QUANTIFICATION OF PRESSURE INTERFERENCE AMONG WELLS

Abstract

Quantification of pressure interference among wells in a well system is determined by determining a base productivity index for a target well in the well system. The base productivity index is free of interference on production through the target well from flow through other wells in the multiple wells. A current productivity index for the target well is determined. The current productivity index is affected by interference on production through the target well from flow through other wells in the multiple wells. An interference modulus is determined for the target well based on the current productivity index and the base productivity index for the target well. Using the interference modulus for the target well, an effect, such as a numerical value representing the effect, on the target well, of the simultaneous flow through the other wells in the multiple wells is determined.

Description

TECHNICAL FIELD

This disclosure describes computer-implemented methods, computer-readable storage media and computer systems relating to quantification of pressure interference among wells.

BACKGROUND

Hydrocarbon reservoirs are subsurface pools of porous or fractured rock formations containing hydrocarbons. Such deposits occur naturally over geologic times, and are trapped by overlaying impermeable rock formations. The potential of petroleum reservoir is identified by performing geophysical or seismic surveys to map and interpret the sedimentary facies and other geologic features. After identifying the hydrocarbons (e.g., oil, gas, combinations of them) reservoirs, wells are drilled to confirm and quantify the hydrocarbon pore volumes in such reservoirs. Transient well tests are usually performed in these wells to better understand the dynamic reservoir quality for future field development and well placement planning. Transient well tests are experiments performed on hydrocarbon and water wells under controlled environments for collecting transient-pressure data through gauges deployed downhole in the wells. The collected pressure data in combination with the fluid production or injection rates, and the rock and fluid properties is utilized to characterize the well and the intersected reservoir within the drainage area.

SUMMARY

This specification describes technologies relating to quantification of pressure interference among wells.

Certain aspects of the subject matter described here can be implemented as a method. A base productivity index for a target well is determined. The target well is included in a well system that includes multiple wells including the target well. The well system is drilled in a subterranean zone from a surface to a subsurface reservoir entrapping hydrocarbons. The base productivity index is based on reservoir pressure or its updated value and based on bottomhole pressure of the target well. The base productivity index is free of interference on production through the target well from flow through other wells in the multiple wells. A current productivity index for the target well is determined. The current productivity index is based on the reservoir pressure or its updated value and based on the bottomhole pressure of the target well. The current productivity index is affected by interference on production through the target well from flow through other wells in the multiple wells. An interference modulus is determined for the target well based on the current productivity index and the base productivity index for the target well. Using the interference modulus for the target well, an effect (e.g., a numerical value representing the effect), on the target well, of the flow through the other wells in the multiple wells is determined.

An aspect combinable with any other aspect includes the following features. Using sensors disposed within the target well, the reservoir pressure is measured before production through the target well is started. Using the sensors, the bottomhole pressure is measured after a volumetric flow rate through the target well has reached a pre-determined flow rate and immediately before the target well is shut in. The bottomhole pressure data can lead to determining the reservoir properties and to updating the reservoir pressure.

An aspect combinable with any other aspect includes the following features. The base productivity index is determined from a field buildup well test conducted in a field in which the multiple wells are drilled.

An aspect combinable with any other aspect includes the following features. The base productivity index is determined from an Earth numerical model that computationally simulates a field in which the multiple wells are drilled.

An aspect combinable with any other aspect includes the following features. The base productivity index and the current productivity index are each a productivity index, which is determined as explained here. Before producing through the target well, the reservoir pressure in the target well is measured. Hydrocarbons are produced through the target well until a volumetric flow rate through the target well stabilizes. The stabilized volumetric flow rate is measured. After the volumetric flow rate stabilizes, the bottomhole pressure in the target well is measured. After measuring the bottomhole pressure in the target well, the target well is shut in to determine the dynamic reservoir properties and the updated reservoir pressure.

An aspect combinable with any other aspect includes the following features. The productivity index is determined by dividing the stabilized volumetric flow rate by a difference between the reservoir pressure or its value and the bottomhole pressure.

An aspect combinable with any other aspect includes the following features. The interference modulus for the target well is determined by dividing the current productivity index by the base productivity index.

An aspect combinable with any other aspect includes the following features. To determine the numerical effect, on the target well, of the flow through the other wells in the multiple wells using the interference modulus for the target well includes one of the following. An increase in productivity of the target well is determined in response to determining that the interference modulus is greater than one. A decrease in the productivity of the target well is determined in response to determining that the interference modulus is less than one. An absence of a change in the productivity of the target well is determined in response to determining that the interference modulus is equal to one. Intermediate values of the interference modulus less than +1 and greater than +1 indicate corresponding intermediate effects on the productivity, of the target well, due to simultaneously flow through the other wells in the multiple wells.

