WO2007024234A1

WO2007024234A1 - Improved hydrocarbon production methods

Info

Publication number: WO2007024234A1
Application number: PCT/US2005/030510
Authority: WO
Inventors: Theodore A. Pagano; Cory L. Eikenberg
Original assignee: Kerr-Mcgee Rocky Mountain Llc
Priority date: 2005-08-25
Filing date: 2005-08-25
Publication date: 2007-03-01

Abstract

The current invention provides improved methods for producing hydrocarbons from subterranean reservoirs. In particular, the current invention is suitable for practice in a wide variety of reservoirs including reservoirs producing fluids flow regimes such as but not limited to bubble flow, slug flow, churn flow, froth flow, annular flow and mist flow. The methods of the current invention initiate hydrocarbon production using a differential controller, a variable choke valve, an orifice plate and a by-pass plunger to produce hydrocarbons under wellbore backpressure.

Description

IMPROVED HYDROCARBON PRODUCTION METHODS

Background of the Invention

[0001] The current invention provides improved methods for producing hydrocarbons from a subterranean reservoir. The improved methods are applicable to reservoirs producing hydrocarbons in a variety of flow regimes. In particular, when used in a wellbore penetrating a reservoir producing primarily natural gas, the current invention reduces the likelihood of liquid loading of the wellbore. Additionally, application of the novel method will extend reservoir life and increase overall yield of gaseous and liquid hydrocarbon producing reservoirs by extending the wellbore 's sphere of influence and by preventing damage to the formation.

[0002] The present invention is based on an often unappreciated or at least underappreciated aspect of producing hydrocarbons from subterranean reservoirs, particularly when pricing is comparatively higher for produced hydrocarbons or experiences a swift upturn - namely, economically speaking, it may ultimately be undesirable to operate in a manner to achieve a high present production rate even in such a pricing environment, to the extent reservoir integrity or the longer-term recovery of hydrocarbons are adversely affected. The production of hydrocarbons from a well is thus not unlike the operation of a chemical or other manufacturing plant, where decisions on operating conditions, maintenance schedules, equipment changes and the like are evaluated by the more sophisticated producers, modeled and optimized, but it must be acknowledged that seldom has the production of hydrocarbons from a subterranean well been viewed in this way. [0003] Many reservoirs have sufficient stored energy to move fluids from the reservoir into the wellbore and subsequently to the surface simply by reducing the amount of backpressure in the wellbore. Other wells rely upon a form of artificial lift to transport the hydrocarbons from the wellbore to the surface while relying on reduced wellbore backpressure to move the hydrocarbons from the reservoir into the wellbore. Typically, artificial lift systems operate under minimal or no wellbore backpressure. As used herein, the term "wellbore" refers to the completed portion of a borehole.

[0004] For example, some reservoirs have natural fractures which permit the flow of hydrocarbons through the reservoir matrix into the wellbore. If the reservoir has sufficient internal energy (pressure), fluid will flow naturally to the surface without the use of artificial lift. Fluid flow to the surface may be enhanced by further reducing pressure within the wellbore thereby creating a fluid pressure differential favoring fluid flow into the borehole and to the surface. However, preserving the natural fractures within the formation requires sufficient pore pressure within the formation matrix. Fluid production from the reservoir at a rate greater than the natural flow of fluid through the fractures (as might seem obviously desirable in a higher price environment for produced hydrocarbons) will lower fluid pore pressure within the formation matrix, thus allowing the natural fractures to close. Formation damage resulting from over-production of a naturally fractured reservoir may shorten the reservoir's production life and may well reduce overall income derived from the reservoir. [0005] The detrimental impact of over-production or accelerated production varies with the type of flow regime generated by the reservoir. For example, in a solution gas-drive oil reservoir, liberation of natural gas from oil provides the primary drive mechanism responsible for moving oil from the reservoir into the wellbore. If production is increased through excessive pressure drawdown in the wellbore, solution gas will separate from the liquid hydrocarbons in a volatile and uncontrolled manner. The premature separation of the solution gas detrimentally impacts the value of the reservoir in three ways. First, the liquid hydrocarbon molecules separate on the basis of weight leaving the medium and heavy molecules behind as unrecoverable high low viscosity oil. Thus, as demonstrated in Fig. 2, the rapid initial production of hydrocarbons from this type of reservoir ultimately reduces the volume and energy value of the recovered oil. Second, the increased volume of liberated gas within the wellbore and the reservoir matrix adjacent to the wellbore will effectively block the movement of oil through the reservoir into the wellbore. Third, the separated oil will saturate the effective pore space nearest the wellbore creating a phenomenon known as "dead-oil block." Dead-oil block effectively seals the wellbore off from the reservoir. [0006] Similar problems are common in retrograde condensate reservoirs when excessive pressure drop is used to increase production. In a retrograde condensate reservoir, the formation is initially saturated with a hydrocarbon gas. Since the gas has a dew point, it will condense in response to certain changes in pressure and temperature. As shown in Fig. 3, an excessive pressure drop within the wellbore will lead to condensation of liquid from the gas. If condensation occurs within the reservoir, the resulting condensate block will saturate the reservoir pore space with hydrocarbon liquids. The condensate block decreases the effective permeability of the reservoir, thereby inhibiting movement of any further retrograde condensate from the reservoir into the wellbore. As the condensate block increases, flow of gas into the wellbore decreases. Under these conditions, the conventional solution calls for an increase in differential pressure drawdown to restore fluid production. However,, increasing the differential pressure drawdown will immediately result in additional liquid condensation within the reservoir. Thus, increased production is a temporary phenomenon as the conventional solution further damages reservoir permeability. Although not as apparent, similar blockage may occur in a gas condensate reservoir thereby dictating the need for careful production from both gas condensate and retrograde condensate reservoirs.

