor. Heating of injected vapor or liquid solvent may enhance production through mechanisms described by “Boberg, T. C. and Lantz, R. B., “Calculation of the production of a thermally stimulated well”, JPT, 1613-1623, December 1966. Towards the end of the injection period, a portion of the injected solvent, perhaps 25% or more, may become a liquid as pressure rises. After the targeted injection cycle volume of solvent is achieved, no special effort is made to maintain the injection pressure at the saturation conditions of the solvent, and liquefaction would occur through pressurization, not condensation. Downhole pressure gauges and/or reservoir simulation may be used to estimate the phase of the solvent and other co-injectants at downhole conditions and in the reservoir. A reservoir simulation may be carried out using a reservoir simulator, a software program for mathematically modeling the phase and flow behavior of fluids in an underground reservoir. Those skilled in the art understand how to use a reservoir simulator to determine if 25% of the injectant would be in the liquid phase immediately after the completion of an injection period. Those skilled in the art may rely on measurements recorded using a downhole pressure gauge in order to increase the accuracy of a reservoir simulator. Alternatively, the downhole pressure gauge measurements may be used to directly make the determination without the use of reservoir simulation.
Although preferably a CSDRP is predominantly a non-thermal process in that heat is not used principally to reduce the viscosity of the viscous oil, the use of heat is not excluded. Heating may be beneficial to improve performance, improve process start-up, or provide flow assurance during production. For start-up, low-level heating (for example, less than 100° C.) may be appropriate. Low-level heating of the solvent prior to injection may also be performed to prevent hydrate formation in tubulars and in the reservoir. Heating to higher temperatures may benefit recovery. Two non-exclusive scenarios of injecting a heated solvent are as follows. In one scenario, vapor solvent would be injected and would condense before it reaches the bitumen. In another scenario, a vapor solvent would be injected at up to 200° C. and would become a supercritical fluid at downhole operating pressure.
Prior descriptions of CSDRPs have not described the use of at least one restriction duration, where injection is restricted, between two continuous injection periods for improving solvent efficiency. Therefore, prior descriptions have not discussed the volume of solvent to inject in a continuous injection period or the volume of solvent to inject during a restriction duration. These aspects of the cyclic process are considerations for improving oil recovery while achieving efficient use of solvent. To obtain a high OISR during a cycle, a significant portion of the solvent must contact viscous oil which has not been exposed to solvent in previous cycles and the mobilized mixture of solvent and oil must flow back to the well. The spatial distribution of the injected solvent may be difficult to ascertain without the use of expensive surveillance techniques such as seismic surveys, real time passive seismic monitoring and/or subsurface electrical resistivity imaging; and therefore methods for judging when solvent has mixed with viscous oil sufficiently to obtain an economic OISR and oil production rate are not readily available. Disclosed below are methods for estimating the optimal solvent injection volumes during continuous injection periods and restriction durations in each cycle.
Injection of a solvent-containing fluid into a well is the first step of a CSDRP and the rates and volumes of injected fluid are an integral part of any CSDRP. Note that, unlike thermal recovery methods where minimum injection rates are often specified to minimize wellbore heat loss, CSDRP injection rates may have considerable flexibility to either reduce and/or increase injection rate depending on specific reservoir conditions, in particular the level of reservoir depletion. Rate flexibility allows the operator to optimize the distribution of solvent among wells in order to balance field injection/production volumes and surface gathering system constraints. Three non-limiting options for determining the volume of solvent-containing injectant to inject are: a purely volume-based approach, a hybrid volume and pressure approach, and a purely pressure-based approach. Each of these three approaches are described below and referred to as A1, A2, and A3.
One method of managing fluid injection in a CSDRP is for the cumulative volume injected over all continuous injection periods in a given cycle to equal the net reservoir voidage resulting from previous injection and production cycles plus an additional volume, for example approximately 2-15%, or approximately 3-8% of the pore volume (PV) of the reservoir volume associated with the well pattern. In mathematical terms, the volume may be represented by:
V
INJECTANT
=V
VOIDAGE
+V
ADDITIONAL
One way to approximate the net in situ volume of fluids produced is to determine the total volume of non-solvent liquid hydrocarbon fractions and aqueous fractions produced minus the net injectant fractions produced. For example, in the case where 100% of the injectant is solvent and the reservoir contains only oil and water, an equation that represents the net in situ volume of fluids produced is,
V
VOIDAGE
=V
OIL
PRODUCED
+V
WATER
PRODUCED−(VSOLVENTINJECTED−VSOLVENTPRODUCED).