Certain aspects of the subject matter described here can be implemented as a computer-readable storage medium storing computer instructions, which when executed by one or more computer systems (e.g., processor or processors) is configured to perform the following operations. For a target well in a well system including multiple wells including the target well, and in an absence of interference on production through the target well from flow through other wells in the multiple wells, the following are received—a first reservoir pressure in the target well before producing hydrocarbons through the target well; after producing hydrocarbons through the target well, a first stabilized volumetric flow rate of hydrocarbon production through the target well; before shutting in the target well, a first bottomhole pressure in the target well; after shutting in the target well, the first updated reservoir pressure. A base productivity index for the target well is determined using the first volumetric flow rate, the first reservoir pressure or its updated value and the first bottomhole pressure. A current productivity index for the target well is determined using the second volumetric flow rate, the second reservoir pressure or its updated value and the second bottomhole pressure. An interference modulus for the target well is determined from the current productivity index and the base productivity index. Using the interference modulus for the target well, an effect, on the target well, of the flow through the other wells in the multiple wells is determined. The interference modulus is provided.

An aspect combinable with any other aspect includes the following features. To determine the current productivity index, a ratio between the second volumetric flow rate and a difference between the second reservoir pressure or its updated value the second bottomhole pressure is determined.

An aspect combinable with any other aspect includes the following features. To determine the base productivity index, a ratio between the first volumetric flow rate and a difference between the first reservoir pressure or its updated value and the first bottomhole pressure is determined.

An aspect combinable with any other aspect includes the following features. To determine the interference modulus, a ratio between the current productivity index and the base productivity index is determined.

An aspect combinable with any other aspect includes the following features. To determine the numerical effect, on the target well, of the flow through the other wells in the multiple wells using the interference modulus for the target well includes one of the following. An increase in productivity of the target well is determined in response to determining that the interference modulus is greater than one. A decrease in the productivity of the target well is determined in response to determining that the interference modulus is less than one. An absence of a change in the productivity of the target well is determined in response to determining that the interference modulus is equal to one. Intermediate values of the interference modulus less than +1 and greater than +1 indicate corresponding intermediate effects on the productivity, of the target well, due to simultaneous flow through the other wells in the multiple wells.

An aspect combinable with any other aspect includes the following features. The first volumetric flow rate, the first reservoir pressure or its updated value, the second volumetric flow rate, the second reservoir pressure or its updated value and the second bottomhole pressure are determined from a field buildup test conducted in a field in which the multiple wells are drilled.

An aspect combinable with any other aspect includes the following features. The first volumetric flow rate and the first reservoir pressure or its updated value are determined from an Earth numerical model that computationally simulates a field in which the multiple wells are drilled.

The details of one or more implementations of the subject matter described in this specification are set forth in the accompanying drawings and the description below. Other features, aspects, and advantages of the subject matter will become apparent from the description, the drawings, and the claims.

BRIEF DESCRIPTION OF THE DRAWINGS

FIGS. 1A-1C each are schematic diagrams of well systems including multiple wells.

FIG. 2A is a schematic diagram of a producing well.

FIG. 2B is a plot showing parameters from a buildup test of the producing well of FIG. 2A.

FIG. 3 is a flowchart of an example of a process of quantifying pressure interference among wells in a well system.

FIG. 4 is an example of computed interference moduli under various well settings and placements.

FIG. 5 is a flowchart of an example of an interpretation of computed interference modulus.

FIG. 6 is a block diagram of an example computer system to implement the process of FIG. 3.

Like reference numbers and designations in the various drawings indicate like elements.

DETAILED DESCRIPTION

During field development and infill drilling, wells are drilled to withdraw the hydrocarbons from the reservoirs. Various well types, including vertical, horizontal, deviated and multi-lateral wells are used in the infill drilling based on the reservoir recovery to maximize the recovery. For example, multiple wells are drilled from the surface of the Earth to the subsurface reservoir, sometimes in a pattern chosen to optimize hydrocarbon production from the subsurface reservoir to the surface. Each well is designed to withdraw certain volume of hydrocarbons within its drainage area. Hydrocarbon flow through one well can affect (i.e., interfere with) hydrocarbon flow through one or more adjacent wells. The inter-well spacing usually takes into account the impact of such interference between the wells.

This disclosure describes methods (including computer-implemented methods), computer-readable storage media and computer systems that can be used to study the well-to-well pressure interference. More specifically, this disclosure describes quantification of the interference on well productivity in multi-well applications. The techniques described here can be implemented as a holistic approach for all kinds of fields or wells to quantify the impact of interference.