[0007] Given the detrimental impact of overproduction resulting from decreased wellbore pressures, i.e. increased differential drawdown, attempts have been made to produce fluids under wellbore backpressure. However, these efforts typically produce a condition known as "liquid loading" or "heading."

[0008] While liquid loading may occur in any wellbore, it is more common when producing natural gas having a liquid component. Liquid loading is characterized by an excessive accumulation of fluids within the wellbore. Typically, production of fluids under backpressure will lead to liquid loading due to the separation of fluid components on the basis of density and viscosity. Separation typically leads to gas slippage, i.e. the separation of the gas phase from the heavier more viscous oil, water or condensate phases. Loss of the gas phase from the liquids results in slug or churn flow within the wellbore and the failure to bring the liquids to the surface. As liquid levels increase within the wellbore, gas production is reduced due to liquid blockage of the wellbore from the reservoir.

[0009] Clearly, the production of hydrocarbons from a subterranean reservoir requires a careful balance between excessive pressure drop within the wellbore and excessive backpressure on the wellbore. The methods and apparatus of the current invention efficiently recover hydrocarbons from a subterranean reservoir using wellbore backpressure without liquid loading the wellbore. Additionally, the current invention avoids reservoir formation damage resulting from production of fluids under excessive drawdown pressures. By protecting the integrity of the subterranean reservoir and avoiding blockages within the reservoir adjacent to the wellbore, the current invention provides for a steady flow of hydrocarbons over a longer period of time than provided by prior art practices. Additionally, by controlling hydrocarbon production under wellbore backpressure, the current invention increases the sphere of influence for the wellbore.

Summary of the Invention

[0010] Briefly stated, the current invention initiates commercial hydrocarbon production from a subterranean reservoir through a wellbore operating under wellbore backpressure by immediately introducing a bypass plunger into the wellbore. In the method of the current invention, fluid production is initiated with the use of the bypass plunger coupled with a surface located differential controller. The differential controller controls a choke valve which maintains the desired wellbore backpressure thereby precluding liquid loading of the wellbore while maximizing bypass plunger trips through the wellbore. [0011] In one embodiment, the current invention provides a method for producing hydrocarbons comprising the drilling and completion of a wellbore penetrating a hydrocarbon producing subterranean reservoir. Further, a production control system comprising a differential controller and a variable choke valve is installed. Prior to initiating production under control of the differential controller, fluids are allowed to flow from the wellbore for a period of time sufficient to permit stabilization of wellbore pressure. Following stabilization of wellbore pressure, fluid production is initiated under wellbore backpressure as regulated by the differential controller and the variable choke valve. [0012] In yet another embodiment, the current invention provides a method for producing hydrocarbons comprising the drilling and completion of a wellbore penetrating a hydrocarbon producing subterranean reservoir. Further, a production control system comprising a differential controller and a variable choke valve is installed. Additionally, a production fluid loss device is installed or positioned at the lower end of the wellbore. Subsequently, a by-pass plunger is positioned within the wellbore and fluid production initiated under wellbore backpressure regulated by the differential controller and variable choke valve.

Brief Description of the Drawings

[0013] Figure 1 demonstrates the rapid depletion of reservoir pressure in the region of the wellbore when fluids are produced from the reservoir without wellbore backpressure. [0014] Figure 2 demonstrates the percent loss of gas due to a drop in wellbore or reservoir pressure.

[0015] Figure 3 demonstrates the percentage of entrained liquids resulting from a drop in wellbore or reservoir pressure.

[0016] Figure 4 depicts the reduced production resulting from a retrograde condensate block.

[0017] Figure 5 depicts the enhanced long term production resulting from application of the inventive method. [0018] Figure 6 depicts the change in wellbore pressure following initiation of the current invention.