Estimates of the PV are the reservoir volume inside a unit cell of a repeating well pattern or the reservoir volume inside a minimum convex perimeter defined around a set of wells. Fluid volume may be calculated at in situ conditions, which take into account reservoir temperatures and pressures. If the application is for a single well, the “pore volume of the reservoir” is defined by an inferred drainage radius region around the well which is approximately equal to the distance that solvent fingers are expected to travel during the injection cycle (for example, about 30-200 m). Such a distance may be estimated by reservoir surveillance activities, reservoir simulation or reference to prior observed field performance. In this approach, the pore volume may be estimated by direct calculation using the estimated distance, and injection ceased when the associated injection volume (2-15% PV) has been reached.
The sum of the volume of solvent injected for each continuous injection period in a given cycle would be the cumulative volume of solvent injected in that cycle. To determine the volume of solvent injected in each continuous injection period, first the number of continuous injection periods in each cycle should be specified, for example, between 2 and 8 continuous injection periods could occur in each cycle. One method of determining the volume of solvent injected in each continuous injection period would then, for example, be to divide the additional injection volume by the number of continuous injection periods in that cycle and inject this volume into the reservoir during each continuous injection period, with the first continuous injection period in a cycle also injecting a volume equal to the net reservoir voidage resulting from previous injection and production cycles. Therefore, in this example, the first continuous injection period would inject a volume equal to the additional injection volume divided by the number of continuous injection periods in that cycle plus the net reservoir voidage resulting from previous injection and production cycles while each subsequent continuous injection period in that cycle would inject a volume equal to the additional injection volume divided by the number of continuous injection periods in that cycle.
The volume of solvent injected during each restriction duration should be less than the volume of solvent injected in each immediately previous continuous injection period. For example, the volume of solvent injected during each restriction duration could be approximately 0-25% of the volume of solvent injected during the previous continuous injection period.
Sometimes, it is challenging to define the “pore volume accessible to the well” because of geological heterogeneity or uncertainties in the distance the solvent fingers are expected to travel. The relative ease of pressure measurement and generally higher accuracy versus volumetric measurement may lead to a preference for pressure or hybrid pressure-volume methods.
Rather than estimating the net reservoir voidage resulting from previous injection and production cycles, it may be more practical to establish a primary threshold pressure which must be obtained during each continuous injection period before injecting a predetermined additional volume. For example in each continuous injection period a primary threshold pressure would be achieved and the solvent volume injected after achieving said threshold pressure could be determined, as in the previous example, by dividing the cumulative additional volume of solvent to be injected in the given cycle, approximately equal to 2-15% of the volume injected to reach the primary threshold pressure in the first continuous injection period in the given cycle, or 3-8% of the pore volume, by the number of continuous injection periods in the given cycle. The primary threshold pressure may have to be continually monitored and adjusted as the reservoir is depleted. In particular, the level of communication amongst adjacent wells may impact the ability to achieve a targeted primary threshold pressure.
As in A1, the volume of solvent injected during each restriction duration should be less than the volume of solvent injected in each immediately previous continuous injection period. For example, the volume of solvent injected during each restriction duration could be approximately 0-25% of the volume of solvent injected during the previous continuous injection period.
An alternative to a volume-based scheme is one based on pressure measurements. In this approach, the solvent injection in each continuous injection period continues until an approximately predetermined time after the injection pressure during said injection period first passes from less than to greater than a designated primary threshold injection pressure. In some cases, it may be desirable to continue injection past the primary threshold pressure for only a minimal amount of time before switching to the restriction duration. In other cases, it may be desirable to switch to the restriction duration once the primary threshold pressure is met.
As in A1, the volume of solvent injected during each restriction duration should be less than the volume of solvent injected in each immediately previous continuous injection period. In one embodiment, for example, the volume of solvent injected during each restriction duration could be approximately 0-25% of the volume of solvent injected during the previous continuous injection period. In another embodiment, for example, the volume of solvent injected during each restriction duration could be designed to maintain the injection pressure above a secondary threshold pressure, which is not necessarily different from the primary threshold pressure.
In one embodiment, in both the volume-pressure hybrid and pressure-only approaches, the designated primary and secondary threshold injection pressures are pressures close to but below fracture pressure, for example above 90% of fracture pressure, or above 80% of fracture pressure, or above 95% of fracture pressure. In one embodiment, the primary and secondary threshold injection pressures are pressures within 1 MPa of, and below, the fracture pressure. As used herein, “fracture pressure” is the pressure at which injection fluids will cause the formation to fracture. In one embodiment, the secondary threshold injection pressure is below the primary threshold injection pressure, for example within 1 MPa of, and below, the primary threshold pressure, or within 6 MPa of, and below, the primary threshold pressure, or within 2 MPa of, and below, the primary threshold pressure.
In unconsolidated formations, it is also desirable that the primary threshold injection pressure be above the dilation pressure of the formation. As used herein, “dilation pressure” refers to the onset of in-elastic dilation, the yielding of the geo-materials, or the onset of non-linear elastic deformation. As used herein, “geomechanical formation dilation” means the tendency of a geomechanical formation to dilate as the pore pressure is raised towards the formation minimum in-situ stress, typically by injecting a liquid or a gas.
The formation in situ stress can be determined in a well test in which water is injected into the formation at high rates while bottom-hole pressure response is recorded. Alternatively, the stress may be measured during the first cycle injection of solvent. Analysis of the pressure response would reveal the conditions at which formation failure occurs (the pressure at which the in situ stress is exceeded). As used herein, “Pore fluid compression” means compression of a pore fluid by pressure. In the field, the operator can obtain pore fluid compression by multiplying pressure increase by fluid compressibility, which is a fluid property measurable in laboratory tests by procedures known to those skilled in the art. Pore dilation refers to dilation of pores in rock or soil. However, it may also be desirable for the primary threshold pressure to be close to or at the fracture pressure or be below the dilation pressure, depending on the specific reservoir characteristics and overall depletion plan. The benefits of reaching fracture pressure or being below dilation pressure are discussed below.
Either a volume of solvent is injected (204) or injection continues until the designated primary threshold pressure is achieved (206). The fluid volume (204) is the approximate net in situ volume of fluids produced in a previous cycle or cycles. Where the pressure is raised to the designated primary threshold pressure (206), either an additional volume of solvent is injected (208) (e.g. about 2-15% of the net in situ volume of fluids produced from the previous cycle or about 3-8% of PV divided by the number of continuous injection periods as described above) or injection continues for an additional amount of time (210), after which the number of continuous injection periods in the cycle is compared with the desired total number of continuous injection periods in the cycle (212). If the number of continuous injection periods equals the desired number of continuous injection periods in a cycle, injection ceases (218). If the number of continuous injection periods in the cycle is less than the desired number of continuous injection periods in the cycle, the process enters the restriction duration. In the restriction duration step, either a net volume of solvent is injected which is less than that injected in the previous continuous injection period (e.g., 0-25% of the net volume of solvent injected in the previous continuous injection period) (214) or solvent is injected to maintain an injection pressure above a secondary threshold pressure (e.g., between 6 MPa below the primary threshold pressure up to the primary threshold pressure) for an additional amount of time (216), after which the process enters the continuous solvent injection period (208) or (210).
Optionally, there is a soak period (220) of a flexible duration depending on overall depletion plan before production (222) begins. If the oil rate is not too low (224) and if the gas rate is not too high (226), production continues. If the oil rate is too low (224) or if the gas rate is too high (226), production is stopped (228) and an assessment is made as to whether the next cycle will be economic (230). If the next cycle will be economic, another cycle begins with fluid injection (202). If the next cycle will not be economic, additional oil may be recovered by other means (232), described below. Alternatively, the well may be produced at the lowest achievable (blowdown) pressure (234), and an assessment is made as to whether continued production will be economic (236). If it will not be economic, the well may be suspended or abandoned (238). If it will be economic, production at blowdown pressure is continued or reused as per the specific depletion plan (i.e. recompleted to different hydrocarbon interval or converted to an alternative service such as dedicated injection or disposal). Production at blowdown pressure is continued if deemed to be economic (234).
As discussed above, it may also be desirable in some situations for the primary threshold pressure to be about equal to the fracture pressure or be below the dilation pressure.
The above discussion details applying restriction durations throughout the injection cycle to improve mixing of solvent and oil in a given well drainage area. As an alternative to injection rate restriction, it may be advantageous to deliberately reduce the reservoir pressure in the vicinity of the injection well. This pressure reduction would reverse flow direction of a portion of the injectant back towards the injection well. The purpose of this flowback is to enhance solvent-oil mixing and reduce the average distance solvent travels from the well during an injection period. One embodiment of the flowback would be a fixed volume targeted to comprise a low amount of viscous oil that would likely not be sufficient for sales processing. The flow reversal in the injection well vicinity may also alleviate or mitigate near well permeability impairments from any undesirable solids contamination in the injectant. An example field deployment would be the installation of a surge tank at surface. The surface storage would allow injected fluids to flow back into the well and be stored in the surge tank before reestablishing injection. The reinjection of flowback viscous oil may have the added benefit of a viscosifier to the injected solvent stream. In this example, practical size constraints of the surge tank defines the fixed volume of the flowback and therefore may limit injection cycles interrupted by periodic surge flowbacks to only the early cycles of CSDRP for maximum effectiveness. An alternative to an installed surge tank would be flowback of a solvent rich stream to feed the injection stream into an adjacent well. This would require additional process piping and perhaps booster pumps but eliminates or mitigates any surface storage. Note that employing an injection strategy with periodic surge flowback does not alter the total solvent volume of fluid injected in the cycle. Therefore, providing the targeted cycle injection volume for an economic production cycle. In the following sections, the expression “restriction duration” is assumed to encompass an option for a surge flowback.
Regardless of the particular volume injected, the instantaneous injection rate need not be constant throughout the injection of the volume in a given cycle or from continuous injection period to continuous injection period or from restriction duration to restriction duration. In certain reservoir conditions affecting the fluid injectivity, tailoring the injection rate throughout the cycle volume may enhance solvent conformance. Rate control provides the practitioner with a means of optimizing oil production by designed solvent conformance for the given target reservoir.
During injection, solvent can finger into the reservoir in fine fingers due to the adverse mobility contrast between the injected solvent and in situ oil. Too severe of fingering can result in poor sweep of the reservoir and poor recovery of solvent in a given cycle, and thus poor recovery of oil and inefficient solvent utilization. It is preferred that the solvent injected in each cycle be utilized as efficiently as possible in reducing the viscosity of in situ oil and allowing the maximum amount of oil to flow back to the production well in the minimum time. Therefore, maintaining solvent in contact with in situ oil in a zone near enough to the production well to allow the in situ oil to be produced in a timely fashion is important in a CSDRP. Without intending to be bound by theory, introducing restriction durations between continuous injection periods is thought to allow solvent to stay in contact with in situ oil in a more desirable zone. It is thought that restriction durations, where the injection rates and volumes are significantly reduced below those in the immediately preceding continuous injection period, allow for solvent fingers to spread in directions that are not necessarily collinear with the direction of primary finger growth by means of the pressure gradient between solvent and the surrounding in situ fluids as well as countercurrent, gravity mixing as well as diffusion among other physical phenomena. This finger spreading results in a thicker zone of lower viscosity fluid. Upon switching back to a continuous injection period, it is thought that the solvent fingers will conform more to the solvent influenced, thicker zones due to the reduced viscosity contrast between the injectant and solvent influenced zone, keeping a larger fraction of solvent in a more favorable location, closer to the production well where the contacted in situ oil can be efficiently produced in the same cycle as demonstrated in the modeled example discussed below. As discussed previously, the periodic surge flowback to reverse flow direction in solvent fingers may assist finger spreading and further ensure injected solvent is closer to the production well.
In one embodiment, the amount of time for each continuous injection period after the first injection period is constant and specified, for example 1 day or 6 hours or 3 days. The amount of time for the first continuous injection period is the amount of time required to inject the net reservoir voidage resulting from previous injection and production cycles plus a specified period, where the specified period, for example is 1 day or 6 hours, or 3 days. In one embodiment, the amount of time in a given cycle of each continuous injection period, after a cumulative cycle volume equal to the net reservoir voidage resulting from previous injection and production cycles has been injected, increases for each subsequent injection period. For example, for an injection cycle with 3 continuous injection periods, the amounts of time, after a cumulative cycle volume equal to the net reservoir voidage resulting from previous injection and production cycles has been injected, for the first, second, and third continuous injection periods are 1 day, 2 days, and 3 days respectively.
In one embodiment, the amount of time for each restriction duration is constant and specified, for example 1 day, 6 hours, or 3 days. In one embodiment, the amount of time for each restriction duration is greater than the amount of time for the immediately previous continuous injection period measured after a cumulative cycle volume equal to the net reservoir voidage resulting from previous injection and production cycles has been injected, for example for a continuous injection period of 1 day after a cumulative cycle volume equal to the net reservoir voidage resulting from previous injection and production cycles has been injected the amount of time for the restriction duration could be 1.01 days, 3 days, or 2 days. In one embodiment, the amount of time for each restriction duration is more than twice the amount of time for the immediately previous continuous injection period measured after a cumulative cycle volume equal to the net reservoir voidage resulting from previous injection and production cycles has been injected, for example for a continuous injection period of 1 day after a cumulative cycle volume equal to the net reservoir voidage resulting from previous injection and production cycles has been injected the amount of time for the restriction duration could be 3 days or 2 days. The duration of time for a restriction duration and the period of time for a continuous injection period can be determined a number of ways including methods based on computational reservoir simulation, methods based on field measurements of bottom hole pressure, produced fluid composition, produced fluid rate, injection pressure, or injection rate, or methods based on analytical scaling arguments.
In one embodiment, the injection pressure can be monitored to determine the amount of time for each restriction duration. By reducing or halting the injection rate the injection pressure will decline as the pressure in the finger network leaks off to the formation matrix. A threshold pressure drop and/or rate of pressure decline can be specified to optimally control the restriction duration to enhance mixing of solvent and oil. The threshold pressure drop and/or rate of pressure decline can be derived by reservoir simulation, experimental measurements or observed field performance in similar well operations either in the same formation or in an analogous formation.
Regardless of the producing pressure of a well, if the production phase of a cycle is too short, a disproportionate amount of solvent-rich fluid near the wellbore is produced during the cycle, resulting in a low oil production rate and perhaps an uneconomic process. If the production phase continues for too long, the oil rate declines to a low level resulting in delay of the next cycle of oil production due to delay in the next cycle of solvent injection. Two criteria are used to judge the end of the production phase of a cycle: a low oil rate criterion and a high gas rate criterion. Note that unlike thermal recovery methods where production performance has a time dependency due to cooling, CSDRP performance is expected to be relatively unaffected by short production cycle and/or large delays in solvent injection; this offers the operator significant depletion plan flexibility. For example, CSDRP operation cycle length can be adapted to unusual market conditions such as commodity price fluctuations in order to maximize economic performance.
If a low oil rate criterion is used, production is halted when the oil production rate falls to a specified percentage of the average rate obtained during a cycle, for example a value between 60% and 90%. Such a cutoff generally allows production of the majority of mobilized heavy oil from cyclic solvent injection and halts the production when the rate is about equal to or somewhat below the expected average rate over the next cycle, resulting in minimum oil production deferral. This is shown in scheme 3B of
Alternatively, production may be halted if the current oil rate falls to less than a predetermined percentage (e.g. 30%, or 20 to 40%) of the maximum oil rate for the cycle. Those skilled in the art will recognize that there are many equivalent criteria for stopping oil production. For example, fractions or percentages of the calendar day oil rate (CDOR), or fractions or percentages of a running average. CDOR is the total oil produced during an injection/production cycle divided by the number of days since injection began.
Also, if the oil rate is too low (314) based on the oil measurement (307), production may be stopped. In viscous oil recovery processes, gravity is often a significant mechanism for moving oil towards the well. Processes with significant contribution from gravity are often slow and production for a lengthy period of time at a low rate may be necessary, especially in later cycles. Correspondingly, an absolute rate cutoff (314) could be low, especially in later cycles.
Production at low pressure (i.e. pressure less than the bubble-point of the native fluid or injected fluid) may cause excessive gas-phase production and cause difficulties in artificial lift performance and/or production gathering facilities operation. High gas rates may significantly degrade oil recovery performance and efficient use of injected solvent. To mitigate these effects, in addition to the rate-based production stop criterion discussed above, the production may also be halted due to the produced gas rate or an estimated downhole gas rate exceeding a specified value.
In
After production halts due to at least criterion being met, a determination is made whether or not another cycle would be economic (224, see
All criteria for ceasing production and switching to injection discussed thus far have applied to all cycles and use data measured in the oilfield. Reservoir surveillance activities and numerical simulation programs provide another tool for developing optimal production rate cutoff criteria on a cycle-by-cycle basis. One method of optimization is to simulate a CSDRP and then choose switch points where the production rate meets the criteria discussed above. This simulation may be updated based on actual field performance data. The anticipated production rate for the next cycle can be estimated using reservoir simulation using the existing production data. Alternatively, collection of historical production data through reservoir surveillance can lead to development of empirical performance curves whereby historical performance of mature wells is used to predict performance of similar wells yet to be drilled and/or in early state of depletion. Reservoir surveillance, numerical simulation studies, and evolving geologic understanding may improve field depletion strategies.
In a CSDRP embodiment (particularly a CSP™ process) as described in Canadian Patent No. 2,349,234 (Lim et al.), a well typically produces at a bottomhole pressure low enough to result in solvent vaporization and the formation of a secondary gas cap. However, such low pressures may not be preferred, especially in early cycles. There are several potential advantages to operating above such low pressures. First, solvent vaporization may necessitate increased facilities costs to handle the produced gas as well as necessitate complex solvent management strategies to efficiently satisfy the highly dynamic solvent requirements. Moreover, some solvent blends may introduce additional facilities and operational complexities due to their tendency to enter the reservoir at low pressures and as a multi-phase fluid. Finally, solvent vaporization may result in hydrate formation in some reservoirs, requiring the injected solvent to be heated prior to injection.
In one disclosed embodiment, a method involves injecting solvent into an underground reservoir in a liquid state and producing at a bottomhole pressure above the bubble point of the injected solvent. Producing at bottomhole pressures above the bubble point of the solvent results primarily in the production of the viscous oil and the solvent in the liquid phase, potentially eliminating, or reducing, the need for additional costs associated with gas handling facilities. Since operating at production pressures above the solvent bubble point does not create as large of a pressure drop as operating below the bubble point, it is may be preferred to operate at a higher cycle frequency to maintain acceptable recovery rates of the viscous oil. The potential advantage of more rapid cycling is that most portions of the reservoir in which the in situ fluids have been displaced remain filled with liquid solvent, reducing the volume of solvent injected during a cycle compared to previous CSDRP strategies at a given volume of viscous oil produced. This technique potentially reduces the complexities of solvent management as well as storage and facilities costs. In addition, operation above the bubble point pressure of the solvent eliminates, or reduces, the challenges associated with multi-phase injection. One challenge for multiphase injection is that it may require more complex or costly pumping equipment than single-phase injection.
A well's production rate may be constrained by facility design and artificial lift capacity. If the well is producing at lower than its maximum production rate, the producing pressure may be progressively lowered until it reaches some minimum threshold pressure or the maximum design production capacity is achieved. The bottomhole pressure of the well may be controlled by means of choking flow to keep the bottomhole pressure above a specified producing pressure, for example, 300-1000 kPa. The minimum producing pressure controls whether or not the produced fluid is produced primarily as a liquid or primarily as a gas. In one embodiment, the minimum pressure is less than the vapor pressure of the produced fluid, causing the production of a principally gaseous fluid. In an alternative embodiment, the minimum pressure is above the vapor pressure of the produced fluid, causing the produced fluid to be produced primarily as a liquid.
In addition to a low oil production rate, it may be important to set an absolute minimum to the producing bottomhole pressure, especially if gas production presents operational difficulties. A low pressure may lead to too much gas production and a high pressure may leave behind producible oil. In some embodiments the bottomhole-producing pressure of the well is between 500 and 1500 kPa. These values are specific to a reservoir in Cold Lake, Alberta, and are based on depth, reservoir temperature, and injectant composition. The particular choice of bottomhole pressure is depth, reservoir temperature, and injectant composition dependant.
A two-dimensional, fine grid reservoir simulation model was built with geological and geomechanical properties representative of shallow in-situ bitumen deposits in a subterranean reservoir (11° API) near Cold Lake. The solvent was modeled as propane. In this model, solvent was injected for a continuous injection period, as in (208) of
A series of three-dimensional reservoir simulation models were built with similar properties to the 2D model but with larger grids. A CSDRP was simulated using these models according to the cycle strategy outlined in
As is evident from Table 1, using the method shown in
Table 2 outlines the operating ranges for CSDRPs of some embodiments. The present invention is not intended to be limited by such operating ranges.
In Table 2, embodiments may be formed by combining two or more parameters and, for brevity and clarity, each of these combinations will not be individually listed.
In the context of this specification, diluent means a liquid compound that can be used to dilute the solvent and can be used to manipulate the viscosity of any resulting solvent-bitumen mixture. By such manipulation of the viscosity of the solvent-bitumen (and diluent) mixture, the invasion, mobility, and distribution of solvent in the reservoir can be controlled so as to increase viscous oil production.
The diluent is typically a viscous hydrocarbon liquid, especially a C4 to C20 hydrocarbon, or mixture thereof, is commonly locally produced and is typically used to thin bitumen to pipeline specifications. Pentane, hexane, and heptane are commonly components of such diluents. Bitumen itself can be used to modify the viscosity of the injected fluid, often in conjunction with ethane solvent.
In certain embodiments, the diluent may have an average initial boiling point close to the boiling point of pentane (36° C.) or hexane (69° C.) though the average boiling point (defined further below) may change with reuse as the mix changes (some of the solvent originating among the recovered viscous oil fractions). Preferably, more than 50% by weight of the diluent has an average boiling point lower than the boiling point of decane (174° C.). More preferably, more than 75% by weight, especially more than 80% by weight, and particularly more than 90% by weight of the diluent, has an average boiling point between the boiling point of pentane and the boiling point of decane. In further preferred embodiments, the diluent has an average boiling point close to the boiling point of hexane (69° C.) or heptane (98° C.), or even water (100° C.).
In additional embodiments, more than 50% by weight of the diluent (particularly more than 75% or 80% by weight and especially more than 90% by weight) has a boiling point between the boiling points of pentane and decane. In other embodiments, more than 50% by weight of the diluent has a boiling point between the boiling points of hexane (69° C.) and nonane (151° C.), particularly between the boiling points of heptane (98° C.) and octane (126° C.).
By average boiling point of the diluent, we mean the boiling point of the diluent remaining after half (by weight) of a starting amount of diluent has been boiled off as defined by ASTM D 2887 (1997), for example. The average boiling point can be determined by gas chromatographic methods or more tediously by distillation. Boiling points are defined as the boiling points at atmospheric pressure.
The at least one restriction duration may be for a longer time than at least one of the two continuous injection periods. The at least one restriction duration may be for a predetermined duration of time greater than 4 hours. The at least one restriction duration may be for at least twice as long a time as at least one of the two continuous injection periods. The at least one of the two continuous injection periods may be predetermined periods of time greater than 4 hours.
A peak injection rate during at least one of the two continuous injection periods may be at least 4 times (or at least 10 times, or at least 100 times) greater than an average injection rate during the at least one restriction duration.
An average injection rate during at least one of the two continuous injection periods may be at least 4 times (or at least 10 times, or at least 100 times) greater than an average injection rate during the at least one restriction duration.
A volume of solvent injected during the at least one restriction duration may be 0-25% of a volume of solvent injected during at least one of the two continuous injection periods.
Step (a) may comprise alternating between continuous injection periods and restriction durations. The at least one restriction duration may comprise ceasing injection.
In at least one cycle, an in situ volume of fluid injected in steps (a) to (c) may be equal to a net in situ volume of fluids produced from the production well in an immediately preceding cycle plus an additional volume of fluid.
At least one of the two continuous injection periods may be for a predetermined period of time after an estimated bottomhole pressure reaches a primary threshold pressure. The at least one restriction duration may be for a predetermined duration of time after an estimated bottomhole pressure reaches a secondary threshold pressure.
At least one restriction duration may be determined by a time required to inject a predetermined volume of fluid after an estimated bottomhole pressure reaches a secondary threshold pressure. At least one of the two continuous injection periods may be determined by a time required to inject a predetermined volume of fluid after an estimated bottomhole pressure reaches a primary threshold pressure. At least one of the two continuous injection periods may be determined by a time required to inject a predetermined volume of fluid after an injection rate reaches a target injection rate.
The at least one restriction duration may be 1 to 9 restriction durations.
One or each of the two continuous injection periods may be greater than 1 hour and less than 10 days, or greater than 6 hours and less than 72 hours.
The at least one restriction duration may be greater than 1 hour and less than 10 days, or greater than 6 hours and less than 72 hours.
A duration of time for the at least one restriction duration may be determined by a time required for an estimated bottomhole pressure to drop to a secondary threshold pressure.
An injection pressure during the at least one restriction duration may be equal to a secondary threshold pressure above an initial reservoir pressure.
The method may be operated using a plurality of wells, each undergoing the cycles of injection and production according to substantially the same schedule.
The injection well and the production well may utilize a common wellbore.
The hydrocarbons may be a viscous oil having a viscosity of at least 10 cP at initial reservoir conditions.
The solvent may comprise, ethane, propane, butane, pentane, carbon dioxide, or a combination thereof.
The injected fluid may comprise diesel, viscous oil, natural gas, bitumen, diluent, C5+ hydrocarbons, ketones, alcohols, non-condensable gas, water, biodegradable solid particles, salt, water soluble solid particles, solvent soluble solid particles, or a combination thereof.
The injected fluid may comprise at least 25 mass % liquid at the end of an injection cycle. The injected fluid may comprise less than 50 mass % solid at the end of an injection cycle.
At least 75 mass % of fluid injected in a solid phase may transition to a liquid phase by the end of a subsequent production cycle. At least 75 mass % of fluid injected in a solid phase may dissolve into a liquid phase by the end of a subsequent production cycle.
During an injection cycle, the phase of the injected fluid entering the reservoir may transition from greater than 75 mass % in the vapor phase to greater than 75 mass % in the liquid phase.
During an injection cycle, the phase of the injected fluid entering the reservoir may alternate between greater than 75 mass % in the vapor phase to greater than 75 mass % in the liquid phase.
The injected fluid may be heated such that it is injected into the underground reservoir at a temperature greater than 20° C.
At least 25 mass % of the solvent in an injection cycle may enter the reservoir as a liquid. At least 25 mass % of the solvent at the end of an injection cycle may be a liquid.
An in situ volume of fluid injected over a cycle may be equal to a net in situ volume of fluids produced from the production well summed over all preceding cycles plus an additional in situ volume of fluid.
The additional in situ volume of fluid may be, at reservoir conditions, equal to 2% to 15% of a pore volume within the reservoir zone around the injection well within which solvent fingers are expected to travel during the cycle.
The injected fluid may comprises a diesel, viscous oil, bitumen, or diluent to increase the viscosity of the injected fluid.
In the preceding description, for purposes of explanation, numerous details are set forth in order to provide a thorough understanding of the embodiments of the invention. However, it will be apparent to one skilled in the art that these specific details are not required in order to practice the invention.
The above-described embodiments of the invention are intended to be examples only. Alterations, modifications and variations can be effected to the particular embodiments by those of skill in the art without departing from the scope of the invention, which is defined solely by the claims appended hereto.
| Number | Date | Country | Kind |
|---|---|---|---|
| 2,734,170 | Mar 2011 | CA | national |
