Abstract:
An inflow control device controls the rate of fluid flow from a subsurface fluid reservoir into a production tubing string. The inflow control device includes a particulate screen to remove particulate matter from the reservoir fluid, and at least two flow restrictors. The flow restrictors are positioned on circumferentially opposite sides of the inflow control device and are connected by an isolated fluid passage. The flow restrictors limit the flowrate of reservoir fluid when the reservoir fluid has a high water or gas-to-oil ratio. The inflow control device also includes at least one pressure drop device that generates a pressure drop for the reservoir fluid in response to fluid pressure in the reservoir. The inflow control device also includes a choking apparatus that allows the flow of reservoir fluid to be shut off and the particulate screen cleaned while the inflow control device is in place in hole.

Description:
This application claims priority to and the benefit of U.S. Provisional Application No. 61/535,802, filed on Sep. 16, 2011, entitled “Self-Controlled Inflow Control Device,” which application is hereby incorporated herein by reference. 
    
    
     BACKGROUND OF THE INVENTION 
     1. Field of the Invention 
     The present invention relates in general to well production devices and, in particular, to a self-controlled inflow control device. 
     2. Brief Description of Related Art 
     Some well completions use lateral lines to penetrate horizontally across a reservoir. These horizontal well sections extend through a reservoir at the same general elevation to produce fluid from across the reservoir rather than a localized area around a vertical well. The lateral lines extend from a heel at the junction of the lateral line with the vertical line to a toe at the end of the lateral line. Fluid along the horizontal wellbore profile will flow into the production tubing all along the lateral. However, the fluid flowing into the heel will block flow from the toe, preventing production of fluid from the entire reservoir profile to the surface. Instead, the majority of the produced fluid will be drawn from the formation areas around the heel. This may lead to coning. Coning refers to the cone shape reservoir fluid movement front, i.e. a boundary between desired reservoir fluid and undesired reservoir fluid, when too much reservoir production occurs from a single zone of the well. As reservoir fluid is produced from the formation, surrounding fluids, such as water, will flow into the produced areas. If the produced fluid flowrate is too high, the water will fill the area before desired fluid can replace the produced fluid. In a lateral well, production only at the heel will draw water into the formation at the heel. As the heel produces water, it will block formation fluid from the toe. In these situations, inflow control devices (ICDs) are used to restrict the flow of reservoir fluid from the heel and other high pressure areas of the formation to create a more even production profile that produces reservoir fluid from the formation and prevent coning. 
     Inflow control devices restrict flow by forcing fluid through restricted passageways to create a pressure differential. This pressure differential must be overcome by the pressure in the reservoir surrounding the inflow control device. Where reservoir pressure is high, the pressure will overcome the inflow control device pressure differential and be produced to the surface. As production causes a pressure drop in the reservoir around the inflow control device, the reservoir pressure will no longer overcome the inflow control device pressure differential, limiting production from that area until reservoir pressure increases. Reservoir formations are tested before the inflow control devices are run-in-hole, and the inflow control devices are adjusted prior to run-in to accommodate the pressure for the specific zone of the reservoir in which the inflow control device is placed. These inflow control devices have difficulties maintaining the desired production profile for longer production periods, eventually completely stopping production as the reservoir pressure drops. To overcome this, some inflow control devices include mechanisms that allow the inflow control device to vary the pressure differential to accommodate reservoir pressure changes. These inflow control devices use hydraulically controlled functions powered by hydraulic umbilicals that supply fluid pressure from the surface. These inflow control devices are significantly more expensive to use due to the specialty equipment needed to run the hydraulic umbilical and monitor it from the surface. 
     In addition, many inflow control devices are unable to actively restrict the fluid flowrate of reservoir fluid through the inflow control device and adjust for reservoir fluid flow that has a high volume of gas or a high volume of water in the flow. Thus, if a portion of the well begins to produce a gas or water, the inflow control device cannot further restrict flow to limit the percentage of water or gas in the fluid produced at the surface. Some inflow control devices include equipment that may be operated from the surface to accommodate for these situations, but similar to the hydraulic pressure adjustment equipment, the inflow control devices need expensive hydraulic or electric umbilicals to perform the water and gas restriction function. These inflow control devices also require an extensive and expensive testing process to determine which portion of the well is producing the water and gas. Still further, some inflow control devices include means to restrict water and gas flow using devices that respond to varying fluid density in the reservoir. These devices must then mate with corresponding nozzles to restrict fluid flow. However, many of these devices are unable to successfully operate outside of specific known density conditions. Thus, in the event there is a significant variance in the expected reservoir fluid density, the devices are unable to properly limit flow of the water or gas. Typically, these devices may only accommodate restriction of either water or gas, but not both. 
     Another problem faced by use of inflow control devices, particularly in well formations using an openhole production process is clogging of filter media. As the inflow control device is used, particulate matter builds up on the filter and blocks flow of fluid from the reservoir into the inflow control device and production tubing. Still another problem faced by inflow control devices is the inability of the inflow control device to be choked back or turned off by an operator at the surface to prevent flow of reservoir fluid through the inflow control device under predetermined conditions. Therefore, an inflow control device that overcomes the problems of the prior art described above would be desirable. 
     SUMMARY OF THE INVENTION 
     These and other problems are generally solved or circumvented, and technical advantages are generally achieved, by preferred embodiments of the present invention that provide a self-controlled inflow control device, and a method for using the same. 
     In accordance with an embodiment of the present invention, an inflow control device for controlling fluid flow from a subsurface fluid reservoir into a production tubing string is disclosed. The inflow control device includes a tubular member defining a central bore having an axis, wherein upstream and downstream ends of the tubular member may couple to the production tubing string. A plurality of passages are formed in a wall of the tubular member. The inflow control device includes an upstream inlet to the plurality of passages leading to an exterior of the tubular member to accept fluid. Each passage has at least two flow restrictors with floatation elements of selected and different densities to restrict flow through the flow restrictors in response to a density of the fluid. The inflow control device includes at least one pressure drop device positioned within each passage in fluid communication with an outflow of the flow restrictors, the pressure drop device having a pressure piston for creating a pressure differential in the flowing fluid based on the reservoir fluid pressure. An outflow of the pressure drop device flows into an inflow fluid port in communication with the central bore. 
