Method for Determining Injector Bottom Hole Pressure in a Hydrocarbon Recovery Operation Using Liner-Deployed Outflow Control Devices

The present disclosure claims priority from U.S. Provisional Patent Appl. No. 63/648,535, filed on May 16, 2024, entitled “METHOD FOR DETERMINING INJECTOR BOTTOM HOLE PRESSURE IN A HYDROCARBON RECOVERY OPERATION USING LINER-DEPLOYED OUTFLOW CONTROL DEVICES,” herein incorporated by reference in its entirety.

The present disclosure relates to thermal recovery methods for heavy hydrocarbon reservoirs, and more particularly to determining an optimized steam injection flowrate.

It is known in the art of hydrocarbon recovery to employ certain enhanced oil recovery techniques for a hydrocarbon resource that is not recoverable in whole or in part by conventional primary recovery methods. For example, heavy hydrocarbons such as bitumen under normal reservoir conditions do not flow to a well for production to surface, and often require heating which can be achieved in many cases by injection of steam (with or without additives such as solvents).

Cyclic steam stimulation (CSS) and steam-assisted gravity drainage (SAGD) are common types of thermal recovery methods applied to heavy hydrocarbon resources. In the case of CSS, steam is injected downhole through a well, the well is shut-in for some period of time (a “soak” period) to allow the steam to heat the resource and mobilize it, and the now-mobilized hydrocarbon is then pumped to surface through the same well. In SAGD there are typically two wells—an injector well and a producer well—which are drilled down to the reservoir and then commonly extend generally horizontally through the target reservoir area, the injector well drilled near but above the producer well. Steam is injected through the injector well into the reservoir, mobilizing the hydrocarbon resource, and the mobilized hydrocarbon then flows downwardly toward the underlying producer well by gravity where the mobilized hydrocarbon is lifted to surface, using artificial lifting technologies such as electrical submersible pumps (ESPs).

One of the main operational limitations when injecting steam into a reservoir is the maximum operating pressure (MOP) for the reservoir, which cannot be exceeded under applicable industry regulations to avoid cap rock failure and uncontrolled release of reservoir fluids. A higher steam flowrate leads to increased pressure in the reservoir over time; if the pressure approaches MOP, the steam flowrate must be limited (therefore a reduced steam injection with impact on hydrocarbon production). Shallow reservoirs have a lower MOP given their proximity to the surface, and this severely limits the ability to inject steam since such recovery operations are necessarily operated very close to MOP. For perspective, the MOP in a typical heavy hydrocarbon reservoir may be around 9000 kPa, while in shallow reservoirs it may be around 1700 kPa. Although the risk of exceeding MOP may be higher for shallow reservoirs, this risk also exists and is important in deeper wells-every well has an MOP that must not be exceeded, with a potential negative impact on steam injection and hydrocarbon recovery. Note that this is during the SAGD phase of the well's life, usually during the circulation and ramp up phase, and there is a regulatory exception to temporarily increase the MOP to allow for well startup.

Outflow control devices (OCDs) are known for use in SAGD injector wells to control injection of steam into the reservoir and they provide well-known advantages. Two known OCD deployment systems for use in SAGD operations are the liner-deployed outflow control device (LDOCD) in which the OCDs are deployed in the liner (part of the well casing), and the tubing-deployed outflow control device (TDOCD) where a tubing string is run inside the casing/liner and the tubing houses the OCDs. In a prior art system using TDOCD where tubing is used to deliver the steam, there is an annular space between the tubing and the liner with pressure equalized between the annular space and the reservoir (see); this allows for more accurate injector bottom hole pressure (IBHP) estimation, and the operator can more confidently inject steam to the maximum operating pressure (MOP) of the reservoir. LDOCD systems, however, do not have an annular space (there is no tubing, the steam being injected directly into the liner; see), so the reservoir pressure is often necessarily overestimated for safety reasons and lack of direct estimation or measurement. The steam injection allowance is thus underestimated, reducing potential hydrocarbon production, leading to an inefficient resource utilization.