FIGS. 1A-1C each are schematic diagrams of well systems including multiple wells. For example, FIG. 1A is a well system that includes two wells (a first well 102A, a second well 102B), each drilled in a subterranean zone 104 (e.g., a formation, a portion of a formation, multiple formations) from the surface to a subsurface reservoir with hydrocarbons. The well drainage area 106 for the first well 102A is schematically shown by the circle 106 at a given time. A similar well drainage area is defined for the second well 102B as well. In the schematic shown in FIG. 1A, the two wells 102A and 102B are far enough apart such that the hydrocarbon flow (e.g., the production of hydrocarbons from the subsurface reservoir to the surface, an injection of water or other fluid from the surface towards the subsurface reservoir) in one well has no effect on the hydrocarbon flow in the other well at the same time. The absence of interference is schematically shown by an absence of intersection between the well drainage areas of the two wells in FIG. 1A.

FIG. 1B is a well system that includes two wells (a first well 102C, a second well 102D), each drilled in a subterranean zone 108 similar to the subterranean zone 104, from the surface to a subsurface reservoir with hydrocarbons. Similar to the well drainage area 106 for the first well 102A, respective well drainage areas are also defined for the two wells 102C and 102D at a given time. In the schematic shown in FIG. 1B, the two wells 102C and 102D are close enough that the hydrocarbon flow in one well affects (i.e., interferes with) the hydrocarbon flow in the other well at the same time. The interference is schematically shown by an intersection between the well drainage areas of the two wells in FIG. 1B.

FIG. 1C is a well system that includes two wells (a first well 102E, a second well 102D), each drilled in a subterranean zone 110 similar to the subterranean zones 104 and 108, from the surface to a subsurface reservoir with hydrocarbons. Similar to the well drainage area 106 for the first well 102A, respective well drainage areas are also defined for the two wells 102E and 102F at a given time. In the schematic shown in FIG. 1C, the two wells 102E and 102F are close enough that the hydrocarbon flow in one well affects (i.e., interferes with) the hydrocarbon flow in the other well. The interference is schematically shown by an intersection between the well drainage areas of the two wells at the same time. Specifically, an intersection between the well drainage areas of the two wells 102E and 102F is greater than that between the well drainage areas of the two wells 102C and 102D. The greater intersection indicates more interference in the well system shown in FIG. 1C compared to the interference in the well system shown in FIG. 1B. The increased interference is due, in part, to the wells 102E and 102F being closer to each other compared to the wells 102C and 102D. Another reason for the increased interference can be the greater connectivity between the wells through a set of favorable reservoir and fluid properties under in-situ conditions.

In some examples, a well system can include more than two wells (e.g., three, four, five, six or more wells) arranged in a pattern or no pattern. For example, a target well can be in a center of the pattern with multiple wells symmetrically (e.g., equidistantly) drilled surrounding the target well. In such examples, several factors affect the flow of hydrocarbons through the target well including, for example, pressure drops across each surrounding well, direction of fluid flow through each well, properties of the formation in which the well is drilled, a quantity of hydrocarbons in the reservoir to which each well in the well system extends, to name a few. This disclosure describes techniques to quantify an interference, on the target well, by other wells in the well system.

FIG. 2A is a schematic diagram of a producing well 200 drilled in a subterranean zone 202 from a surface to a subsurface reservoir. In some implementations, well sensors 206, e.g., pressure gauges, flow meters, and similar well sensors, can be installed within the well 200. The rate of production through a well at the surface conditions is sometimes measured by deploying a multi-phase flow meter at the surface. The producing well 200 can be one well in a well system that includes multiple wells, the rest of which are not shown in FIG. 2A. The producing well 200 can be a target well for which an interference from other wells in the well system is to be quantified. The quantification of interference is implemented by determining a productivity index of a target well (e.g., the producing well 200). The productivity index is a measure of the ability of a producing well to produce. The productivity index is determined by dividing the produced flow rate (q) by a well to the corresponding pressure drawdown, which is a difference between the reservoir pressure or its updated value (p_R) and the current bottom hole pressure (p_BH), and is shown in Equation 1.

$\begin{array}{cc}\mathrm{Productivity}\mathrm{Index}\left(\mathrm{PI}\right)=\frac{q}{p_R-p_{\mathrm{BH}}},\mathrm{STB}/D/\mathrm{psia}& \left[\mathrm{Eq}.1\right]\end{array}$

FIG. 2B is a plot showing parameters from a buildup test of the producing well 200. The buildup test is performed to determine the productivity index of a well. In particular, the buildup test is performed to determine the variables used to measure the productivity index using Equation 1. The plot in FIG. 2B shows time on the X-axis and, on the Y-axis, shows the production rate (q) and the transient bottomhole pressure (p). The buildup test is performed by measuring the bottomhole pressure at the producing well at a shut-in condition. The initial reservoir pressure (p_R), before production through the producing well 200 begins, may well be very close to the initial reservoir pressure if the volume of the produced fluid is negligible compared to the initial fluid volume in place. Otherwise, the persons skilled in the art can determine the updated reservoir pressure. Then, hydrocarbons are produced through the producing well 200 until the production rate, i.e., the volumetric flow rate of hydrocarbons through the producing well, stabilizes to the produced flow rate (q) in Equation 1. The produced flow rate can be a pre-determined flow rate, or can be a flow rate at which the time rate of change of the produced flow rate is zero or less than a threshold. The bottomhole pressure can be measured by one of the well sensors 206. The rate of production at surface conditions can be measured independent of the pressure measurement. The pressure drop across the producing well at the produced flow rate, i.e., the bottomhole pressure, p_BH, is measured, for example, by one of the well sensors 206 disposed in the well. Then, the producing well 200 is shut in, and the pressure builds up over time towards the reservoir pressure, p_R. The data of the buildup test during the well is shut in can be utilized to update the reservoir pressure.

To measure an effect (e.g., a numerical value representing the effect) of flow through the producing well 200 by flow through remaining wells in the well system, the productivity index is measured under two separate conditions. In the first condition, a base productivity index, which assumes no effect (i.e., no interference from) or flow through the remaining wells, is measured. In the second condition, a current productivity index, which assumes interference from the remaining wells, is measured. An interference modulus (Equation 2) is measured using the current productivity index and the base productivity index.

$\begin{array}{cc}\mathrm{Interference}\mathrm{Modulus}\left(\mathrm{IM}\right)=\frac{\mathrm{Productivity}{\mathrm{Index}}_{\mathrm{Current}}}{\mathrm{Productivity}{\mathrm{Index}}_{\mathrm{Base}}}& \left[\mathrm{Eq}.2\right]\end{array}$

The interference modulus is an indicator of the degree of positive or negative interference between wells in the well system based on the ratio between current productivity index and the base productivity index in the absence of interference.

In some implementations, the buildup test can be performed in a physical well that has been drilled in a field from a surface to the subsurface reservoir. In such implementations, the variables to determine the productivity index (Equation 1) and the interference modulus (Equation 2) can be physical measurements measured using well sensors installed within (or outside) the producing well 200 and the rate of production at surface conditions.

In some situations, however, the physical well may not be available for testing. For example, the well may not yet have been drilled in the field. Alternatively, if the well has been drilled, then well integrity restrictions may make the well unavailable for the test. In such situations, the productivity index can be numerically determined based on numerical model mimicking reservoir conditions. In such implementations, an Earth numerical model is built using reservoir and fluid properties, and such simulated properties can be used to determine the base productivity index in the absence of interference.

For example, the Earth model can be built based on seismic data, well logs petrophysical data and structure of the reservoir. Such data can be integrated into computational numerical modeling simulators with the pressure, temperature and fluid properties to mimic the reservoir behavior. The petrophysical data can be calibrated with dynamic data from wells to capture the dynamic behavior of the reservoir along the entire history life. Well test data is a reliable source of the data to be utilized for the calibration because of the wider radius of investigation. After the calibration process, the model can be used for both forecasting and optimizing the future infill drilling. Optimization of the inter-well interference is one of the applications of Earth modeling. Using such a model, the base productivity index can be determined by assigning production rates of the tested well keeping nearby wells inactive. The simulator can then be executed for a certain time to calculate the corresponding pressure behavior using the production rate and two points from the simulated pressure profile, reservoir pressure and bottomhole flowing pressure just before the shut in.

FIG. 3 is a flowchart of an example of a process 300 of quantifying pressure interference among wells in a well system. The process 300 can be computationally implemented using a computer system, e.g., the computer system 600 described with reference to FIG. 6. At 302, three measurements are received for a target well in a well system that includes multiple wells including a target well and in an absence of interference on production through the target well from flow through other wells in the well system. The three measurements include (i) a first reservoir pressure or its updated value in the target well before producing hydrocarbons through the target well, (ii) a first stabilized volumetric flow rate of hydrocarbon production through the target well after producing hydrocarbons through the target well, and (iii) a first bottomhole pressure in the target well before shutting in the target well. After the target well has been shut in, the bottomhole pressure increases with time, e.g., building up towards the first reservoir pressure. If the bottomhole pressure does not return to the first reservoir pressure, the first updated reservoir needs to be determined and used in computing the base productivity index.

At 304, the same three measurements are received for the target well, but this time in the presence of interference on production through the target well from flow through other wells in the well system, namely, (i) a second reservoir pressure or its updated value, (ii) a second stabilized volumetric flow rate, and (iii) a second bottomhole pressure. The second reservoir pressure may need to be updated based on the buildup test data. The interference can be, for example, due to hydrocarbon production through one or more or all of the other wells in the well system. Alternatively, the interference can be due to injection into one or more or all of the other wells in the well system. In a further alternative, the interference can be due to a combination of production through some and injection into some wells in the well system. In some implementations, interference can be due to flow through some, but not all, of the remaining wells in the well system.

At 306, a base productivity index is determined for the target well using the first volumetric flow rate, the first reservoir pressure or its updated value and the first bottomhole pressure. The base productivity index can be determined using Equation 3.

$\begin{array}{cc}\mathrm{Base}\mathrm{Productivity}\mathrm{Index}\left({\mathrm{PI}}_{\mathrm{Base}}\right)=\frac{\mathrm{Production}\mathrm{rates},\mathrm{STB}/D}{\mathrm{Pressure}\mathrm{drawdown},\mathrm{psia}}& \left[\mathrm{Eq}.3\right]\end{array}$

In Equation 3, the numerator is the first stabilized volumetric flow rate of hydrocarbon production through the target well after producing hydrocarbons through the target well. The denominator is a difference between the first reservoir pressure or its updated value and the first bottomhole pressure. The base productivity index is a measure of productivity of the target well in the absence of interference caused by flow through neighboring wells.

At 308, a current productivity index is determined for the target well using the second volumetric flow rate, the second reservoir pressure or its updated value and the second bottomhole pressure. The current productivity index can be determined using Equation 4.

$\begin{array}{cc}\mathrm{Current}\mathrm{Productivity}\mathrm{Index}\left({\mathrm{PI}}_{\mathrm{Current}}\right)=\frac{\mathrm{Production}\mathrm{rates},\mathrm{STB}/D}{\mathrm{Pressure}\mathrm{drawdown},\mathrm{psia}}& \left[\mathrm{Eq}.4\right]\end{array}$

In Equation 4, the numerator is the second stabilized volumetric flow rate of hydrocarbon production through the target well after producing hydrocarbons through the target well. The denominator is a difference between the second reservoir pressure or its updated value and the second bottomhole pressure. The current productivity index is a measure of productivity of the target well due to interference caused by flow through neighboring wells.

At 306, the base productivity index can be determined using the measurements received at step 302. At 308, the current productivity index can be determined using the measurements received at step 304. At 310, the interference modulus can be determined by dividing the current productivity index by the base productivity index. Examples of computed interference moduli under various well settings and placements are presented in FIG. 5

At 312, an effect (e.g., a numerical value representing or quantifying the effect) of interference on the target well productivity can be determined based on the interference modulus determined at step 310. An interference modulus less than one (1) indicates that the productivity through the target well is being negatively affected by simultaneous flow through one or more or all of the other wells in the well system. For example, concurrent production through one or more or other wells in the well system can be negatively affecting production through the target well. In such situations, production through one or more or all of the other wells can be modified (e.g., reduced) to improve productivity index for the target well. Alternatively or in addition, secondary recovery techniques including, for example, injecting fluid into one or more of the other wells, can be implemented to improve the productivity index for the target well. The interpretation at 312 is also summarized graphically with the process 500 shown in and described with reference to FIG. 5.

An interference modulus of one indicates that the productivity through the target well is unaffected by (i.e., is facing no interference from) flow through one or more or other wells in the well system. For example, concurrent production through one or more or all of the other wells in the well system has no effect on production through the target well. In such situations, production through the other wells can be maintained. Alternatively, in a situation in which fluid is being injected into one or more or all of the other wells to aid production through the target well, an interference modulus of one indicates that the injection is not aiding productivity of the target well as intended. Accordingly, injection operations in the well system can be modified or other secondary recovery techniques can be implemented in the target well.

An interference modulus greater than one indicates that the productivity through the target well is being positively affected by flow through one or more or all of the other wells in the well system. For example, an interference modulus greater than one can indicate that injection through one or more or all of the other wells in the well system is aiding hydrocarbon production through the target well or preserving reservoir energy by producing the target production rate with lower drawdown pressure. In such instances, the injection operations can be modified, e.g., optimized, to conserve resources spent to implement the injection operations. In the context of this disclosure, modification of well operations (e.g., injection operations) means adjusting a flow of well fluid flowed into or out of any of the wells in the well system.

In some implementations, the measurements to determine the base productivity index and the current productivity index can be determined in sequence, i.e., base productivity index variable measurements followed by current productivity index measurements. The base productivity index and the current productivity index can be determined in sequence or in parallel. In some implementations, the productivity indices and the interference moduli can be measured at multiple time instants over a duration to determine time profiles of the productivity indices. Determinations regarding modifying flow conditions through the wells in the well system can be made based on the quantified values of the productivity indices, interference moduli and time profiles.

FIG. 4 is an example of computed interference moduli. The bar graph in FIG. 4 shows multiple interference moduli values greater than 1 indicating gain in the well productivity due to the interference with injection wells. The bar graph in FIG. 4 also shows multiple interference moduli values less than 1 indicating a drop in the well productivity due to the interference among producers. The bar graph in FIG. 4 also shows a few instances of interference moduli equal to 1 indicating no interference.

FIG. 5 is a flowchart of an example of a process 500 of determining well productivity based on interference modulus. The process 500 can be implemented, for example, by the computer system 600 (FIG. 6). Having determined the current productivity index (Productivity Index Current) and the base productivity index (Productivity Index Base) by executing Equation 4 and Equation 3, respectively, at 502, the computer system 600 determines the interference modulus (IM) as a ratio of the current productivity index to the base productivity index. At 504, the computer system 600 checks if the IM is greater than 1. If the computer system 600 determines that the IM is greater than 1 (decision branch “Yes”), then a gain in target well productivity has been observed. For example, at 506, the computer system 600 transmits a notification indicating a gain in well productivity. If, at 504, the computer system 600 determines that the IM is not greater than 1 (decision branch “No”), then, at 508, the computer system 600 checks if the IM is less than 1. If the computer system determines that the IM is less than 1, then a drop in target well productivity has been observed. At 510, the computer system 510 transmits a notification indicating a drop in well productivity. If, at 508, the computer system 600 determines IM is not less than 1 (decision branch “No”), then, at 512, the computer system 600 checks if IM is equal to 1. If yes, then no gain or drop in target well productivity has been observed. For example, at 514, the computer system 600 transmits a notification indicating no gain or drop in well productivity. As described earlier, based on a received notification, a well operator can modify well operations, e.g., operate flow equipment to increase or decrease flow through remaining wells in the well system.

FIG. 6 is a block diagram of an example computer system 600 used to implement the process 300 and the process 500 in sequence. The computer system 600 can provide computational functionalities associated with described algorithms, methods, functions, processes, flows, and procedures described in the present disclosure, according to some implementations of the present disclosure. The illustrated computer 602 is intended to encompass any computing device such as a server, a desktop computer, a laptop/notebook computer, a wireless data port, a smart phone, a personal data assistant (PDA), a tablet computing device, or one or more processors within these devices, including physical instances, virtual instances, or both. The computer 602 can include input devices such as keypads, keyboards, and touch screens that can accept user information. Also, the computer 602 can include output devices that can convey information associated with the operation of the computer 602. The information can include digital data, visual data, audio information, or a combination of information. The information can be presented in a graphical user interface (UI) (or GUI).

The computer 602 can serve in a role as a client, a network component, a server, a database, a persistency, or components of a computer system for performing the subject matter described in the present disclosure. The illustrated computer 602 is communicably coupled with a network 630. In some implementations, one or more components of the computer 602 can be configured to operate within different environments, including cloud-computing-based environments, local environments, global environments, and combinations of environments.

At a top level, the computer 602 is an electronic computing device operable to receive, transmit, process, store, and manage data and information associated with the described subject matter. According to some implementations, the computer 602 can also include, or be communicably coupled with, an application server, an email server, a web server, a caching server, a streaming data server, or a combination of servers.

The computer 602 can receive requests over network 630 from a client application (for example, executing on another computer 602). The computer 602 can respond to the received requests by processing the received requests using software applications. Requests can also be sent to the computer 602 from internal users (for example, from a command console), external (or third) parties, automated applications, entities, individuals, systems, and computers.

Each of the components of the computer 602 can communicate using a system bus 603. In some implementations, any or all of the components of the computer 602, including hardware or software components, can interface with each other or the interface 604 (or a combination of both) over the system bus 603. Interfaces can use an application programming interface (API) 612, a service layer 613, or a combination of the API 612 and service layer 613. The API 612 can include specifications for routines, data structures, and object classes. The API 612 can be either computer-language independent or dependent. The API 612 can refer to a complete interface, a single function, or a set of APIs.

The service layer 613 can provide software services to the computer 602 and other components (whether illustrated or not) that are communicably coupled to the computer 602. The functionality of the computer 602 can be accessible for all service consumers using this service layer. Software services, such as those provided by the service layer 613, can provide reusable, defined functionalities through a defined interface. For example, the interface can be software written in JAVA, C++, or a language providing data in extensible markup language (XML) format. While illustrated as an integrated component of the computer 602, in alternative implementations, the API 612 or the service layer 613 can be stand-alone components in relation to other components of the computer 602 and other components communicably coupled to the computer 602. Moreover, any or all parts of the API 612 or the service layer 613 can be implemented as child or sub-modules of another software module, enterprise application, or hardware module without departing from the scope of the present disclosure.

The computer 602 includes an interface 604. Although illustrated as a single interface 604 in FIG. 6, two or more interfaces 604 can be used according to particular needs, desires, or particular implementations of the computer 602 and the described functionality. The interface 604 can be used by the computer 602 for communicating with other systems that are connected to the network 630 (whether illustrated or not) in a distributed environment. Generally, the interface 604 can include, or be implemented using, logic encoded in software or hardware (or a combination of software and hardware) operable to communicate with the network 630. More specifically, the interface 604 can include software supporting one or more communication protocols associated with communications. As such, the network 630 or the interface's hardware can be operable to communicate physical signals within and outside of the illustrated computer 602.

The computer 602 includes a processor 605. Although illustrated as a single processor 605 in FIG. 6, two or more processors 605 can be used according to particular needs, desires, or particular implementations of the computer 602 and the described functionality. Generally, the processor 605 can execute instructions and can manipulate data to perform the operations of the computer 602, including operations using algorithms, methods, functions, processes, flows, and procedures as described in the present disclosure.

The computer 602 also includes a database 606 that can hold data for the computer 602 and other components connected to the network 630 (whether illustrated or not). For example, database 606 can be an in-memory, conventional, or a database storing data consistent with the present disclosure. In some implementations, database 606 can be a combination of two or more different database types (for example, hybrid in-memory and conventional databases) according to particular needs, desires, or particular implementations of the computer 602 and the described functionality. Although illustrated as a single database 606 in FIG. 6, two or more databases (of the same, different, or combination of types) can be used according to particular needs, desires, or particular implementations of the computer 602 and the described functionality. While database 606 is illustrated as an internal component of the computer 602, in alternative implementations, database 606 can be external to the computer 602.

The computer 602 also includes a memory 607 (e.g., a computer-readable storage medium such as a non-transitory computer-readable storage medium) that can hold data (e.g., computer instructions executable by the processor 605) for the computer 602 or a combination of components connected to the network 630 (whether illustrated or not). Memory 607 can store any data consistent with the present disclosure. In some implementations, memory 607 can be a combination of two or more different types of memory (for example, a combination of semiconductor and magnetic storage) according to particular needs, desires, or particular implementations of the computer 602 and the described functionality. Although illustrated as a single memory 607 in FIG. 6, two or more memories 607 (of the same, different, or combination of types) can be used according to particular needs, desires, or particular implementations of the computer 602 and the described functionality. While memory 607 is illustrated as an internal component of the computer 602, in alternative implementations, memory 607 can be external to the computer 602.

The application 608 can be an algorithmic software engine providing functionality according to particular needs, desires, or particular implementations of the computer 602 and the described functionality. For example, application 608 can serve as one or more components, modules, or applications. Further, although illustrated as a single application 608, the application 608 can be implemented as multiple applications 608 on the computer 602. In addition, although illustrated as internal to the computer 602, in alternative implementations, the application 608 can be external to the computer 602.

The computer 602 can also include a power supply 614. The power supply 614 can include a rechargeable or non-rechargeable battery that can be configured to be either user- or non-user-replaceable. In some implementations, the power supply 614 can include power-conversion and management circuits, including recharging, standby, and power management functionalities. In some implementations, the power supply 614 can include a power plug to allow the computer 602 to be plugged into a wall socket or a power source to, for example, power the computer 602 or recharge a rechargeable battery.

There can be any number of computers 602 associated with, or external to, a computer system containing computer 602, with each computer 602 communicating over network 630. Further, the terms “client,” “user,” and other appropriate terminology can be used interchangeably, as appropriate, without departing from the scope of the present disclosure. Moreover, the present disclosure contemplates that many users can use one computer 602 and one user can use multiple computers 602.

Thus, particular implementations of the subject matter have been described. Other implementations are within the scope of the following claims. In some cases, the actions recited in the claims can be performed in a different order and still achieve desirable results. In addition, the processes depicted in the accompanying figures do not necessarily require the particular order shown, or sequential order, to achieve desirable results. In certain implementations, multitasking and parallel processing may be advantageous.

Claims

1. A method comprising: determining a base productivity index for a target well in a well system comprising a plurality of wells including the target well drilled in a subterranean zone from a surface to a subsurface reservoir entrapping hydrocarbons, the base productivity index based on reservoir pressure and based on bottomhole pressure of the target well, the base productivity index free of interference on production through the target well from flow through other wells in the plurality of wells;determining a current productivity index for the target well, the current productivity index based on the reservoir pressure and based on the bottomhole pressure of the target well, the current productivity index affected by interference on production through the target well from flow through other wells in the plurality of wells;determining an interference modulus for the target well based on the current productivity index and the base productivity index for the target well; anddetermining, using the interference modulus for the target well, a numerical effect, on the target well, of the flow through the other wells in the plurality of wells.

2. The method of claim 1, further comprising receiving, by sensors disposed within the target well: the reservoir pressure measured before production through the target well is started, andthe bottomhole pressure measured after a volumetric flow rate through the target well has reached a pre-determined flow rate and immediately before the target well is shut in.

3. The method of claim 1, wherein the base productivity index is determined from a field buildup well test conducted in a field in which the plurality of wells are drilled.

4. The method of claim 1, wherein the base productivity index is determined from an Earth numerical model that computationally simulates a field in which the plurality of wells are drilled.

5. The method of claim 1, wherein the base productivity index and the current productivity index are each a productivity index, which is determined by: before producing through the target well, measuring the reservoir pressure in the target well;producing through the target well until a volumetric flow rate through the target well stabilizes;measuring the stabilized volumetric flow rate;after the volumetric flow rate stabilizes, measuring the bottomhole pressure in the target well; andafter measuring the bottomhole pressure in the target well, shutting in the target well.

6. The method of claim 5, further comprising determining the productivity index by dividing the stabilized volumetric flow rate by a difference between the reservoir pressure and the bottomhole pressure.

7. The method of claim 6, wherein determining the interference modulus for the target well comprises dividing the current productivity index by the base productivity index.

8. The method of claim 1, wherein determining, using the interference modulus for the target well, the numerical effect, on the target well, of the flow through the other wells in the plurality of wells comprises one of: determining an increase in productivity of the target well in response to determining that the interference modulus is greater than one, ordetermining a decrease in the productivity of the target well in response to determining that the interference modulus is less than one, ordetermining an absence of a change in the productivity of the target well in response to determining that the interference modulus is equal to one.

9. A computer-readable storage medium storing computer instructions, which when executed by one or more computer systems is configured to perform operations comprising: for a target well in a well system comprising a plurality of wells including the target well and in an absence of interference on production through the target well from flow through other wells in the plurality of wells, receiving: a first reservoir pressure in the target well before producing hydrocarbons through the target well,after producing hydrocarbons through the target well, a first stabilized volumetric flow rate of hydrocarbon production through the target well, andbefore shutting in the target well, a first bottomhole pressure in the target well;for the target well and in the presence of interference on the production through the target well from the flow through other wells in the plurality of wells, receiving: a second reservoir pressure in the target well before producing hydrocarbons through the target well,after producing hydrocarbons through the target well, a second stabilized volumetric flow rate of hydrocarbon production through the target well, andbefore shutting in the target well, a second bottomhole pressure in the target well;determining a base productivity index for the target well using the first volumetric flow rate, the first reservoir pressure and the first bottomhole pressure;determining a current productivity index for the target well using the second volumetric flow rate, the second reservoir pressure and the second bottomhole pressure;determining an interference modulus for the target well from the current productivity index and the base productivity index;determining, using the interference modulus for the target well, an effect, on the target well, of the flow through the other wells in the plurality of wells; andproviding the interference modulus.

10. The computer-readable storage medium of claim 9, wherein determining the base productivity index comprises determining a ratio between the first volumetric flow rate and a difference between the first reservoir pressure and the first bottomhole pressure.

11. The computer-readable storage medium of claim 10, wherein determining the current productivity index comprises determining a ratio between the second volumetric flow rate and a difference between the second reservoir pressure and the second bottomhole pressure.

12. The computer-readable storage medium of claim 11, wherein determining the interference modulus comprises determining a ratio between the current productivity index and the base productivity index.

13. The computer-readable storage medium of claim 12, determining, using the interference modulus for the target well, the effect, on the target well, of the flow through the other wells in the plurality of wells comprises one of: determining an increase in productivity of the target well in response to determining that the interference modulus is greater than one, ordetermining a decrease in the productivity of the target well in response to determining that the interference modulus is less than one, ordetermining an absence of a change in the productivity of the target well in response to determining that the interference modulus is equal to one.

14. The computer-readable storage medium of claim 11, wherein the first volumetric flow rate, the first reservoir pressure, the first bottomhole pressure, the second volumetric flow rate, the second reservoir pressure and the second bottomhole pressure are determined from a field buildup well test conducted in a field in which the plurality of wells are drilled.

15. The computer-readable storage medium of claim 11, wherein the first volumetric flow rate, the first reservoir pressure and the first bottomhole pressure are determined from an Earth numerical model that computationally simulates a field in which the plurality of wells are drilled.