Detailed Disclosure of the Preferred Embodiments

[0019] The novel methods disclosed herein depart from current art teachings related to the production of hydrocarbons from a subterranean reservoir. In particular, industry convention dictates that artificial lift is not used until pressure within the reservoir is insufficient to move fluids to the surface. Thus, artificial lift systems are not used during initial commercial production of fluids from the reservoir. Further, current practices delay the use of artificial lift by decreasing wellbore backpressure in order to promote fluid production. Finally, under current art practices once artificial lift is initiated, wellbore backpressure is minimized or preferably eliminated in order to promote rapid travel of a plunger from the wellbore bottom to the surface or ease of operation of other artificial lift systems.

[0020] In contrast to these conventions, the current invention initiates hydrocarbon production with the use of artificial lift operating under wellbore backpressure as regulated by a differential controller and variable choke valve. In the method of the current invention, a hydrocarbon producing wellbore is prepared according to techniques known to those skilled in the art. Following typical completion steps, such as installing casing and production control systems, the method of the current invention includes the addition of a differential controller to the wellbore production control system and a variable choke valve in the fluid production line. Typically, the differential controller is incorporated at the wellhead production battery, i.e., the surface equipment necessary for running the well. [0021] Following installation of the differential controller, fluid is generally allowed to flow from the well for a time sufficient to obtain fluid flow and pressure measurements, and preferably for a time sufficient to stabilize fluid pressure and remove debris which could damage the bypass plunger and other equipment. Preferably fluid is allowed to flow for approximately 24 hours. This initial fluid flow permits monitoring of wellbore sand production as well as determination of other production parameters. This initial fluid flow is not, however, considered established commercial hydrocarbon production. In other words, this initial fluid flow does not establish the commercial fluid production rate for the well. Based upon the fluid flow and pressure measurements obtained during this period, an appropriate size orifice plate is added to the fluid production system to allow the operator to monitor and optimize fluid flow rates and wellbore backpressure. [0022] With reference to Fig. 6, production of fluid through an orifice plate from a wellbore under free flow conditions lacking wellbore back pressure is depicted by the "paint brush" strokes of the graph to the left of the letter "A". The paint brush graph reading alerts the well operator to a liquid loading condition within the wellbore. The chart to the right of Fig. A represents production of fluid under wellbore back pressure conditions. The initial spike to the right of point A represents fluid production under insufficient wellbore back pressure. Following an increase in wellbore back pressure by the differential control manipulation of the choke, the chart depicts the desired representation of each trip of the plunger.

[0023] After the initial 24 hour period and prior to initiating production, a downhole production apparatus suitable for precluding the loss of production fluids from the bottom of the completed portion of the wellbore is installed. The production fluid loss prevention device, commonly known as a ball and seat bumper spring, is positioned within the production tubulars located within the wellbore. Following seating of the ball and seat bumper spring, the wellbore is ready for commercial production. A bypass plunger is dropped into the wellbore and commercial fluid production is initiated under wellbore backpressure as regulated by a differential controller and variable choke valve. [0024] As is known to those skilled in the art, a bypass plunger has a hollow core which allows the plunger to drop significantly faster than a traditional solid plunger. When the plunger hits bottom, the hollow core shifts to a closed position and subsequently serves as solid interface similar to a traditional plunger. The volume of produced fluid transported by artificial lift is normally referred to as a "slug."

[0025] In the practice of the current invention, the differential controller regulates fluid production rates by adjusting the variable choke valve to maintain the desired backpressure. When producing natural gas having entrained liquids, the differential controller maintains fluid production at a rate sufficient to avoid fluid loading of the wellbore. Similarly, when producing predominately liquid hydrocarbons, production occurs under wellbore backpressure sufficient to avoid damage to the reservoir resulting from conditions produced by rapid pressure depletion. Such conditions include collapse of natural fractures and/or blockage of the near wellbore region by a dead oil block. Thus, the coupling of a bypass plunger and a differential controller provides the ability to maintain wellbore backpressure while efficiently moving fluids to the surface in an environment where backpressure is critical to insuring maximum reservoir life. [0026] As indicated above, the current invention initiates regular commercial hydrocarbon production with the immediate use of bypass plunger. A production interval wherein a plunger transports a slug of fluid to the surface and returns to wellbore bottom is known as "trip." In contrast to the 1-16 trips for a solid plunger, a bypass plunger operating in the method of the current invention may trip between 25 and 60 times per day, depending on well characteristics. Therefore, while the bypass plunger carries a smaller volume of produced liquid (a slug) to the surface it makes more trips to the surface in a given period of time. Further, in contrast to a solid plunger, production with a bypass plunger does not require shutting-in the wellbore during the fall of the plunger to the wellbore bottom. Thus, fluid production continues as the bypass plunger falls to the wellbore bottom. As a result, production is not reduced during the practice of the current invention. [0027] The invention will now be described in more specific detail as applied to a predominantly liquid producing reservoir. Many liquid producing reservoirs have sufficient stored energy to permit production of the liquid hydrocarbons to the surface without the need for artificial lift. However, as previously discussed, producing fluid under free flow conditions will likely damage the formation by permitting conditions unfavorable to maintaining reservoir deliverability such as collapse of fractures and/or creating a dead oil block.

[0028] Additionally, reservoirs which flow on their own or are produced under aggressive drawdown commonly experience a rapid drop in reservoir pressure in the area nearest the bore hole. Fig. 1 demonstrates the rapid depletion of reservoir pressure in the region of the wellbore when fluids are produced from the reservoir without benefit of the current invention. Specifically, Fig. 1 depicts the relationship between formation pressure and distance from the wellbore during the production of fluids from a reservoir. Line A represents the production of fluids which flow freely into the wellbore and to the surface without maintaining backpressure on the wellbore. As depicted, Line A demonstrates a rapid drop-off in formation pressure in the region of the wellbore. As production continues, formation pressure in the region of the wellbore will eventually drop to a level insufficient to permit free flow of fluids from the formation to the surface, thereby requiring the use of artificial lift.

[0029] Fig. 1 also demonstrates the reduced sphere of influence exerted by a wellbore when production is carried out under free flow conditions or under aggressive differential drawdown. As shown in Fig. 1, free flow production coupled with differential drawdown produces the steep Curve A depicted therein. The rapid change in formation pressure represented by Curve A ultimately limits the flow of hydrocarbons through the formation to the wellbore. Vertical Line C represents the sphere of influence exerted by the wellbore when fluids are produced under these conditions. Clearly the sphere of influence is limited to a near wellbore region. The reduced sphere of influence is a consequence of reservoir damage due to producing the well without wellbore back pressure leading to closure of natural fractures and/or dead oil block. As depicted in Fig. 2, a decrease in pressure for a given temperature increases the likelihood of gas separation from the liquid hydrocarbons. As previously discussed, gas separation in a solution gas drive reservoir will ultimately lead to a dead oil block which seals the wellbore off from the remaining reservoir. Fig. 2 demonstrates that the volume of produced liquid will decrease as gas separates from solution.

[0030] In contrast to the prior art practices, application of the current invention to a solution gas drive reservoir, or to any other reservoir producing predominantly liquid hydrocarbons by relying upon the use of gas energy, will extend the zone of influence exerted by the wellbore. With continued reference to Fig. 1, application of the current invention will enhance or extend the zone of influence exerted by the wellbore by decreasing the slope of the pressure drop within the formation.

[0031] As represented by Curve B, initiating fluid production immediately with the use of a bypass plunger coupled with a differential controller limits the pressure drop in the near wellbore area. By limiting the pressure drop, the current invention allows hydrocarbons to flow at a consistent rate through the formation matrix to the vicinity of the wellbore. Thus, the formation experiences a uniform and gradual drop in formation pressure (P₁) thereby permitting the continued flow of hydrocarbons to the wellbore. As shown in Fig. 1, formation pressure generally flattens out and decreases uniformly during production as the distance from the wellbore increases. Since formation pressure is generally consistent across the region from the wellbore extending outwardly, the likelihood of a dead oil block and/or damage to the formation matrix is reduced. Thus, production of liquid hydrocarbons under wellbore backpressure by means of a bypass plunger will protect the formation, extend the wellbore sphere of influence, and extend the overall life of the formation. Further, in the practice of the current invention, wellbore backpressure does not preclude fluid production during dropping of the by-pass plunger from the surface to the bottom of the wellbore and the formation pressure drop in the near wellbore region will be less than the formation pressure drop experienced under free flow production conditions. [0032] When practiced within a solution gas-drive liquid hydrocarbon producing reservoir, the current invention enhances production by advantageously using the normally natural liberation of gaseous hydrocarbons from solution with the liquid hydrocarbons to move the by-pass plunger to the surface. In this embodiment, the wellbore backpressure is controlled to provide sufficient back pressure to preclude a dead oil block within the reservoir. However, backpressure is not so great as to preclude all separation of gaseous hydrocarbons from solution. Rather, wellbore backpressure is preferably low enough to permit sufficient separation of gaseous hydrocarbons to carry the by-pass plunger to the surface or top of the wellbore.