The surface measurement of pressure is commonly but not exclusively the wellhead pressure (WHP), which measurement by pressure gauges at the wellhead indicates steam pressure but does not take into account the significant downhole pressure losses along the liner including the OCDs. For TDOCD, a surface blanket gas measurement is equivalent to the pressure in the annular space which is in equilibrium with the injector bottomhole pressure (IBHP), and so the operator can more confidently determine whether the MOP is being reached. For LDOCD, there is no annular space, and therefore the blanket gas measurement and the WHP measurement are equal to the steam pressure; the steam pressure is always equal to or greater than the IBHP. Since the only instrumentation that measures pressure is for WHP or blanket gas pressure, it is always an overestimate of IBHP, and it is a significant overestimate where a correction is essential (especially in shallow reservoirs, where minimal steam can be injected, since even a small steam flowrate will show a WHP>>MOP, and the WHP is larger than the IBHP). The flow of steam through the OCDs causes a pressure drop which must be overcome to allow steam introduction to the reservoir, which biases the IBHP determination upward; any steam flowrate above zero will reduce the operating margin with respect to the MOP, under prior art methods. Any steam flow (or fluid flow in general) will create a pressure drop as it flows through a pipe and/or a restriction, such as the OCDs. Steam flow through the injector well causes a pressure drop due to frictional losses. The WHP incorporates the pressure drop (dP) such that the WHP is less than the MOP. This means that the steam flowrate would be limited in order to reduce the pressure drop (dP) to ensure the WHP<MOP. In general, for well productivity it is desirable to operate at higher pressures because it allows the reservoir to be at a higher temperature and enhance heavy hydrocarbon production. It is also desirable to maintain the reservoir pressure, so higher steam flowrates are needed. Therefore, a correction that accounts for the pressure drop and determines the IBHP would allow one to increase steam injection while still being under the MOP.

Notwithstanding the foregoing, the use of LDOCDs would have numerous benefits over the use of TDOCDs, including a substantial cost savings. Cost reduction is driven by lower material costs and drilling and completion operational costs (cement, labour, rig time, etc.). For example, in addition to savings on the tubing on the LDOCD, in a TDOCD system the tubing may be only 4.5″ in diameter—to provide the same hydraulics as a LDOCD, this might need to be increased to 7″, and the subsequent liner diameter increased even further. The smaller diameter leads to higher frictional losses, which consequently leads to a higher pressure drop across the lateral section of the well. Due to the higher pressure drop, it becomes infeasible at the given pressures to drill potentially longer wells. Therefore, LDOCDs allow for longer wells which are more capital/resource efficient. As part of the sustainability goals is the efficient use of resource reducing the footprint and production intensity (per barrel of bitumen produced). If we upsize a TDOCD to have comparable hydraulics to LDOCD, it would have a larger surface footprint while drilling, making the drilling process less sustainable and more difficult.

SAGD operations in reservoirs must operate below MOP, and while this is a factor in all reservoirs the MOP is even lower in shallow reservoirs. This is a regulatory requirement to avoid fracturing the cap rock and creating an uncontrolled release from the reservoir. The use of LDOCDs would present advantages in such SAGD operations but their use is hampered by the inability under prior art techniques to accurately determine or predict the IBHP to maintain operations below MOP. Being able to operate at higher reservoir pressures and steam flowrates when using LDOCDs would be enabled by a method of estimating the true reservoir pressure (the IBHP), allowing the operation to achieve higher production rates, steam efficiency, capital efficiency, and per well net present values (NPVs).

According to a first broad aspect of the present disclosure, there is provided a method for determining bottom hole pressure for a steam injection well used in hydrocarbon recovery, the steam injection well configured to introduce steam to a subsurface reservoir containing hydrocarbon, wherein a downhole liner of the well is provided with at least one liner-deployed outflow control device for introducing the steam to the reservoir, the steam injection well further provided with (i) a valve at surface for controlling steam flowrate into the well, (ii) a meter at the surface for measuring the steam flowrate, and (iii) a gauge at the surface for measuring pressure upstream of the at least one liner-deployed outflow control device, the method comprising the steps of:

The actual bottom hole pressure can then be more confidently determined based on the determined bottom hole pressure.

In some exemplary embodiments, the pressure measured at the surface is wellhead pressure, although blanket gas pressure could also be measured at the surface. For liner-deployed outflow control devices, the wellhead pressure and the blanket gas pressure are approximately equal.

In some exemplary embodiments of the first broad aspect of the present disclosure, the shut-in period is sufficient to allow the pressure measured by the gauge to reach equilibrium with the bottom hole pressure.

The steam injection well is preferably but not necessarily an injector well of a steam-assisted gravity drainage well pair.

Some exemplary embodiments further comprise operating the valve at step c. at a variety of valve positions to implement a range of steam flowrates including the at least one shut-in, and measuring the pressure for each of the variety of valve positions. The valve positions are preferably but not necessarily maintained for at least 15 minutes. The variety of valve settings preferably ranges from 0% to a selected maximum steam flowrate.