     In accordance with another embodiment of the present invention, an inflow control device for controlling fluid flow from a subsurface fluid reservoir into a production tubing string for production to a surface is disclosed. The inflow control device includes a tubular member defining a central bore having an axis with a plurality of passages formed in a wall of the tubular member. Each passage partially circumscribes the tubular member so that a terminus of each passage is 180 degrees from a head of the passage. The inflow control device also includes at least two flow restrictors having floatation members of selected and different densities positioned within each flow restrictor to restrict flow of reservoir fluid having a high water-to-oil ratio and a high gas-to-oil ratio. A passage of the plurality of passages is vertically oriented so that at least one of the corresponding flow restrictors is at a highest elevation of the inflow control device and at least one of the corresponding flow restrictors is at a lowest elevation of the inflow control device. At least one pressure drop device is positioned within each passage in fluid communication with an outflow of the flow restrictors. The pressure drop device creates a pressure differential in the flowing fluid with a pressure piston in response to the reservoir fluid pressure. An outflow of the pressure drop device flows into an inflow fluid port in communication with the central bore. A pressure actuated choke apparatus is positioned downstream of the pressure drop device to restrict flow of fluid from the plurality of passages into the central bore in response to fluid pressure applied to the production tubing string at the surface. A filter media is positioned within an annular opening defined by the tubular member near an upstream end of the inflow control device, the filter media allowing fluid communication between the subsurface fluid reservoir and the plurality of passages. The inflow control device also includes a pressure actuated member positioned on an upstream end of the inflow control device and actuable in response to a pressure within the central bore to allow fluid communication from the central bore to the filter media to clean the filter media. 
     In accordance with yet another embodiment of the present invention, a method for producing fluid from a subsurface reservoir with an inflow control device is disclosed. The method couples at least one inflow control device to a production tubing string, and runs the production tubing string into a wellbore. The method then applies fluid pressure to the tubing string to prevent flow of reservoir fluid through the inflow control device during run-in of the production tubing string. The method then removes fluid pressure from the production tubing string to allow reservoir fluid to flow into the production tubing string through the inflow control device while restricting flow of reservoir fluid having a high water-to-oil ratio and a high gas-to-oil ratio and controlling the flow rate of the reservoir fluid with the inflow control device. In the event a substantial interruption of reservoir fluid flow occurs, the method applies a fluid pressure to the production tubing string greater than the fluid pressure applied during run-in to cause fluid flow through the inflow control device and into the reservoir. The method then removes the fluid pressure to continue production of reservoir fluid. 
     An advantage of the disclosed embodiments is that they provides an inflow control device that may be used to create a pressure drop to reduce reservoir fluid flow and maintain a balanced production profile across multiple production zones, particularly those at the same elevation. The disclosed inflow control devices accommodate varying reservoir pressure by varying the pressure differential in response to the reservoir pressure. Still further, the disclosed embodiments will restrict the flow of production fluid having high volumes of water or gas based on the ratio of those substances within the reservoir fluid. In addition, the disclosed embodiments will remove solid particulate matter from the reservoir fluid flow. The disclosed embodiments remove particulates and include a process to allow for washing of the inflow control device while in place in hole. This allows for a longer life of the inflow control device with fewer problems related to plugging or blockage as compared to other inflow control devices. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       So that the manner in which the features, advantages and objects of the invention, as well as others which will become apparent, are attained, and can be understood in more detail, more particular description of the invention briefly summarized above may be had by reference to the embodiments thereof which are illustrated in the appended drawings that form a part of this specification. It is to be noted, however, that the drawings illustrate only a preferred embodiment of the invention and are therefore not to be considered limiting of its scope as the invention may admit to other equally effective embodiments. 
         FIG. 1  is a schematic representation of a portion of a production well in accordance with an embodiment of the present invention. 
         FIG. 2A  is a schematic side sectional view of an inflow control device during a production process in accordance with an embodiment of the present invention. 
         FIG. 2B  is a schematic representation of fluid flow through the inflow control device of  FIG. 2A  during the production process. 
         FIG. 2C  is a schematic representation of fluid flow through the inflow control device of  FIG. 2A  during a remedial or backwash process. 
         FIGS. 3A-3B  are sectional views of flow restrictor devices of  FIG. 2A  taken along lines  3 A- 3 A and  3 B- 3 B, respectively, in accordance with an embodiment of the present invention. 
         FIG. 3C  is a sectional view of  FIG. 3A  and  FIG. 3B  taken along line  3 C- 3 C of  FIG. 3A  and  FIG. 3B . 
         FIGS. 3D-3E  are front views of a downstream porting wall and an upstream porting wall, respectively, of  FIG. 3C . 
         FIGS. 4-8  are schematic views of portions of the flow restrictors of  FIGS. 3A-3C  during production of expected reservoir fluid. 
         FIGS. 9-13  are schematic views of portions of the flow restrictors of  FIGS. 3A-3C  during production of high gas-to-oil ratio reservoir fluid. 
         FIGS. 14-18  are schematic view of portions of the flow restrictors of  FIGS. 3A-3C  during production of high water-to-oil ratio reservoir fluid. 
         FIG. 19  is an end view of a pressure drop device of  FIG. 2A  in accordance with an embodiment of the present invention. 
         FIG. 20  is a sectional view of the pressure drop device of  FIG. 2A  taken along line  20 - 20  of  FIG. 19 . 
         FIGS. 21-22  are sectional views of the pressure drop device of  FIG. 2A  taken along line  21 - 21  and  22 - 22  of  FIG. 20 , respectively. 
         FIGS. 23-26  are sectional views of the pressure drop device of  FIG. 2A  illustrating operational steps of the use of the pressure drop device. 
         FIGS. 27 and 28  are detail sectional views of the pressure drop device of  FIG. 2A  illustrating operational steps of a flow restriction process. 
         FIG. 29  is a sectional view of the inflow control device of  FIG. 1  in a nm-in-hole process. 
         FIG. 30  is a sectional view of the inflow control device of  FIG. 1  in a remedial process. 
         FIG. 31  is sectional view of the pressure drop device of  FIG. 30  illustrating an operational step of the pressure drop device during the remedial process. 
     
    
    
     DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENT 
     The present invention will now be described more fully hereinafter with reference to the accompanying drawings which illustrate embodiments of the invention. This invention may, however, be embodied in many different forms and should not be construed as limited to the illustrated embodiments set forth herein. Rather, these embodiments are provided so that this disclosure will be thorough and complete, and will fully convey the scope of the invention to those skilled in the art. Like numbers refer to like elements throughout, and the prime notation, if used, indicates similar elements in alternative embodiments or positions. 
     In the following discussion, numerous specific details are set forth to provide a thorough understanding of the present invention. However, it will be obvious to those skilled in the art that the present invention may be practiced without such specific details. Additionally, for the most part, details concerning well drilling, reservoir testing, well completion, and the like have been omitted inasmuch as such details are not considered necessary to obtain a complete understanding of the present invention, and are considered to be within the skills of persons skilled in the relevant art. 
     Referring to  FIG. 1 , a well system  11  includes a wellbore  13  that is at least partially completed with a casing string  15 . In the illustrated embodiment wellbore  13  includes a lateral  17  having a heel  18  and a toe  20  extending horizontally from wellbore  13 . Wellbore  13  may be installed with a casing string  15  cemented in place with a cement layer  9 . Cement layer  9  may protect casing  15  and act as an isolation barrier. Lateral  17  may be uncased as shown. Alternatively lateral  17  may be completed with a casing string similar to casing string  15 . A production tubing string  19  is suspended within casing string  15  and lateral  17 . A production packer  7  placed within an annulus between production tubing string  19  and casing string  15  may isolate production tubing string  19  below an end of casing string  15 . Production string  19  may include an inflow control device  21  (three of which are shown) to aid in the controlled flow of fluid from a formation surrounding lateral  17  into production tubing  19  as described in more detail below. In the illustrated embodiment, each inflow control device  21  is isolated in a separate zone by an open hole packer  5 , two of which are shown. Production tubing  19  may be closed at toe  20 , or alternatively include a packer on an upstream end of production tubing  19  to prevent direct flow of reservoir fluids into a bore of production tubing  19 . In alternative embodiments, shown in dashed lines in  FIG. 1 , wellbore  13  may not include lateral  17  and will extend vertically to a terminus of wellbore  13 ′. Casing string  15 ′ may extend to the terminus of wellbore  13 ′ and production tubing  19 ′, having inflow control devices  21 ′, and will not include horizontal portions, but will complete the well in a vertical manner as shown. 
     Referring to  FIG. 2A , inflow control device  21  is shown in a side sectional view. Inflow control device  21  may be a tubular member  23  having threaded pin connection  25  at a downhole end of tubular member  23 , i.e. closer to toe  20  of lateral  17 , and a threaded box connection  27  at an uphole end of tubular member  23 , i.e. closer to heel  18  of lateral  17 . Tubular member  23  has an outer diameter  29  and defines a central bore  31  having an axis  33 . Production tubing  19  may couple to tubular member  23  at threaded connections  25 ,  27  so that fluid, such as reservoir fluid, drilling fluid, cleaning fluid, or the like may be circulated through central bore  31 . 
     A tubular housing  35  having a conical ends  37  encircles tubular member  23 . Conical ends  37  will join to tubular member  23  at outer diameter  29  of tubular member  23  so that fluid may not flow into tubular housing  35  along outer diameter  29  of tubular member  23 . Although described herein as separate components, tubular housing  35  and tubular member  23  may be integral components formed as a single body. Tubular housing  35  includes annular standoffs  39  positioned on an outer diameter of tubular housing  35  at opposite ends of tubular housing  35 . Standoffs  39  will contact an inner diameter of casing string  15  ( FIG. 1 ) or wellbore  17  ( FIG. 1 ) so that an annulus may be maintained around inflow control device  21 . Tubular housing  35  will have an inner diameter greater than outer diameter  29  to form an annulus  41  between tubular member  23  and tubular housing  35 . Tubular housing  35  may define an annular recess or opening  43  in fluid communication with annulus  41 . A filter media  45  will be positioned within annular opening  43  so that fluid in casing string  15  or lateral  17  may flow into annulus  41  through filter media  45 . Filter media  45  may be any suitable media type such as a wire screen or the like, provided the selected media prevents flow of undesired particulate matter from lateral  17  into annulus  41 . 
     Annulus  41  may communicate with central bore  31  through fluid passages formed in tubular housing  35 . In the illustrated embodiment, a fluid wash port  47  is positioned proximate to threaded pin connection  25  and extends from central bore  31  into annulus  41 . Fluid wash port  47  may be positioned between opening  43  and conical end  37  of tubular housing  35  so that, as described in more detail below, fluid may flow from central bore  31  into annulus  41  and through filter media  45  under predetermined conditions. Fluid wash port  47  is an annular flow passage, and a compressible disc  49  may be positioned within fluid wash port  47 . Compressible disc  49  is an annular member formed of a suitable material so that compressible disc  49  may compress when subjected to a predetermined fluid pressure to allow fluid communication between central bore  31  and annulus  41  as described in more detail below. 
     In the illustrated embodiment, annulus  41  may define a fluid collecting chamber  51 . Fluid collecting chamber  51  is an annular chamber proximate to opening  43  and filter media  45  opposite fluid wash port  47 . Fluid may flow from lateral  17  through filter media  45  and into fluid collecting chamber  51 . A plurality of isolated passages  53  may extend from fluid collecting chamber  51  to a piston fluid port  55  opposite fluid wash port  47  and proximate to box end connection  27 . In the illustrated embodiment, eight passages  53  are used; however, a person skilled in the art will understand that more or fewer passages  53  may be used depending on the nature of the well into which inflow control device  21  is placed. In an alternate embodiment, twelve passages  53  are used. Each passage  53  will be spaced equidistantly around the circumference of tubular member  23  from the adjacent passages  53 . Each passage  53  will include two flow restrictors  57  positioned within passage  53  proximate to fluid collecting chamber  51  so that fluid in fluid collecting chamber  51  may flow through flow restrictors  57 . A pressure drop device  59  will then be positioned within passage  53  proximate to flow restrictors  57  so that fluid flowing through flow restrictors  57  may flow into pressure drop device  59 . Fluid flowing through pressure drop device  59  may then flow out of a tubing inflow port  61  into central bore  31 . A piston  63  will be positioned within passage  53  in the fluid flow path of fluid flowing from pressure drop device  59 . Piston  63  may move to variably allow or prevent fluid flow from pressure drop device  59  to enter central bore  31 . Piston fluid port  55  allows fluid communication between piston  63  opposite pressure drop device  59  and central bore  31  to actuate movement of piston  63  to prevent fluid flow through tubing inflow port  61 . 
     As shown in  FIG. 2B , during a production phase, fluid from a reservoir surrounding lateral  17  ( FIG. 1 ) may flow through inflow control device  21  as indicated by fluid  46 . Fluid will pass through filter media  45  into inflow control device  21 . There fluid will be directed through upstream and downstream flow restrictors  57  as described in more detail below. After flowing through flow restrictors  57 , fluid will be directed through pressure drop device  59 . From pressure drop device  59 , fluid may flow into central bore  31  as described in more detail below. Referring to  FIG. 2C , during a remedial or backwash phase, fluid may be circulated down production tubing string  19  ( FIG. 1 ) into central bore  31  of inflow control device  21  as indicated by fluid  48 . Piston  63  will prevent flow of fluid  48  from central bore  31  into pressure drop device  59  and downstream and upstream flow restrictors  57  as described in more detail below. Fluid  48  will have a sufficient fluid pressure to actuate pressure disc  49 . Fluid  48  may then flow through pressure disc  49  and through filter media  45  into the formation surrounding inflow control device  21  as described in more detail below. 
     Referring to  FIG. 3A , eight passages  53 A through  53 H are shown. Passages  53  partially circumscribe tubular member  23  so that fluid passing through each passage flows at least partway around tubular member  23 . When run-in-hole, at least one passage  53  will be positioned at a highest elevation of inflow control device  21 , i.e. a twelve o&#39;clock position as shown in  FIG. 3A . Similarly, at least one passage  53  will be positioned at a lowest elevation of inflow control device  21 , i.e. a six o&#39;clock position as shown in  FIG. 3A . As shown in  FIG. 3B , a terminus of each passage is 180° from a head of the respective passage  53  at fluid collecting chamber  51  ( FIG. 2A ). As shown in  FIG. 3C , a flow restrictor  57  is positioned on each end of passage  53 . For example, the eight passages of the illustrated embodiment are referred to as passages  53 A,  53 B,  53 C,  53 D,  53 E,  53 F,  53 G, and  53 H, herein. Passage  53 A will include a flow restrictor  57 A′ in passage  53 A proximate to fluid collecting chamber  51 . In the illustrated embodiment, flow restrictor  57 A′ will occupy a position that is closest to the surface or the twelve o&#39;clock position as shown in  FIG. 3A . A flow restrictor  57 K will also be located in passage  53 A proximate to pressure drop device  59  ( FIG. 2A ). Flow restrictor  57 A″ will occupy a position that is farthest to the surface or the six o&#39;clock position as shown in  FIG. 3B . Similarly, passage  53 E will include a flow restrictor  57 E′ in passage  53 E proximate to fluid collecting chamber  51 . Flow restrictor  57 E′ will occupy a position that is farthest to the surface or the six o&#39;clock position as shown in  FIG. 3A . A flow restrictor  57 E″ will also be located in passage  53 E proximate to pressure drop device  59  ( FIG. 2A ). Flow restrictor  57 E′ will occupy a position that is closest to the surface or the twelve o&#39;clock position as shown in  FIG. 3A . Inflow control device  21  will be placed in lateral  17  so that at least one passages  53 A,  53 B,  53 C,  53 D,  53 E,  53 F,  53 G, and  53 H will occupy the uppermost position, i.e. the twelve o&#39;clock position, and at least one will occupy the lowermost position, i.e. the six o&#39;clock position. 
     Referring to  FIG. 3C , each flow restrictor  57  includes an upstream chamber  65  and a downstream chamber  67 . An upstream ball  69  is positioned within upstream chamber  65 , and a downstream ball  71  is positioned within downstream chamber  67 . An upstream porting wall  73  having a port  75  separates upstream chamber  65  from downstream chamber  67 , and a downstream porting wall  77  having a port  79  separates downstream chamber  67  from the next operation in passage  53 . As shown in  FIG. 3D , downstream porting wall  77  may be a bulkhead having an area equivalent to the cross sectional area of downstream chamber  67  so that fluid flow through downstream chamber  67  may only occur through port  79 . Similarly, as shown in  FIG. 3E , upstream porting wall  73  may be a bulkhead having an area equivalent to the cross sectional area of upstream chamber  65  so that fluid flow through upstream chamber  65  may only occur through port  75 . 
     Each pair of flow restrictors  57  in each passage  53  may operate as described with respect to  FIGS. 4-8 . As shown in  FIG. 4 , each flow restrictor  57  has a width substantially equivalent to the diameter of upstream and downstream balls  69 ,  71  so that, balls  69 ,  71  may not move around the circumference of tubular member  23 . As shown in  FIG. 3C , balls  69 ,  71  may move radially toward outer diameter  29  of tubular member  23  ( FIG. 1 ) or toward the inner diameter of tubular housing  35 . In addition, balls  69 ,  71  may move axially in line with axis  33  ( FIG. 1 ). By restricting circumferential movement of upstream ball  69  and down stream ball  71 , effective removal of high water-to-oil ratio and gas-to-oil ratio fluid is restricted from passing into central bore  31 , as described in more detail below. Upstream ball  69  has a density less than the density of oil in the formation reservoir, allowing upstream ball  69  to float in reservoir oil. Downstream ball  71  has a density that is the same as the density of oil in the formation reservoir, allowing downstream ball  71  to neither float nor sink in reservoir oil. The actual densities of upstream ball  69  and downstream ball  71  will be selected based on testing data for the particular well in which inflow control device  21  will be used. 
       FIG. 5  and  FIG. 6  illustrate flow restrictors  57 A′ and  57 A″, respectively, in a production flow that is primarily reservoir oil with a low or minimal water-to-oil and gas-to-oil ratio. Flow restrictors  57 A′ and  57 A″ will be positioned within lateral  17  ( FIG. 1 ) so that  57 A′ and  57 A″ are the uppermost and lowermost flow restrictors  57 , respectively, as illustrated in  FIGS. 3A-3C . A person skilled in the art will understand that operation of flow restrictor  57 E″ will be similar to that of flow restrictor  57 A′, and operation of flow restrictor  57 E′ will be similar to that of flow restrictor  57 A″. As illustrated in  FIGS. 5 and 6 , and applicable to  FIGS. 4-18 , upstream porting wall  73  has a height that is equal to twice the diameter of upstream ball  69 . Port  75  in upstream porting wall  73  will be positioned so that a portion of upstream porting wall  73  extending radially outward from a portion of flow restrictor  57  proximate to central bore  31  has a height that is equivalent to a diameter of upstream ball  69 . Downstream porting wall  77  has a height that is equal to twice the diameter of downstream ball  71 . Port  79  in downstream porting wall  77  will be positioned proximate to tubular housing  35  so that a center of port  79  will align with a center of downstream ball  71  when downstream ball  71  contacts tubular housing  35  and downstream porting wall  77 . 
     When the fluid flowing through flow restrictors  57 A′ and  57 A″ has a low gas-to-oil ratio and a low water-to-oil ratio, as illustrated in  FIGS. 4 ,  5  and  6 , upstream balls  69 A′ and  69 A″, having a density less than the density of the reservoir fluid, will float, and downstream balls  71 A′ and  71 A″ will mix with the fluid. Referring to  FIG. 4 , upstream ball  69 A will be pushed against upstream porting wall  73  by the fluid flow. Downstream ball  71 A will mix within the reservoir oil and neither float nor sink. The fluid flow through downstream chamber may be turbulent or slightly non-steady. In such a fluid flow rate, the density of downstream ball  71 A allows the ball to roll and move within downstream chamber  67 A rather than move to block port  79 A in downstream porting wall  77 A. Referring to  FIG. 5 , upstream ball  69 A′ will float to a position in contact with tubular housing  35  and upstream porting wall  73 A′. In this position, upstream ball  69 A′ will partially block port  75 A′ in upstream porting wall  73 A′, allowing a partial flow of reservoir oil. Downstream ball  71 A′ will mix within the reservoir oil. Reservoir oil may flow through port  79 A′ of downstream porting wall  77 A′ uninhibited by downstream ball  71 A′. Referring to  FIG. 6 , upstream ball  69 A″ will float to a position in contact with tubular housing  35  and upstream porting wall  73 A″. In this position, upstream ball  69 K will not block port  75 A″ in upstream porting wall  73 A″, allowing flow of reservoir oil uninhibited by upstream ball  69 A″. Downstream ball  71 K will mix within the reservoir oil. Reservoir oil may flow through port  79 A″ of downstream porting wall  77 K uninhibited by downstream ball  71 K. 
       FIGS. 7 and 8  illustrate exemplary flow restrictors  57 , such as flow restrictors  57 B,  57 C,  57 D,  57 F,  57 G, and  57 H, that do not occupy the uppermost and lowermost positions of inflow control device  21  when inflow control device  21  is installed in lateral  17 . As illustrated, in reservoir oil flow having a low gas-to-oil ratio and a low water-to-oil ratio, both upstream balls  69  and downstream balls  71  will be carried by the fluid flow stream so that upstream balls  69  block port  75  in upstream porting wall  73  and downstream balls  71  block port  79  in downstream porting wall  77 , preventing flow of fluid through flow restrictors  57 B,  57 C,  57 D,  57 F,  57 G, and  57 H in the illustrated embodiment. Thus, as shown, in a fluid flow having a low gas-to-oil ratio and a low water-to-oil ratio, only flow restrictors  57 A and  57 E will allow fluid flow through flow restrictors  57 . 
       FIGS. 9-13  illustrate operation of flow restrictors  57  in a fluid flow from the reservoir having a high gas-to-oil ratio. As illustrated in  FIG. 9 , fluid flow having a high gas-to-oil ratio will move upstream ball  69 A and downstream ball  71 A against upstream porting wall  73 A and downstream porting wall  77 A, respectively. Referring to  FIG. 10 , upstream ball  69 A′ and downstream ball  71 A′, having a density that is greater than the high gas-to-oil ratio reservoir fluid, will sink. The fluid flow will carry upstream ball  69 N to a position in contact with tubular member  23  and upstream porting wall  73 A′. In this position, upstream ball  69 A′ will not inhibit flow through port  75 A′ of upstream porting wall  73 N. Similarly, the fluid flow will carry downstream ball  71 A′ to a position in contact with tubular member  23  and downstream porting wall  77 A′. In this position, downstream ball  71 N will not inhibit flow through port  79 A′ of downstream porting wall  77 A′. 
     Referring to  FIG. 11 , upstream ball  69 K and downstream ball  71 K, having a density that is greater than the high gas-to-oil ratio reservoir fluid, will sink. The fluid flow will carry upstream ball  69 K to a position in contact with tubular housing  35  and upstream porting wall  73 K. In this position, upstream ball  69 K will partially inhibit flow through port  75 A″ of upstream porting wall  73 K. Similarly, the fluid flow will carry downstream ball  71 K to a position in contact with tubular housing  35  and downstream porting wall  77 K. In this position, downstream ball  71 A″ will prevent flow through port  79 A″ of downstream porting wall  77 A″. 
       FIGS. 12 and 13  illustrate exemplary flow restrictors  57 , such as flow restrictors  57 B,  57 C,  57 D,  57 F,  57 G, and  57 H, that do not occupy uppermost and lowermost positions of inflow control device  21  when inflow control device  21  is installed in lateral  17 . As illustrated, in reservoir oil flow having a high gas-to-oil ratio, both upstream balls  69  and downstream balls  71  will be carried by the fluid flow stream so that upstream balls  69  block port  75  in upstream porting wall  73  and downstream balls  71  block port  79  in downstream porting wall  77 , preventing flow of fluid through flow restrictors  57 B,  57 C,  57 D,  57 F,  57 G, and  57 H in the illustrated embodiment. Thus, in the illustrated embodiment, in a fluid flow having a high gas-to-oil ratio, fluid flow through flow restrictors  57  will be prevented by flow restrictors  57 A″ and  57 E′ in the lowermost flow restrictor  57  position of inflow control device  21 . 
       FIGS. 14-18  illustrate operation of flow restrictors  57  in a fluid flow from the reservoir having a high water-to-oil ratio. As illustrated in  FIG. 14 , fluid flow having a high water-to-oil ratio will move upstream ball  69 A and downstream ball  71 A against upstream porting wall  73 A and downstream porting wall  77 A, respectively. Referring to  FIG. 15 , upstream ball  69 A′ and downstream ball  71 A′, having a density that is less than the high water-to-oil ratio reservoir fluid will float. The fluid flow will carry upstream ball  69 A′ to a position in contact with tubular housing  35  and upstream porting wall  73 A′. In this position, upstream ball  69 N will partially inhibit flow through port  75 N of upstream porting wall  73 A′. Similarly, the fluid flow will carry downstream ball  71 A′ to a position in contact with tubular housing  35  and downstream porting wall  77 A′. In this position, downstream ball  71 A′ will prevent flow through port  79 A′ of downstream porting wall  77 A′. 
     Referring to  FIG. 16 , upstream ball  69 A″ and downstream ball  71 K, having a density that is less than the high water-to-oil ratio reservoir fluid will float. The fluid flow will carry upstream ball  69 K to a position in contact with tubular member  23  and upstream porting wall  73 K. In this position, upstream ball  69 K will not inhibit flow through port  75 K of upstream porting wall  73 K. Similarly, the fluid flow will carry downstream ball  71 K to a position in contact with tubular member  23  and downstream porting wall  77 A″. In this position, downstream ball  71 A″ will not inhibit flow through port  79 A″ of downstream porting wall  77 A″. 
       FIGS. 17 and 18  illustrate exemplary flow restrictors  57 , such as flow restrictors  57 B,  57 C,  57 D,  57 F,  57 G, and  57 H, that do not occupy the uppermost and lowermost positions of inflow control device  21  when inflow control device  21  is installed in lateral  17 . As illustrated, in reservoir oil flow having a high water-to-oil ratio, both upstream balls  69  and downstream balls  71  will be carried by the fluid flow stream so that upstream balls  69  block port  75  in upstream porting wall  73  and downstream balls  71  block port  79  in downstream porting wall  77 , preventing flow of fluid through flow restrictors  57 B,  57 C,  57 D,  57 F,  57 G, and  57 H in the illustrated embodiment. Thus, in the illustrated embodiment, in a fluid flow having a high water-to-oil ratio, fluid flow through flow restrictors  57  will be prevented by flow restrictors  57 A′ and  57 E″ located in the uppermost flow restrictor  57  position of inflow control device  21 . 
     Referring to  FIG. 19 , an end view of pressure drop device (PDD)  59  is shown. A PDD  59  will be located in each passage  53  downstream of flow restrictors  57  so that fluid flowing through each pair of flow restrictors  57  will flow into a separate PDD  59 . As shown in  FIG. 19 , tubular housing  35  and tubular member  23  may be substantially sealed to PDD  59  so that fluid may not flow around an exterior of PDD  59 . PDD  59  may include a PDD housing  81 , a fluid outflow port  83 , and a pressure equalization port  85 . 
     Referring to  FIGS. 20-22 , pressure equalization port  85  allows fluid communication with an interior of a rod housing  87 . Rod housing  87  defines a fluid chamber having a shaft chamber  89  and a piston head chamber  91 . Shaft chamber  89  will have a diameter less than that of piston head chamber  91 . A pressure piston  93  having a piston shaft  95  and a piston head  97  may be positioned within rod housing  87  so that piston shaft  95  is positioned within shaft chamber  89  and piston head  97  is positioned within piston head chamber  91 . Pressure piston  93  may have a T shape as shown. In the illustrated embodiment pressure piston  93  is formed of a non-metallic material having a density greater than that of reservoir water. A person skilled in the art will understand that pressure piston  93  may be formed of other materials and in different configurations, provided pressure piston  93  operates as described below. 
     Piston shaft  95  may moveably seal to shaft chamber  89  so that fluid in piston head chamber  91  may not flow around piston shaft  95  into shaft chamber  89 . Passage  53  will be in fluid communication with an end of piston head chamber  91  so that fluid flowing from flow restrictors  57  may flow into piston head chamber  91 . Piston head chamber  91  will include a plurality of ports  101  allowing for fluid communication between piston head chamber  91  and an annulus  99  formed between PDD housing  81  and rod housing  87 . Annulus  99  may be in fluid communication with fluid outflow port  83 . Piston head  97  has an outer diameter that is substantially equivalent to the inner diameter of piston head chamber  91 . Piston head  97  may move within piston head chamber  91  to inhibit fluid flow through one or more of the plurality of ports  101 . Movement of pressure piston  93  is influenced in part by the length of piston shaft  95  and piston head  97 . An increased length of piston shaft  95  and/or piston head  97  will increase the mass of pressure piston  93  that fluid flowing from passage  53  must move to flow to inflow production port  61 , as described in more detail below. Flow through the plurality of ports  101  creates a varying pressure differential based on the number of ports  101  through which fluid can flow freely. Thus, the plurality of ports  101  reduce the flow rate into inflow fluid port  61 . Fluid within piston shaft chamber  89  may be in fluid communication with inflow fluid port  61  through pressure equalization port  85 . A PDD filter media  103  may be positioned within pressure equalization port  85  to prevent movement of particulate matter into piston shaft chamber  89 . 
     PDD  59  may operate as described below with respect to  FIGS. 23-26 . When inflow control device  21  ( FIG. 2A ) is run into position within lateral  17  ( FIG. 1 ), pressure piston  93  will be in the position illustrated in  FIG. 25 . Fluid flow from passage  53  will be limited or prevented through the plurality of ports  101 . Pressure piston  93  will move in response to the pressure of the reservoir oil flow. As shown in  FIG. 23 , in reservoir oil flow having a low gas-to-oil ratio, a low water-to-oil ratio, and a low pressure reservoir oil flow, pressure piston  93  will move partially past the plurality of ports  101  so that only a portion of the plurality of ports  101  allow free flow of fluid from passage  53  into annulus  99 . Thus, production flow is reduced when the fluid pressure in the reservoir is reduced, aiding in the prevention of coning associated with over production from a particular zone of the reservoir. As shown in  FIG. 24 , in reservoir oil flow having a low gas-to-oil ratio, a low water-to-oil ratio, and a high pressure reservoir oil flow, pressure piston  93  will move past the plurality of ports  101  so that most of the plurality of ports  101  allow free flow of fluid from passage  53  into annulus  99 . Thus, production flow is reduced less when the fluid pressure in the reservoir is increased, allowing increased fluid flow when warranted by sufficient reservoir pressure. 
     As shown in  FIG. 25 , in reservoir oil flow having a low gas-to-oil ratio, a high water-to-oil ratio, and a low pressure reservoir oil flow, pressure piston  93  will move negligibly so that fluid may only flow through the plurality of ports  101  in a gap between piston head  97  and piston head chamber  91  ( FIG. 22 ). Thus, production flow is severely limited when the fluid pressure in the reservoir is reduced and the zone around inflow control device  21  produces a substantial amount of water, further limiting the amount of water produced to the surface. As shown in  FIG. 26 , in reservoir oil flow having a low gas-to-oil ratio, a high water-to-oil ratio, and a high pressure reservoir oil flow, pressure piston  93  will move partially past the plurality of ports  101  so that only a portion of the plurality of ports  101  allow free flow of fluid from passage  53  into annulus  99 . Thus, production flow is reduced when the fluid pressure in the reservoir is increased, but producing a greater than expected amount of water, aiding in the reduction of water production from the reservoir. In the disclosed embodiments, pressure piston  93  has a density greater than the density of the high water-to-oil ratio reservoir fluid. Thus, it will take significantly more pressure to move pressure piston  93  when the reservoir fluid has a high water-to-oil ratio. As pressure piston  93  moves within rod housing  87 , fluid in shaft chamber  89  may flow through pressure equalization port  85  to prevent over pressurization of shaft chamber  89  that would prevent movement of pressure piston  93  away from passage  53 . Similarly, fluid in shaft chamber  89  may flow through pressure equalization port  85  to prevent creation of a vacuum within shaft chamber  89  as pressure piston  93  moves toward passage  53 . Pressure piston  93  may be reset to the position illustrated in  FIG. 25  at any time during operation of inflow control device  21  in a manner described in more detail below. 
     Referring now to  FIG. 27 , fluid flow through fluid outflow port  83  may be may be restricted by piston  63 , which is downstream of PDD  59 . Piston  63  may have a first end  105  proximate to inflow fluid port  61 , and a second end  107  proximate to piston fluid port  55 . Fluid outflow port  83  terminates in inflow fluid port  61  opposite first end  105  of piston  63 . Piston  63  is moveable so that first end  105  may contact fluid outflow port  83  to prevent flow of fluid from PDD  59 , as described below. A piston biasing spring  109  is positioned between first end  105  of piston  63  and an oppositely facing wall of tubular housing  35  proximate to fluid outflow port  83 . In the illustrated embodiment, piston biasing spring  109  biases piston  63  to the position shown in  FIG. 27  so that fluid may flow from PDD  59  through fluid outflow port  83  into inflow fluid port  61  and then into central bore  31  for production to the surface. Piston  63  may be a cylindrical member positioned within a corresponding cylindrical chamber so that piston  63  may prevent flow through a respective flow passage  53  when first end  105  of piston  63  is in contact with a corresponding fluid outflow port  83 . In these embodiments, a separate piston  63  will correspond with each flow passage  53 . In alternative embodiments, piston  63  may be an annular member positioned within a corresponding annular chamber so that piston  63  may prevent flow through all flow passages  53  simultaneously. 
     Referring to  FIG. 28 , fluid may be pressurized from the surface so that fluid will flow into piston fluid port  55 . The fluid will act on second surface  107  of piston  63  moving piston  63  against fluid outflow port  83 , blocking flow of fluid into inflow fluid port  61  from PDD  59 . Piston biasing spring  109  will compress. When fluid pressure is removed from central bore  31 , piston biasing spring  109 , along with reservoir fluid pressure flowing through fluid outflow port  83  of PDD  59  will move piston  63  out of inflow fluid port  61 , allowing for production of reservoir fluid to the surface. 
       FIG. 29  illustrates a run-in-hole, ream, or circulation process that may be performed with inflow control device  21 . The processes as described with respect to  FIG. 29  are those which may be conducted while installing inflow control device  21  in place within lateral  17  ( FIG. 1 ). During the run-in-hole process of  FIG. 29 , fluid will be circulated down central bore  31  from the surface through production tubing  19 . The fluid will be circulated at a pressure sufficient to move piston  63  to the position of  FIG. 28 , preventing flow of circulation fluid from central bore  31  through PDD  59 , flow restrictors  57  and filter media  45 . Fluid pressure circulated through central bore  31  in the operative embodiment of  FIG. 29  will have a pressure less than that needed to actuate pressure disc  49 . Thus, pressure disc  49  will prevent flow of fluid from central bore  31  into fluid wash port  47 . 
     During a production process, as shown in  FIG. 2A , fluid pressure will not be applied to central bore  31 . Reservoir fluid will be allowed to flow through filter media  45  and into fluid collection chamber  51 . From fluid collection chamber  51 , fluid will flow into fluid passages  53  ( FIGS. 3A-3C ). In the illustrated embodiment, passage  53 A will be positioned to be at the point closest to the surface within lateral  17  ( FIG. 1 ). Reservoir fluid will flow through passages  53  and into respective flow restrictors  57 . Flow restrictors  57  will operate as described above with respect to  FIGS. 4-18  to prevent or limit the flow of high gas-to-oil ratio and high water-to-oil ratio reservoir fluid from passing through flow restrictors  57 . Reservoir fluid that is allowed to flow through flow restrictors  57  will then flow into PDDs  59 . There, each PDD  59  will create a varying pressure differential as described above with respect to  FIGS. 19-26  to aid in the creation of a balanced production profile across the entirety of lateral  17  ( FIG. 1 ). At anytime after production of fluid from the reservoir commences, pressure piston  93  ( FIG. 29 ) may be reset to the run-in-hole position of  FIG. 29  by applying fluid pressure to production string  19  in the manner described above with respect to  FIG. 29 . The applied fluid pressure will actuate piston  63  to close outflow port  83 . However, piston  63  will not prevent flow of fluid pressure through pressure equalization port  85 . Thus, fluid pressure may be applied to piston shaft  95 , causing pressure piston  93  to move to the position illustrated in  FIG. 25 . 
     During the production process of  FIG. 2A , production logging operations may be conducted to establish baseline performance of the well intervals in which inflow control device  21  is placed. When well production deviates significantly and unexpectedly, additional production logging operations may be conducted to determine which well interval is performing poorly. Once the interval is identified, a remedial process may be performed. Alternatively, the entire production string  19  and all inflow control devices  21  installed thereon may be washed in the same operation. Referring to  FIG. 30 , a remedial or cleanout process is shown. During the remedial process, a wash fluid, such as an acid wash like acidic brine, will be supplied to central bore  31  and raised to a fluid pressure greater than the fluid pressure applied during the run-in-hole process. For example, the fluid pressure needed to actuate pressure disc  49  may be approximately 1,500 p.s.i. above the fluid pressure within central bore  31  during the production process of  FIG. 2A . Further, the fluid pressure needed to actuate pressure disc  49  may be approximately 1,000 p.s.i. above the fluid pressure within central bore  31  during the run-in-hole or circulation process of  FIG. 29 . 
     The wash fluid will move piston  63  as described above with respect to  FIG. 31  to prevent flow of the wash fluid into PDD  59  and flow restrictors  57  through inflow fluid port  61 . The fluid pressure of the wash fluid will cause pressure disc  49  to compress, radially outward so that wash fluid may flow into fluid wash port  47 . The wash fluid may then flow through fluid wash port  47  and through filter media  45  into the reservoir. Thus, any particulate matter that may have lodged in filter media  45  may be removed by the reversal of fluid through filter media  45 . In an embodiment, the wash fluid comprises an acidic wash fluid so that particulates made of carbonate material, for instance where the wellbore penetrates a carbonate reservoir, may be dissolved by the wash fluid. Wash fluid pressure supplied through pressure disc  49  and wash port  47  may also be supplied to fluid collecting chamber  51  and passages  53 . In this manner, PDD  59  may also receive wash fluid pressure through flow restrictor  57 . Thus, pressure piston  93  of PDD  59  may receive wash fluid pressure at piston head  97  through flow restrictor  57  and wash fluid pressure at piston shaft  95  through pressure equalization port  85  at inflow fluid port  61 . Piston head  97  may have a larger surface area subjected to wash fluid pressure than piston shaft  95 ; thus, pressure piston  93  may move to the position of  FIG. 31  during remedial operations of  FIG. 30 . By opening PDD  59  in this manner, when wash fluid pressure is removed from production tubing  19 , wash fluid pushed into the reservoir may flow back into central bore  31  through inflow control device  21 . This will allow wash fluid to be circulated out of production tubing  19 . A fluid pressure less than the activation pressure of pressure disc  49  may then be supplied from the surface to return PDD  59  to the position of  FIG. 25  for production operations as described above. In an embodiment, a separate operating media, such as coiled tubing, may supply fluid pressure to set PDD  59  to the position of  FIG. 25  for production operations as described above. 
     While illustrated and described with respect to a horizontal well completion, a person skilled in the art will understand that the disclosed inflow control device  21  may be used in a vertical well completion, such as that depicted in  FIG. 1 . Inflow control device  21  may generally operate as described above with respect to  FIGS. 2-30 , while requiring additional reservoir pressure to compensate for the additional restrictive effects of gravity. 
     Accordingly, the disclosed embodiments provide numerous advantages over prior art embodiments. For example, the disclosed embodiments provide an inflow control device that may be used to create a pressure drop to reduce reservoir fluid flow and maintain a balanced production profile across multiple production zones, particularly those at the same elevation. The disclosed inflow control devices accommodate varying reservoir pressure by varying the pressure differential in response to the reservoir pressure. Still further, the disclosed embodiments will restrict the flow of production fluid having high volumes of water or gas based on the ratio of those substances within the reservoir fluid. In addition, the disclosed embodiments will remove solid particulate matter from the reservoir fluid flow. The disclosed embodiments remove particulates and include a process to allow for washing of the inflow control device while in place in hole. This allows for better handling of viscous or heavy oil and a longer life of the inflow control device with fewer problems related to plugging or blockage as compared to other inflow control devices. Still further, the disclosed embodiments allow an operator to open and close the device from the surface without the need for additional hydraulic or electric equipment and umbilicals. 
     It is understood that the present invention may take many forms and embodiments. Accordingly, several variations may be made in the foregoing without departing from the spirit or scope of the invention. Having thus described the present invention by reference to certain of its preferred embodiments, it is noted that the embodiments disclosed are illustrative rather than limiting in nature and that a wide range of variations, modifications, changes, and substitutions are contemplated in the foregoing disclosure and, in some instances, some features of the present invention may be employed without a corresponding use of the other features. Many such variations and modifications may be considered obvious and desirable by those skilled in the art based upon a review of the foregoing description of preferred embodiments. Accordingly, it is appropriate that the appended claims be construed broadly and in a manner consistent with the scope of the invention.