[0033] In summary, applying the current invention to a predominantly liquid producing reservoir entails the steps of drilling and completing a wellbore penetrating the subterranean reservoir. The completion process includes conventional steps such as installing production control systems. In the practice of the current invention, the production control system includes a variable choke valve suitable for controlling the production of hydrocarbons. Additionally, in the practice of the current invention, the production control system incorporates a differential controller. Prior to initiating production of fluids under control of the differential controller and variable choke valve, the wellbore is allowed to flow fluids for a time, preferably a period of approximately 24 hours. During this time, the operator monitors wellbore pressures, sand production and other typical production parameters. This monitoring period also clears the wellbore of any damaging debris left behind from the drilling and completion process. Following the monitoring period, an orifice plate is selected and installed within the production line. Prior to initiating commercial production, a ball and seat bumper spring device is dropped down the tubulars. Along with the casing and production tubulars, the ball and seat bumper spring is the only other down hole completion apparatus necessary for the practice of the current invention. The ball and seat bumper spring retains reservoir fluid within the wellbore, precluding it from dropping out from the end of the tubing. Other devices suitable for precluding fluid loss from the end of the tubing may be substituted for the ball and seat bumper. However, additional downhole completion tools are not required prior to initiating commercial production in the practice of the current invention. [0034] Following completion of the monitoring period, installation of the orifice plate and dropping of the ball and seat bumper spring down the tubulars, commercial production is initiated immediately with the use of a bypass plunger. As the bypass plunger drops to the bottom of the wellbore, backpressure is maintained on the wellbore by manipulation of the variable choke valve positioned within the production tubing. Control of the variable choke valve is provided by the differential controller. When the bypass plunger reaches the ball and seat bumper spring at the bottom of the wellbore, the plunger closes. As gas pressure begins to build beneath the plunger, gas moves to the surface carrying the plunger and a slug of produced liquid. Thus, the gas component of the produced hydrocarbons provides sufficient energy to overcome the backpressure maintained by the variable choke valve and regulated by the differential controller.

[0035] According to the current invention, the time for the bypass plunger to travel from the wellbore bottom to the surface is monitored. If the travel time of the bypass plunger is deemed to be too slow, or if the plunger fails to arrive, the differential controller will direct the variable choke valve to open thereby removing a portion of the backpressure maintained on the wellbore and allowing the greater differential energy to move the plunger to the surface. Once at the surface the bypass plunger is manipulated in a conventional manner until the produced fluid is moved to a holding tank through conventional pipelines. Following removal of the produced fluid, the bypass plunger is allowed to drop once again to the wellbore bottom thereby completing one trip. Preferably, the bypass plunger will trip at least two to three times per hour. During production, fluid flow rates and wellbore pressures are constantly monitored in order to maintain the desired backpressure on the wellbore while maintaining the desired number of plunger trips per hour. [0036] As previously noted, fluid production from the wellbore preferably does not stop during the passage of the bypass plunger to the bottom of the wellbore. Although the operator has the option of shutting in the well during plunger drop, the preferred method of the current invention will permit the natural flow of fluid during plunger drop. Thus, in the preferred embodiment, reservoir fluid entering the wellbore will readily pass through the bypass plunger as it falls and the fluid will flow to the surface under pressures sufficient to overcome the backpressure maintained on the wellbore thereby permitting continued production of fluids during drop of the plunger from the surface to the wellbore bottom. Thus, the current invention provides for the production of liquid hydrocarbon on a continuous basis while protecting formation structure and precluding the occurrence of a dead oil block within the reservoir.

[0037] Fig. 5 demonstrates the benefits of the current invention in a liquid hydrocarbon producing field. The curves depicted in Fig. 5 represent the actual production rate from the reservoir, the initial hypothesized production rate from the reservoir, and the forecasted production rate following initiation of the methods of the current invention. As shown on the graph, the hypothesized production rate is identified as line 1. The forecasted rate for fluid production under the methods of the current invention is identified as line 2 and the actual production rate is identified as line 3. For the subterranean reservoir depicted in figure 5, the method of the current invention was initiated after approximately two weeks of free flow production. The two week production period is identified on the graph as Region A. As shown, the production rate under free flow conditions experienced a marked decline over this initial two-week period. This marked decline coupled with knowledge of flow rates from other wells within the same reservoir resulted in the initial hypothesized production rate for the life of the well. However, following production of fluids under wellbore backpressure in accordance with the methods of the current invention, the decline in production significantly flattened compared to the initial hypothesized rate. As a result, a new forecast of fluid production was generated shown as line 2. However, the improvements provided by fluid production using the methods of the current invention required a subsequent recalculation in the forecast fluid production. The new forecast for fluid production resulted in the increase shown at point B on the graph. [0038] At point C, the well was prepared for shutting in and subsequent workover. Following removal of the plunger at this time, the well experienced a buildup of 1600 psi within the well bore and flowed on its own for four days. Wellbore pressure of this nature would not be expected in a well which had produced fluid for approximately one year. Rather, most operators would expect to see zero psi within the wellbore following removal of the plunger from a well operated for this period of time. Following the flow of fluids for four days, the well was shut-in as shown at point D resulting in the complete shutoff of production from the well.