The at least one shut-in is preferably achieved by operating the valve at step c. to between a full shut-in (0%) and a partial shut-in (5%) valve position. In a full shut-in there is minimal steam flowrate at or close to zero, resulting in a negligible pressure drop, while for a partial shut-in (5% or “trickle flow”) there is minimal steam flowrate with a very small pressure drop.

Exemplary methods may further comprise monitoring for changes in the determined bottom hole pressure.

Exemplary methods further comprise the step of, in response to a determined bottom hole pressure exceeding a maximum operating pressure for the reservoir, operating the valve to reduce the steam flowrate.

Step c. preferably comprises at least two shut-ins.

According to a second broad aspect of the present disclosure, there is provided a method for predicting bottom hole pressure for a steam injection well used in hydrocarbon recovery for a range of steam flowrate values, the steam injection well configured to introduce steam to a subsurface reservoir containing hydrocarbon, wherein a downhole liner of the well is provided with at least one liner-deployed outflow control device for introducing the steam to the reservoir, the steam injection well further provided with (i) a valve at surface for controlling steam flowrate into the well, (ii) a meter at the surface for measuring the steam flowrate, and (iii) a gauge at the surface for measuring pressure upstream of the at least one liner-deployed outflow control device, the method comprising the steps of:

The bottom hole pressure can then be more confidently determined based on the determined bottom hole pressure for various steam flowrate values within the range. This method can be used for a plurality of steam injection wells, where each well would have a unique best fit model and resultant parameters.

In some exemplary embodiments, the pressure measured at the surface is wellhead pressure, although blanket gas pressure could also be measured at the surface. For liner-deployed outflow control devices, the wellhead pressure and the blanket gas pressure are approximately equal.

In some exemplary embodiments of the second broad aspect of the present disclosure, the shut-in period is sufficient to allow the pressure to reach equilibrium with the bottom hole pressure.

The at least one shut-in is achieved by operating the valve at step d. to between a full shut-in (0%) and a partial shut-in (5%) valve position.

Exemplary methods preferably further comprise the step of, in response to a determined bottom hole pressure exceeding a maximum operating pressure for the reservoir, operating the valve to reduce the steam flowrate.

Step d. preferably comprises at least two shut-ins. In some such cases, the determined bottom hole pressures for the at least two shut-ins are averaged to arrive at the average determined bottom hole pressure for the pressure drop calculation of step g.

In some exemplary embodiments the plurality of selected values ranges from 0% to a selected maximum steam flowrate.

Each of the steam flowrate values is preferably a valve position.

In some exemplary embodiments, step h. comprises the best fit model being a line of best fit defining a linear relationship between the pressure drop and the steam flowrate. In some such cases with a linear relationship, the parameters could be slope and intercept of the line of best fit.

Some exemplary embodiments comprise identifying a maximum steam flowrate by determining where the polynomial relationship breaks down. In some such embodiments, a maximum steam flowrate can also be determined as an upper boundary for the best fit model. To determine the maximum steam flowrate for a particular steam injection well, the steam flowrate is varied upwardly and the pressure measured until the steam flowrate increases without significant pressure increases indicating failure of the polynomial relationship, in what is called “choked flow”. By this method, the parameters and the maximum steam flowrate can be determined for a given well. In some exemplary embodiments where the relationship is linear, a method to detect the transition from linear domain to non-linear domain may be used to determine the maximum flowrate.

In some exemplary embodiments, the above method for predicting the bottom hole pressure for the steam injection well for a range of steam flowrate values can be automated using a programmable logic controller (PLC) or similar platform located at the well pad. In some embodiments, the PLC receives the measured steam flowrate from the meter and the measured pressure from the gauge, plots the points and generates the best fit model, and derives the parameters for the best fit model, and performs the required verifications and validations (pre- and post-processing of the data).

A detailed description of exemplary embodiments of the present disclosure is given in the following. It is to be understood, however, that the disclosure is not to be construed as being limited to these embodiments. The exemplary embodiments are directed to particular applications of the present disclosure, while it will be clear to those skilled in the art that the present disclosure has applicability beyond the exemplary embodiments set forth herein.

Exemplary embodiments will now be described with reference to the accompanying drawings.

