Patent Application
20240401451
Not applicable.
The invention relates to petroleum production—in particular to methods for producing heavy oil and/or bitumen with steam and solvent in a manner so as to eliminate gas interference with an electric submersible pump (ESP). More particularly, it relates to a strategy for injecting solvent to varying positions along the well length, to minimize solvent short circuiting and gas locking of the pump, which otherwise reduces emulsion intake and therefore lower oil production rates.
Production of heavy oil and bitumen from a subsurface reservoir can be quite challenging. The initial viscosity of the oil at reservoir temperature is often greater than five million centipoise (cP), and because of its thickness and immobility, cannot be pumped to the surface. Thus, it must be either mined from the surface or treated in situ to make it pumpable. Since only a relatively small percentage—about 3% —of bitumen and oil sand deposits (such as the Athabasca oils sands of Alberta, Canada) are recoverable through open-pit mining, the majority of heavy oils require some form of in situ treatment to mobilize the oil, such as heating the oil with steam by the means of heat conduction or thinning it with solvents by the means of convection.
Steam-assisted gravity drainage (SAGD) is an in-situ method of thinning oil with steam heat that was first introduced by Roger Butler in 1973 as a means of producing viscous oils and is now widely used for recovery of heavy and extra-heavy oil. Traditional SAGD uses two parallel horizontal wells (see
In a pre-production stage, steam is injected into both wells to conductively heat the petroleum deposit between the wells until the two wells are in fluid communication. This stage—known as start-up—can take on the order of 3-6 months in a typical Athabasca oil sands reservoir. While steam injection is the most common method of start-up, there are other methods, and the operator is not limited to steam.
Once the wells are in fluid communication, the lower well is converted over to oil production by changing the completion from injection to production. During the SAGD stage, steam is injected only into the top horizontal well (injection well) and the heated oil and any condensed water are produced by gravity drainage to the lower horizontal well (production well). The heated oil and water emulsion is now pumpable, and is typically brought to the surface with a sucker rod pump or an electric submersible pump (ESP).
SAGD requires on-site steam generation and water treatment, translating into expensive surface facilities. SAGD is also very energy intensive, largely because the reservoir rock and fluids must be heated enough to mobilize the petroleum deposit, but heat is lost to overburden and underburden, to water and gas intervals, and to the non-productive rock. On average, a third of the energy is produced back with fluids in the reservoir, a third is lost to overburden and underburden, and a third is left behind in the reservoir after abandonment. These inefficiencies result in a steam-to-oil ratio (SOR) of 3.0 (vol/vol), and a 50-60% recovery factor of the original bitumen contacted by steam. That is for every barrel of oil produced, three barrels of water must be heated to make steam and only about half the oil can be produced. To compound these inefficiencies, heavy oil and bitumen are sold at significant discounts compared to oil product benchmarks, such as West Texas Intermediate (WTI) due to an additional dilution requirement in order to transport the otherwise viscous product.
All of these factors provide an exceedingly challenging economic environment for producing heavy oil. Thus, there have been many efforts to increase SAGD efficiency and/or reduce costs. This is especially true late in the life cycle of a SAGD well, when the SOR begins to increase, and the costs correspondingly increase with the increased steam usage.
One possible strategy is to replace or supplement steam with a solvent, which can be recycled, or a non-condensable gas (NCG), which helps to maintain pressure and may provide some degree of solvation. Many researchers are therefore looking for ways to optimize steam and/or solvent/NCG production methods in order to produce heavy oils and bitumen as cost effectively and efficiently as possible, and the patent literature is replete with variations on these ideas, including changing the well arrangement, changing solvents or combinations thereof, changing solvent to steam ratios, changing the timing, and the like.
While many patents call for solvent or gas injection in order to reduce the SOR of SAGD, one common problem with this solution is gas interference with the ESP. When solvent is being co-injected during SAGD, it is injected in the gaseous phase. If injected in liquid phase, that fluid will tend to drain by gravity towards the producing well without the opportunity to grow the chamber. Thus, gaseous injection is required for an economic and environmentally friendly recovery scheme where the least amount of solvent and steam is injected to grow the chamber.