[0039] Figure 5, thus demonstrates that the methods of the current invention provide the ability to preserve reservoir deliverability while enhancing the sphere of influence exerted by a single wellbore. More importantly, Fig. 5 provides a real-world demonstration of the predicted characteristics depicted in Fig. 1. As previously discussed, Fig. 1 demonstrates that fluid production under wellbore back pressure will lead to the gradual reduction in formation pressure (Pj) thereby extending the sphere of influence exerted by a single wellbore and permitting continued production of fluids from the reservoir for an extended period of time.

[0040] The methods of the current invention may also be advantageously applied to production of hydrocarbons from predominantly gas producing reservoirs. Such reservoirs include retrograde condensate reservoirs, gas condensate reservoirs and predominantly natural gas producing reservoirs. As known to those skilled in the art, such reservoirs typically produce liquid hydrocarbons, water, and brine in addition to the gaseous hydrocarbons. Accumulation of these liquids within the wellbore will gradually block the flow of gas from the reservoir into the wellbore, creating a condition known as liquid loading or heading. Thus, a wellbore penetrating a gas producing reservoir typically requires some form of liquid separation and removal. Preferably, the form of liquid removal takes advantage of the natural energy provided by the flow of gas from the reservoir into the wellbore and subsequently to the surface. However, as noted above, the free flow of the gas from a retrograde gas condensate reservoir or a gas condensate reservoir must be controlled in order to preclude the formation of a condensate block within the reservoir. Thus, in the preferred embodiment, the current invention maintains sufficient wellbore backpressure to separate out liquids from the gas within the wellbore without leading to a condensate block in the reservoir. Further, the wellbore backpressure is regulated to permit the regular operation of the bypass plunger to remove the separated liquids.

[0041] As demonstrated in Fig. 3, a rapid drop of pressure within the reservoir adjacent to the wellbore increases the likelihood of reservoir damage. Specifically, as pressure drop increases, the percentage of liquid condensing from the gas increases. As condensation occurs, liquid collects within either the wellbore or the pores of the formation. If the condensation occurs within the formation, a condensate block occurs. [0042] The impact of a condensate block within a formation is demonstrated in Fig. 4. As is known to those skilled in the art, hydrocarbon production from the retrograde condensate reservoir has value in both the gas and the liquid components. Fig. 4 provides a graph of the production rate for both the gas component and the condensate hydrocarbon component of a retrograde condensate reservoir. Line 1 represents gas production from the reservoir while line 2 represents production of the condensate liquids from the reservoir. With the passage of time, the production rate of the gas and the condensates noticeably drops. At the point indicated by the letter A, a condensate block has formed within the reservoir. In order to overcome the blockage, a typical fracturing process was carried out in an attempt to restimulate the reservoir. Line 3 demonstrates the return of gas production from the reservoir following this fracturing process. However, condensate production is never resumed. Thus Fig. 4 demonstrates that the damage which may occur to a reservoir through the free flowing production of hydrocarbons from a retrograde condensate reservoir can significantly lower the value of the produced hydrocarbons.

[0043] In contrast to the prior art practice as demonstrated in Fig. 4, use of the current invention will avoid the formation of the condensate block within the reservoir or a retrograde gas producing reservoir. When practiced within a predominantly gas producing reservoir, the current invention entails the drilling and completion of a wellbore penetrating the subterranean reservoir according the conventional practices. Installation of production hardware and control equipment is also carried out in accordance with conventional practices. In a manner similar to that described above with regard to a predominantly liquid producing reservoir, the well is permitted to flow for a period of time, preferably approximately 24 hours. Following the initial fluid flow period, an orifice plate is installed within the production system. Thereafter a ball and seat bumper spring is dropped down the tubulars and a bypass plunger installed within the wellbore

[0044] Following completion and dropping of the bypass plunger, commercial production of hydrocarbons is initiated under backpressure maintained by the variable choke valve and regulated by the differential controller. Commercial production of the hydrocarbon gas from the reservoir under the backpressure maintained by the differential controller is sufficient to maintain wellbore pressure and internal reservoir pressure above the dew point of the gas being produced from the reservoir. Thus, the pressure maintained by the differential controller will be determined in part by the level of liquid saturation within the hydrocarbon gas and the subterranean temperature of the formation. In general, it is preferred to maintain the pressure above the pressure at which a condensate block will likely occur.

[0045] While the backpressure maintained by the differential controller must be sufficient to avoid the formation of a condensate block, it must not be so great as to prevent movement of the bypass plunger from the bottom of the wellbore or to the surface. In this instance, the produced hydrocarbon gas also provides the energy necessary for removal of accumulated liquid from the wellbore. Whether these liquids comprise brine, fresh water or hydrocarbon fluids, the energy provided by the produced gas must be sufficient to overcome the backpressure maintained by the differential controller. In general, the differential controller maintains sufficient backpressure through the choke valve to permit approximately two to four trips per hour per 7000 foot of wellbore length. [0046] Clearly the methods of the current invention are applicable across a wide range of reservoirs. In general, so long as a reservoir has sufficient gas energy to operate a bypass plunger, the methods of the current invention will be applicable to that reservoir. Since each reservoir is unique and may yield hydrocarbons in a variety of fluid flow regimes operational considerations vary from well to well. Commonly encountered fluid flow regimes include but are not limited to bubble flow, slug flow, churn flow, froth flow, annular flow and mist flow. Regardless of the flow regime, the operator will preferably use orifice plate measurements, such as depicted in Fig. 6, to determine the optimum backpressure necessary to move fluids to the surface while avoiding damage to the reservoir. Thus, use of the orifice plate permits optimization of fluid flow rates and wellbore backpressure. In general, gaseous producing reservoirs produce less liquid; therefore, the plunger will trip fewer times. As a result, wellbore backpressure will generally be higher in a predominately gaseous hydrocarbon wellbore. In the case of a retrograde condensate and/or condensate reservoir, the wellbore backpressure should be sufficient to avoid excessive liquid condensation. In contrast, a wellbore producing primarily liquid hydrocarbons requires a greater number of plunger trips. Accordingly, liquid hydrocarbon producing wellbores will normally operate under lower backpressure conditions than a gaseous wellbore. In a primarily liquid producing wellbore, the wellbore back pressure permits tripping of the plunger while precluding a dead oil block.

[0047] Thus, the current invention provides methods suitable for enhancing the zone of influence asserted by a wellbore while protecting formation integrity in a variety of hydrocarbon producing flow regimes. Additionally, the current invention will enhance and extend reservoir life by providing a controlled drawdown of fluids and controlled drop in reservoir pressure. The current invention provides these benefits by ignoring industry convention which dictates the use of a plunger only when reservoir energy is insufficient to move liquid to the surface without the benefit of article lift.

[0048] Other embodiments of the current invention will be apparent to those skilled in the art from a consideration of this specification or practice of the invention disclosed herein. However, the foregoing specification is considered merely exemplary of the current invention with the true scope and spirit of the invention being indicated by the following claims.

Claims

I claim:

1. A method for producing hydrocarbons from a subterranean reservoir comprising: drilling and completing a wellbore penetrating a hydrocarbon producing subterranean reservoir; installing a production control system comprising a differential controller and a variable choke valve; producing hydrocarbons under wellbore backpressure regulated by said differential controller and said variable choke valve.

2. A method for producing hydrocarbons from a subterranean reservoir comprising: drilling and completing a wellbore penetrating a hydrocarbon producing subterranean reservoir; installing a production control system comprising a differential controller and a variable choke valve; positioning a production fluid loss device at the lower end of said wellbore; positioning a by-pass plunger in said wellbore; producing hydrocarbons from said reservoir under wellbore backpressure regulated by said differential controller and said variable choke valve.

3. A method for producing hydrocarbons from a subterranean reservoir comprising: drilling and completing a wellbore penetrating a hydrocarbon producing subterranean reservoir; installing a production control system comprising a differential controller and a variable choke valve; positioning a production fluid loss device at the lower end of said wellbore; positioning a by-pass plunger in said wellbore; prior to initiating production under control of said differential controller, allowing fluids to flow from said wellbore for a period of time sufficient to obtain fluid flow and pressure measurements; initiating fluid production under wellbore backpressure regulated by said differential controller and said variable choke valve.

4. A method for producing hydrocarbons from a subterranean reservoir comprising: drilling and completing a wellbore penetrating a hydrocarbon producing subterranean reservoir; installing a production control system comprising a differential controller and a variable choke valve; positioning a production fluid loss device at the lower end of said wellbore; positioning a by-pass plunger in said wellbore; producing hydrocarbons under wellbore backpressure regulated by said differential controller and said variable choke valve, wherein said produced hydrocarbons are predominately gaseous hydrocarbons having entrained liquids and wherein said backpressure is sufficient to separate liquids from said gaseous hydrocarbons in said wellbore while precluding the condensation of said liquids within said reservoir.

5. A method for producing hydrocarbons from a subterranean reservoir comprising: drilling and completing a wellbore penetrating a hydrocarbon producing subterranean reservoir; installing a production control system comprising a differential controller and a variable choke valve; positioning a production fluid loss device at the lower end of said wellbore; positioning a by-pass plunger in said wellbore; prior to producing hydrocarbons under control of said differential controller, allowing fluids to flow from said wellbore for a period of time sufficient to obtain fluid flow and wellbore pressure measurements; selecting and installing an orifice plate within the fluid production system based on the measured fluid flow and wellbore pressures; producing hydrocarbons under wellbore backpressure regulated by said differential controller and said variable choke valve while using said orifice plate to monitor fluid flow rates and wellbore backpressure.

6. A method for continuously producing hydrocarbons under wellbore backpressure from a subterranean reservoir comprising; drilling and completing a wellbore penetrating a hydrocarbon producing subterranean reservoir; installing a production control system comprising a differential controller and a variable choke valve; positioning a production fluid loss device at the lower end of said wellbore; positioning a by-pass plunger in said wellbore; and, producing hydrocarbons under wellbore backpressure regulated by said differential controller and said variable choke valve during movement of said by-pass plunger from the lower end of said wellbore to the top of said wellbore and also producing hydrocarbons through said by-pass plunger as said plunger falls to the lower end of said wellbore.

7. A method for controlling pressure drop within a hydrocarbon producing subterranean reservoir comprising: drilling and completing a wellbore penetrating a hydrocarbon producing subterranean reservoir; installing a production control system comprising a differential controller and a variable choke valve; positioning a production fluid loss device at the lower end of said wellbore; positioning a by-pass plunger in said wellbore; initiating fluid production under wellbore backpressure regulated by said differential controller and said variable choke valve wherein said backpressure is sufficient to gradually drop pressure within said hydrocarbon producing subterranean reservoir.

8. A method for producing gaseous hydrocarbons having entrained liquids from a subterranean reservoir comprising: drilling and completing a wellbore penetrating a hydrocarbon producing subterranean reservoir; installing a production control system comprising a differential controller and a variable choke valve; positioning a production fluid loss device at the lower end of said wellbore; positioning a by-pass plunger in said wellbore; producing hydrocarbons under wellbore backpressure regulated by said differential controller and said variable choke valve, wherein said backpressure is sufficient to separate liquids from said gaseous hydrocarbons in said wellbore and wherein said backpressure is determined by the level of liquid saturation of said gaseous hydrocarbons.

9. A method for producing gaseous hydrocarbons having entrained liquids from a subterranean reservoir comprising: drilling and completing a wellbore penetrating a hydrocarbon producing subterranean reservoir; installing a production control system comprising a differential controller and a variable choke valve; positioning a production fluid loss device at the lower end of said wellbore; prior to initiating production under control of said differential controller, allowing fluids to flow from said wellbore for a period of time sufficient to permit stabilization of wellbore pressure; positioning a by-pass plunger in said wellbore; following stabilization of wellbore pressure, initiating hydrocarbon production under wellbore backpressure regulated by said differential controller and said variable choke valve, wherein said backpressure is sufficient to separate liquids from said gaseous hydrocarbons in said wellbore and wherein said backpressure is greater than the dew point of said entrained liquids.

10. A method for producing liquid hydrocarbons having dissolved gaseous hydrocarbons from a subterranean reservoir comprising: drilling and completing a wellbore penetrating a hydrocarbon producing subterranean reservoir; installing a production control system comprising a differential controller and a variable choke valve; positioning a production fluid loss device at the lower end of said wellbore; prior to initiating production under control of said differential controller, allowing fluids to flow from said wellbore for a period of time sufficient to permit stabilization of wellbore pressure; positioning a by-pass plunger in said wellbore; following stabilization of wellbore pressure, initiating hydrocarbon production under wellbore backpressure regulated by said differential controller and said variable choke valve, wherein said backpressure is sufficient to maintain said gaseous hydrocarbons in solution with said liquid hydrocarbons.

11. A method for producing liquid hydrocarbons from a solution gas-drive reservoir comprising: drilling and completing a wellbore penetrating a hydrocarbon producing subterranean reservoir; installing a production control system comprising a differential controller and a variable choke valve; positioning a production fluid loss device at the lower end of said wellbore; positioning a by-pass plunger in said wellbore; prior to producing hydrocarbons under control of said differential controller, allowing fluids to flow from said wellbore for a period of time sufficient to remove debris from said wellbore; producing hydrocarbons under wellbore backpressure regulated by said differential controller and said variable choke valve, wherein said backpressure allows sufficient separation of said gaseous hydrocarbons from said liquid hydrocarbons to move said by-pass plunger to the top of said wellbore while precluding a dead oil block within said reservoir.

12. A method for extending the sphere of influence of a wellbore penetrating a hydrocarbon producing reservoir comprising: drilling and completing a wellbore penetrating a hydrocarbon producing subterranean reservoir; installing a production control system comprising a differential controller and a variable choke valve; positioning a production fluid loss device at the lower end of said wellbore; positioning a by-pass plunger in said wellbore; prior to producing hydrocarbons under control of said differential controller, allowing fluids to flow from said wellbore for a period of time sufficient to obtain fluid flow and wellbore pressure measurements; installing an orifice plate within the fluid production system; producing hydrocarbons under wellbore backpressure regulated by said differential controller and said variable choke valve, wherein said wellbore backpressure does not preclude production of fluids during dropping of said by-pass plunger and wherein formation pressure drop in the near wellbore region is less than formation pressure drop under free flow production conditions.