Throughout the following description, specific details are set forth in order to provide a more thorough understanding to persons skilled in the art. However, well known elements may not have been shown or described in detail to avoid unnecessarily obscuring the disclosure. The following description of examples of the present disclosure is not intended to be exhaustive or to limit the disclosure to the precise form of any exemplary embodiment. Accordingly, the description and drawings are to be regarded in an illustrative, rather than a restrictive, sense.

The present disclosure is directed to methods for determining bottom hole pressure for a steam injection well used in hydrocarbon recovery operations, such as for example a SAGD operation, and in particular to such operations where the steam injection well does not house injection tubing but comprises liner-deployed outflow control devices for introducing steam to the reservoir.

The present disclosure uses LDOCDs and employs regular injection well shut-in periods (during which the steam valve position is preferably reduced to 0-5%, with little to no fluid flow through the injection well), which allows pressure to equalize or approach equalization between the wellhead and the reservoir after some period of time required for the blanket gas pressure (measured as WHP) to be in or approach equilibrium steady state with the reservoir pressure. When flow through the OCDs is nearly or fully stopped, since the pressure loss through the OCDs is proportional to flow, then the measured wellhead pressure will eventually become an accurate estimation of reservoir pressure after accounting for static pressure. This process is a first order process and requires time to achieve steady state, on the order of at least 15-45 minutes. This determined IBHP method is preferably also used in order to calibrate and validate a model that can be used for continuous monitoring/prediction. Input data may be continuously collected (not just during shut-in periods) as steam flowrate is varied, and adjusted for pressure loss by using the output of the model so there is a means to estimate the IBHP regularly and monitor for pressure changes during operations. By achieving a better IBHP estimate, LDOCDs can be employed instead of TDOCDs and steam injection can be optimized (allowing the operator to run at higher steam rates and reservoir pressures) and thus enhance well productivity. Using LDOCDs instead of TDOCDs, cost savings, higher steam qualities, longer wells, and other advantages may be achieved.

While full equalization of the WHP and IBHP is most desirable during the shut-in periods, it has been found that it can sometimes take 2.5 hours or more for the WHP to decay to the correct IBHP value. Due to risks in thermal cycling, the exemplary embodiments disclosed herein use 15-minute shut-ins to generate the IBHP ground truth value. This necessarily biases the ground truth values with approximately 50 kPa of positive error, resulting in the model overestimating IBHP by that amount but building in a conservative margin within the model.

In addition to a method for determining IBHP from a data collection process involving shut-in periods and pressure equilibrium, a further desired end is to be able to construct predictive models that may in some embodiments facilitate automated estimation of IBHP at various steam flowrates and thus the allowable IBHP (dependent on steam injection) to remain below MOP. A simpler construct is to have an automated estimation of the pressure drop (ΔP, between the well head and the reservoir), which models can then be used to estimate an IBHP for each well.

ΔP (the pressure drop across the whole liner including OCDs) between WHP and IBHP (essentially the difference between surface and reservoir pressures) is relatively large, as illustrated in, and so an accurate IBHP measurement or determination/prediction is required to help ensure maximum hydrocarbon recovery rate but while not exceeding the MOP-exceeding can overpressure the reservoir rock and overlying cap rock.

In one exemplary method, the valve is adjusted to allow injection of the steam downwardly through the well to the liner, and the steam flowrate and WHP are measured (using the meter and the gauge, respectively). A data collection plan is employed to run the operation through a plurality of valve settings including one or more 0-5% shut-in periods.illustrates one exemplary data collection plan. The operator (or potentially the process is automated, as described below) uses the valve to systematically vary the steam flowrate according to the data collection plan. In the illustrated data collection plan, each step of the process is greater than 15 minutes. In the steps where steam valve position is reduced to 0-5%, the selected time period should be chosen to allow sufficient time for pressure equilibrium to be achieved between the wellhead and the injector bottom hole (reservoir), which has been found to be 15-45 minutes in some contexts (although in some cases, as noted above, full equalization may require a significantly longer period). The steam flowrate is systematically varied from a selected maximum value to zero and then back to the maximum, while only measuring steam flowrate at surface and WHP. The steam flowrate and WHP are measured continuously at surface for every well, resulting in a unique data set for each well.