Steam, as an example, is injected into the reservoir at 2.5 mPa above 240° C. This temperature allows the operator to avoid water injection. At the same pressure of 2.5 mPa, a solvent such as butane should be injected around 150° C. and solvent propane should be injected above 75° C. If the solvents are being injected at any condition residing on the left side of the vapor pressure curve (see
However, as the well starts producing, gaseous solvent (known as “gas slugs”) can be drawn into the fluid mix. Because ESP systems generate lift by pushing fluid through stages, when gas slugs enter the pump, it disrupts the flow of fluid to the surface. Artificial lift engineers have developed technologies over the years to reinforce the ESP's ability to handle gas production, including ESP gas separators, helicoaxial stages, and tapered pump configurations. Whenever possible, however, the operator's best chance to eliminate gas-related setbacks is to prevent gas from entering the pump altogether. Usually, this means injecting more steam to counteract the gas interference, the additional fluid protecting the pump by lifting the fluid levels. However, this solution increases the SOR, contributing to cost.
Thus, what is needed in the art are methods of mitigating gas interference with the ESP. The ideal method will not contribute to SOR, nor increase costs associated with additional completion or cumulative solvent injection rates. This invention meets one or more of these needs.
The invention generally relates to methods to decrease, if not eliminate, gas interference at the pump when injecting gas such as NCG or solvents, such as CO2, CH4, ethane, propane, butane, or mixtures thereof into a reservoir. Described simply, the method involves providing the injection well with both toe and heel tubings (and possibly one or more points therebetween), so that the heated solvent can preferentially be injected towards the toe and further away from the ESP. Customized allocation of solvent injected based on gas lock frequency events can be implemented once a threshold is met for increased gas lock events and reduced oil production rates, wherein the solvent can be allocated to be injected preferentially at the toe or toe and midway.
The invention includes any one or more of the following embodiment(s) in any combination(s) thereof.
As used herein a “toe-dominant” solvent injection means that more solvent is injected at the toe than at the heel. Steam may be co-injected therewith and steam levels need not equate to solvent levels. Thus, steam can be evenly injected along well length and solvent toe-dominant, or steam can also be toe-dominant at the same or different levels than the solvent.
The “toe” of a well is its termination point in the reservoir. The “heel” is where the well turns from horizontal to vertical. The ESP is typically at or near the heel of a producer.
An “ESP” is an electric downhole pump used in heavy oil production that is designed with vane and fin configurations to accommodate frictional losses and pump inefficiencies caused by heavy oil viscosity. It is a multistage centrifugal type pump that accomplishes fluid lift by imparting kinetic energy to the fluid by centrifugal force and then converting that to a potential energy in the form of pressure.
By injecting “steam only,” we mean no NCG or solvent is intentionally injected thereinto. Minor contaminants to the steam are excluded from consideration, however, and include any contaminants in the water used to make the steam, entrained gases, and the like. Likewise, co-injecting only steam and solvent means that other fluids are not intentionally added.
“Solvent” herein can include hydrocarbon solvents and non-condensable gases, or anything else injected in the gaseous phase that is prone to gas locking the ESP.
“Hydrocarbon solvent” refers to a chemical consisting of carbon and hydrogen atoms which is added to oil to increase its fluidity and/or decrease viscosity. A hydrocarbon solvent, for example, can be added to a fossil fuel deposit, such as a heavy oil deposit or bitumen, to partially or completely dissolve the material, thereby lowering its viscosity and allowing recovery. The hydrocarbon solvent can have, for example, 1 to 8 carbon atoms (C1-C8), 1-4 carbons (C1-C4), or preferably 1-2 (C1-C2) or 3-4 carbons (C3-C4) herein.
“Non-condensable gases” or “NCGs” are gases from chemical or petroleum processing units (such as distillation columns or steam ejectors) that are not easily condensed by cooling at reservoir conditions. Examples of suitable NCGs for solvent assisted recovery processes include, but are not limited to, carbon dioxide (CO2), carbon monoxide (CO), nitrogen (N2), methane, ethane, ethylene, nitrogen oxides (NOx), sulfur oxides (SOx), flue gas, and the like, or combinations thereof. CO2 maybe preferred as a means of sequestering carbon in the reservoir, methane may be preferred where readily available onsite or nearby, or flue gas from local engine use is another preferred option, especially flue gas from a direct steam generator.
“Flue gas” or “combustion gas” refers to an exhaust gas from a combustion process that typically exits to the atmosphere via a pipe or channel. Flue gas typically comprises nitrogen, CO2, water vapor, oxygen, CO, nitrogen oxides (NOx) and sulfur oxides (SOx). The combustion gases can be obtained by direct steam generation (DSG), reducing the steam-oil ratio and improving economic recovery.
“Formation” or “reservoir” as used herein refers to a geological structure, that includes one or more hydrocarbon-containing layers, possibly one or more non-hydrocarbon layers, an overburden and/or an underburden. The hydrocarbon layers can contain non-hydrocarbon material as well as hydrocarbon material. The overburden and underburden can contain one or more different types of impermeable materials, for example rock, shale, mudstone wet carbonate, or tight carbonate.
“Petroleum deposit” or “play” refers to an assemblage of hydrocarbons in a geological formation. The petroleum deposit can comprise light and heavy crude oils, natural gas, and bitumen. Of particular interest for the method described herein are petroleum deposits that are primarily heavy oil and bitumen.
“Heavy oil” as used herein is intended to include heavy, extra heavy and bitumen hydrocarbons. A heavy crude is in the 15-25 API range. Anything below 15 API would be considered an extra-heavy crude.
“Steam-assisted gravity drainage” or “SAGD” refers to an in-situ recovery method which uses steam and gravity drainage to produce oil from a traditional parallel horizontal well-pair with about 4-5 meters vertical separation and minimal lateral separation, and generally as described by Butler in U.S. Pat. No. 4,314,485. Such a well-pair may be called a “gravity drainage well-pair” or “SAGD well-pair” and there are variations on the arrangement of such well-pairs beyond the traditional SAGD well-pair, any of which may be used in the invention.
A “SAGD well-pair” or a “well-pair” refers to traditional horizontal parallel wells where the producer is low in the play and the injector is usually 4-5 meters above it. Other wells arrangements are possible in SAGD variants, however. Well-pairs are typically provided in an “array” to cover a play, and infill wells may be added between well-pairs later in the lifecycle of a producing well-pair.
Generally speaking, an injector in a well-pair is roughly “over” the producer, but some leeway in placement is typical as perfect control of drilling is difficult. Further, in some SAGD variants, their placement may vary.
“SAGD variants” includes all SAGD related or modified processes such as steam-assisted gravity push (SAGP), single-well SAGD, expanding solvent-SAGD (ES-SAGD), cross well SAGD (X-SAGD), varying well placement methods, and the like, as well as the original SAGD method, so long as both steam heating and gravity drainage are employed as the dominant driver of production.
In steam-assisted gravity push or “SAGP” the SAGD process be modified by injecting an NCG, such as natural gas, with the steam. Gas accumulates in the chamber above the injector, lowers the temperature there and provides some insulating effect. In addition, the gas helps to maintain pressure and reduce the SOR.
In expanding solvent-SAGD or “ES-SAGD” (also known as solvent assisted SAGD or SA-SAGD), a hydrocarbon additive at low concentration (1-5 vol % solvent) is co-injected with steam in a gravity-dominated process, similar to the SAGD process. The hydrocarbon additive is selected in such a way that it would evaporate and condense at the same conditions as the water phase.
Rich Solvent-SAGD or “RS-SAGD” is similar to ES-SAGD but the solvent content is >60 vol %.
Vapor Assisted Petroleum Extraction or “VAPEX” is a non-thermal vapor extraction (VAPEX) closely related to SAGD. However, in the VAPEX process the steam chamber is replaced with a chamber containing light hydrocarbon vapors close to the dew point at the reservoir pressure. The injected solvent vapor expands and dilutes the heavy oil by contact, which then drains by gravity to the lower horizontal production well to be produced.
The methods used herein can be applied to any oil production method that includes solvent/NCG injection or co-injection. Furthermore, although we tested the concept with steam/solvent co-injections, the same principles are predicted apply to gaseous solvent-only injections.
“Injection well” or “injector” refers to a well that is fitted (aka completed) for injection, and allows fluid injection into a reservoir. In a producing well-pair, it is typically 4-5 meters over a production well in a play, but may be closer in a thin play or in certain specialized well arrangements.
“Production well” or “producer” refers to a well that is fitted for production and is in and close to the bottom of a play and from which a produced fluid, such as heated heavy oil, is recovered from a geological formation. In SAGD and other gravity drainage processes, the well may be initially fitted for injection, then refitted for production once start-up is complete.
An “infill well” is a well low in the play situated between a conventional horizontal well-pair, and serves to catch oil trapped between the teardrop shaped steam/vapor chambers. These are usually drilled after the array of well-pairs have been produced to capture wedge oil that would otherwise be lost.
Although we discuss one or two horizontal well-pairs herein, it is understood that there may be an array of well-pairs covering a play, and that wells may also have multilateral wells branching off a mother well, or infill wells, as needed to effectively drain a play.
A “multilateral well” refers to a well, which is one of a plurality of horizontal branches, or “laterals”, from a mother wellbore. These branch off an existing well, called the “mother” well, and do not reach the surface or have their own well pad. An array of multilaterals off a single mother wellbore may be called a “fishbone.”
“Steam chamber”, “vapor chamber” or “steam vapor chamber” refers to the pocket or chamber of gas and vapor formed in a geological formation by a SAGD, ES-SAGD, SAGP, VAPEX and variant processes.
“Production” refers to extraction of petroleum from a petroleum deposit or hydrocarbon-containing layer within a geologic formation.
By “providing” a well or a well-pair we do not necessarily imply de novo drilling of wells, as it is possible to perform the inventive method in existing wells, though they may need to be refitted with dual or triple injection tubing.
“Start-up” refers to the process of putting two wells in a gravity-drainage well-pair into fluid communication and is a distinctive phase in a well-pair's lifespan. This is frequently done by injecting steam into both wells, but other methods are possible, including electric, RF or EM heating of wells, solvent-assisted start-up, dilation start-up, combustion-based methods, and the like, as well as combinations thereof.
“Wind-down” is another distinct phase in a well's producing life wherein production is slowed, and measures are taken, for example, to recover solvent from the reservoir. Wind-down is initiated when oil production is no longer economical, and thus may vary depending on oil prices. However, wind-down is typically initiated when the oil recovery factor reaches a specified threshold or if the SOR increases to high levels where steam could be redeployed elsewhere to operate at lower SOR conditions. When wind-down is complete, the well is shut-in, although it may be opened again when either new technology is developed or when the price of crude oil increases sufficiently.
The use of the word “a” or “an” when used in conjunction with the term “comprising” in the claims or the specification means one or more than one, unless the context dictates otherwise. The use of the term “or” in the claims is used to mean “and/or” unless explicitly indicated to refer to alternatives only or if the alternatives are mutually exclusive.
The term “about” means the stated value plus or minus the margin of error of measurement or plus or minus 10% if no method of measurement is indicated.
The terms “comprise”, “have”, “include” and “contain” (and their variants) are open-ended linking verbs and allow the addition of other elements when used in a claim. The phrase “consisting of” is closed, and excludes all additional elements. The phrase “consisting essentially of” excludes additional material elements, but allows the inclusions of non-material elements that do not substantially change the nature of the invention, such as varying well arrangements, varying completion parameters, inclusion of additives in the injection fluids, and the like. Any claim or claim element introduced with the open transition term “comprising,” may also be narrowed to use the phrases “consisting essentially of” or “consisting of,” and vice versa. However, the entirety of claim language is not repeated verbatim in the interest of brevity herein.
The following abbreviations or definitions are used herein:
The worst gas locking event can be seen in Box A, impacting oil production as the ESP slows down significantly resulting in increased subcool and slower oil production rates. The last 10 days on the chart are shown in Box B, where more steady temperatures are observed due to reallocation of the solvent/steam co-injection to the toe string. This solution as described herein, restored the temperature of the produced fluid, decreased the subcool and resulted in increased oil production rates.
The invention is a method of avoiding gas interference at the pump for any solvent injection based methods of producing heavy oil, including VAPEX, ES-SAGD, SAGP, Warm Applied Solvent Process (WASP), and any of the many variants thereof whenever a solvent, NCG, and/or steam is injected in gaseous form to produce heavy oil.
The challenge in any solvent injection process of producing oil is how to ensure that the impact on the ESP is minimal. The seismic graphs in
To mitigate this problem, we provide an injection completion 500A-C with at least 2 injection tubings, as shown in
In
With this type of injection completion, we can easily inject more steam/solvent at the toe than at the heel, thus obviating the gas locking problem. Ideally, the switch will be implemented when needed, as indicated by one or more indicators showing that gas locking is becoming problematic.
The graph in
The following 50 days shows a steam-solvent co-injection scheme. The steam injection rate in this case was 100 T/d and the solvent injection rate was 30 T/d, and the co-injection profile was 50/50 vol % between the short (heel) and long (toe) tubings (e.g., even injection). Here there was significant reduction in the associated pump speed and less oil and water emulsion being produced. The flow rate also went to zero at times (see spikes), in order to build the required liquid level “to fight” gaseous solvent short-circuiting towards the ESP.
In
We mitigated the gas interference by injecting an additional 50 T/d of steam to create more liquid level on top of the producing well to limit gas short-circuiting and limit gas locking events (data not shown). Although addressing gas interference, this solution resulted in an increased SOR, which is not advantageous to the recovery scheme when it comes to reducing emissions. In addition, the added steam could have been injected elsewhere to produce further oil and yield higher returns.
A better alternative solution to solve this problem is proposed in this disclosure by solvent portioning and customized reallocation towards the toe string on the solvent injection wt. % basis. This is shown in the last 10 days of
Thus, when gas locking becomes a problem, the injection strategy should be designed accordingly to limit gaseous solvent migration to the ESP by reducing the amount of solvent injected to the heel and increasing the solvent co-injection to the toe. An increase of solvent towards the toe could be required to maintain the pressure in the reservoir and continuing steam-solvent chamber development. The extra solvent allocated towards the toe will travel longer to reach the ESP and in the process more likely condense into the oleic phase, thereby limiting gas interference with the ESP function.
Therefore, the inventive method provides solvent co-injection mainly or only to the long string aka toe injection. The solvent will be able to further advance toe chamber development and migrate towards the ESP as the mid-section is being further developed and oil is being produced.
Preferably, the timing to invoke higher injection of the solvent at the toe will depend on the frequency of the gas short-circuiting events, as seen in
In addition to toe-dominant injections to limit gas locking, the pressure could also be higher at the toe, as the pressure drop at the heel will help avoid gas locking. For example, if 50/20 m3/d of steam/solvent is injected via the toe string and the same via the heel string, and gas locking begins to occur, an operator could decide to allocate 30/30 steam/solvent m3/d to be injected via the toe string and 30/10 steam/solvent m3/d to be injected via the heel string. This approach will create high pressure at the toe region of the reservoir and reduce the pressure at the heel region of the reservoir. This will also help to limit solvent short-circuiting from the heel region. Thus, it is also possible to have toe-dominant solvent injection with even steam injection.
The solvent injection rates could be intermittently reduced to zero to evaluate pressure response and restored with more solvent being injected at the toe to mitigate solvent short-circuiting at the heel.
Intentional subcool increase could be induced by slowing down the ESP speed to transition to solvent dominated toe injection and observe appropriate solvent injection rates to validate that the solvent is not being over injected and thus short-circuits without development the solvent/steam chamber which could be detrimental to the recovery scheme.
The above examples are exemplary only, and every reservoir may react differently to different injection fluids because they have a different oil profile, different porosity, different rock characteristics, etc. However, the general methodology may be applied to oil sands and other heavy or extra heavy reservoirs.
The following references are each incorporated by reference in their entireties for all purposes:
This application claims priority to U.S. Ser. No. 63/504,957, filed May 30, 2023 and incorporated by reference in its entirety for all purposes.
| Number | Date | Country | |
|---|---|---|---|
| 63504957 | May 2023 | US |