In the exemplary data collection plan as shown in, the maximum steam flowrate is 50 t/hr, with a minimum measurable steam flowrate of 10 t/hr; these values are exemplary only, provided solely to illustrate embodiments of the present disclosure. There are two shut-in valve positions that are employed at the noted stages during data collection: 0% steam flowrate (full shut-in) and 5% steam flowrate (so-called “trickle flow” steam flowrate). The 5% steam flowrate may offer greater operational sustainability, as it mitigates the risk of pipe freezing and obviates the necessity for pipe drainage procedures, but the efficacy depends on several factors including line pressure and steam properties (depending on these variables, a 5% valve position may still permit a substantial steam flow, thereby preventing the WHP from equilibrating with the reservoir pressure) as would be clear to those skilled in the art.

Following are the exemplary embodiment plan details:

While the above method may be sufficient to determine an IBHP from the data collection plan including shut-in periods, the data collection plan may also be used as the basis for predicting IBHP for a variety of steam flowrate values in a specific well.

A further exemplary method is for predicting bottom hole pressure for a steam injection well, using the same data collection plan described above. As with the above exemplary method, the valve is opened to allow steam injection to the liner, and the steam flowrate and WHP are measured (by the meter and gauge, respectively). The steam flowrate is varied through a plurality of selected values using the valve, including at least one shut-in period (0-5% steam valve position). The steam flowrate and WHP are measured for each of the selected steam flowrate values, with a time period for the shut-ins sufficient to reduce the WHP to approach the IBHP or even allow equilibrium to occur between the WHP and the IBHP, by which the IBHP can be determined for the 0-5% valve position(s), as described above.

In this further exemplary method, an average steam flowrate and an average wellhead pressure are then determined for the measured steam flowrate and the measured wellhead pressure for each of the plurality of selected values (valve positions). The exemplary data collection process generates data that can be presented in a chart such as, which illustrates data for a sample well. The chart shows steam flowrate and WHP as a function of valve position over time. It can be seen that during the shut-in periods the curves drop to zero flowrate, 0% or 5% valve position, and WHP drops to an equilibrium steady state IBHP (determined IBHP). For each of the steps in the data collection process, which are shown as curve maximums and minimums (square steps) in, the steam flowrate and WHP can be averaged to arrive at an average steam flow rate and an average WHP for each step.

Next, a pressure drop is calculated for each of the plurality of selected values. First, all of the determined bottom hole pressure determinations for the plurality of shut-in periods (0-5% valve positions) are averaged to arrive at a single average IBHP value for the specific well. For one non-limiting example, you may have the following: IBHP at 0%=3499 kPa, and at 5%=3501 kPa, resulting in an average IBHP of 3500 kPa. Second, a pressure drop (WHP minus average IBHP value) is calculated for each of the plurality of selected steam flowrate values. For example, if there is a steam flowrate of 50t/h and the WHP is 4000 kPa, then the pressure drop is 4000 kPa-3500 kPa=500 kPa. If there is a steam flowrate of 35 t/h and the WHP is 3700 kPa, then the pressure drop is 3700 kPa-3500 kPa=200 kPa. This calculation would be repeated for all the other combinations of WHP and steam flowrate, resulting in a set of matched pressure drops and average steam flowrates.

The pressure drops and average steam flowrates can then be plotted on a chart, such as the exemplary. In, each of the points are plotted on a graph of pressure drop (kPa) against average steam flowrate (t/h). Once the points have been plotted for each of the selected steam flowrate values, it becomes clear that there is a polynomial relationship, and specifically in this embodiment a linear relationship, between pressure drop and average steam flowrate, and a best fit model (in this embodiment a line of best fit) can be generated for the points defining the polynomial relationship between the pressure drop and the average steam flowrate for that well. As can be seen in, plotted points and a line of best fit are shown for six steam injection wells, and all manifest a polynomial relationship. Other fitting methods were tested such as exponential and logarithmic, but polynomial (and specifically linear) was selected due to its simplicity. For linear fit, three techniques were tested based on how the intercept (c) of the linear model is determined, and the techniques are described below and shown in:

is a diagram showing qualitative representations of the three techniques (labeled 1, 2, 3). The best technique is technique 1 (labeled 1) based on the data collected, as technique 1 fits the data in the operational domain better.

Given the linear relationship in this embodiment and the ability to then generate a line of best fit for the points derived from the data collection process for a steam injection well, one can further derive a slope and intercept from the line of best fit.is a table showing the derived slope and intercept (and a coefficient of correlation) for each of the six sample wells.

Now that the line of best fit has been generated to allow definition of the linear relationship between pressure drop and average steam flowrate for a specific steam injection well, one can use the derived slope and intercept to predict or model an IBHP (steady state response) for any steam flowrate and WHP for the specific steam injection well: