Patent Publication Number: US-7725301-B2

Title: System and method for estimating multi-phase fluid rates in a subterranean well

Description:
TECHNICAL FIELD 
   The invention relates to methods and systems for estimating multi-phase fluid flow rates in a subterranean well. More particularly, the invention relates to methods and systems that provide estimates of multi-phase fluid flow rates using modeling based on static and transient well characteristics. 
   BACKGROUND OF THE INVENTION 
   In subterranean oil and gas wells, rates and volumes of fluids and gases are typically measured by meters and other physical means at the surface. Multi-phase fluid flow is a term used in the industry to indicate that gas, oil and water may be flowing in various combinations. For example, it is known to use a capacitance-probe technique or turbine flow meter or a combination of multiple techniques to measure the amount of free water and oil or gas passing through the well-head. Such measurements may be used to continuously monitor total oil production, to measure co-mingled production streams, and to determine total water, oil and gas production for the well. It is also known in the art to obtain data from downhole with remote sensors such as temperature or pressure transducers or flow meters. Such data is stored in downhole memory and replayed after the tools are retrieved from the well. Such measurements may also be obtained and transmitted to the surface in real time. 
   Production estimation is generally performed by direct measurements of production rates, over time, at the surface of the well. Pressure and temperature conditions are sometimes used to adjust metered gas or liquid per volume measured at the surface. Problems arise, however, due to an inability of current systems and methodology to obtain measurements of downhole multi-phase flow rates near where fluids first enter the wellbore. Problems associated with the inability to determine multi-phase fluid rates include, but are not limited to, limitations on assessing the efficiency of production and injection operations, incomplete information for planning remedial operations, and inaccuracies in logging production from the various production zones within the well. 
   Improvements in the ability to determine downhole multi-phase fluid rates would result in better monitoring of the various production streams within the well despite their becoming co-mingled at the surface and in making decisions concerning well management, such as injection and stimulation decisions. Methods and systems capable of providing timely and accurate estimates of multi-phase fluid rates would be useful and desirable in the arts for enhancing multi-phase flow profiling, improving production, improving monitoring of production and injection operations, and making workover and stimulation decisions. 
   SUMMARY OF THE INVENTION 
   In general, the invention provides methods and systems for estimating multi-phase fluid flow rates in a subterranean well using modeling based on static and transient well characteristics. 
   According to one aspect of the invention, a method of estimating multi-phase fluid flow rates in a subterranean well includes steps for measuring static and transient conditions in the subterranean well and for modeling the subterranean well using the measured conditions. The multi-phase fluid flow rates are estimated by iteratively comparing measured static and transient well conditions with the model for the well. 
   According to yet another aspect of the invention, temperature measurements are included in the model. 
   According to yet another aspect of the invention, pressure measurements are included in the model. 
   According to still another aspect of the invention, estimated multi-fluid flow rates are provided for a plurality of selected well locations. 
   According to another aspect of the invention, the transient measuring steps and modeling steps are performed in real time. 
   According to another aspect of the invention, the method of estimating multi-phase fluid flow rates in a subterranean well includes steps for measuring the static physical, rheological and thermal characteristics of the subterranean well. The rheological properties are of the fluid and not of the wellbore. These properties are measured as function of pressure and temperature. Steps are also provided for measuring the transient temperature, pressure and wellhead flow rate. The subterranean well is modeled using these measurements to estimate multi-phase fluid flow rates in the subterranean well. 
   According to still another aspect of the invention, the methods include steps for selecting a tolerance level for the match between the measurements and the model response and reiterating the modeling step until the tolerance level is met. 
   According to yet another aspect of the invention, the step of measuring and interpreting the transient temperature characteristics of the subterranean well includes modeling conductive and convective heat flow within the subterranean well. 
   Also disclosed is a system for estimating multi-phase fluid flow rates in a subterranean well. The system includes a computer with user input means, display means and software that operates in accordance with the methodologies of the invention. The software includes a multi-phase fluid flow rate program having a simulation model adapted for receiving data inputs corresponding to pressure and temperature measurements and for calculating a plurality of fluid flow rates from multi-phase fluids in a subterranean well. 
   According to another aspect of the invention, the system includes a data path extending from a computer into the subterranean well for coupling a plurality of temperature and pressure sensors to the computer in order to deliver pressure and temperature measurements from within the subterranean well to the computer. 
   Technical advantages are provided by the invention, including but not limited to improved speed and accuracy in providing multi-phase fluid rate estimates. Use of the invention also results in further advantages in terms of well productivity and control. 

   
     BRIEF DESCRIPTION OF THE DRAWINGS 
     For a better understanding of the invention including its features, advantages and specific embodiments, reference is made to the following detailed description along with accompanying drawings in which: 
       FIG. 1  is a block diagram showing a cutaway view of a subterranean well illustrating use of the methods and systems of the invention according to one embodiment; 
       FIG. 2  is a block diagram showing the functional elements of a system for estimating multi-phase fluid rates according to one embodiment of the invention; 
       FIG. 3  is a process flow diagram illustrating the methods of estimating multi-phase fluid rates in a subterranean well according to one embodiment of the invention; and 
       FIG. 4  is a block diagram showing the inputs to a model and illustrating the process of estimating multi-phase flow rate according to the invention. 
   

   References in the detailed description correspond to like references in the figures unless otherwise noted. Like numerals refer to like parts throughout the various figures. The descriptive and directional terms used in the written description such as top, bottom, left, right, etc., refer to the drawings themselves as laid out on the paper and not to physical limitations of the invention unless specifically noted. The drawings are not to scale and some features of embodiments shown and discussed are simplified or exaggerated for illustrating the principles of the invention. 
   DETAILED DESCRIPTION OF PREFERRED EMBODIMENTS 
   While the making and using of various embodiments of the present invention are discussed in detail below, it should be appreciated that the present invention provides many applicable inventive concepts which can be embodied in a wide variety of specific contexts. It should be understood that the invention may be practiced with computer or software platforms of various types and using various machine readable instruction languages without altering the principles of the invention. Those skilled in the arts will also recognize that the practice of the invention is not limited to a particular subterranean well geometry, production apparatus or method, or sensor technology. 
   Referring to  FIG. 1 , in general, subterranean well  10  begins with a wellbore  12  lined with multiple concentric tubular members  14 ,  16  and  18 . Generally, the inner member  18  terminates at successively deeper locations as compared to outer members  14  and  16 . The annular space  20  between the consecutive tubular members  18  and  16 , for example, may be filled with cement or some other solid, liquid or gas, or a combination of columns of solids and fluids. Fluid flow may be upwards or downwards in the innermost tubing  18  or in any of the outer annular spaces  20 , with possible simultaneous flow of fluids in either direction. Although a simplified vertical wellbore  12  is described for the sake of example, it will be understood that the wellbore  12  may also be angled, horizontal, or a combination of horizontal and vertical segments. 
   Uphole production flow toward the wellhead  22  typically includes multiple measured-depth-separated entries  24  which carry fluid, typically deep within the well  10 . It is well known that each of the entries  24  has its own fluid phase (whether it be oil, water or gas), flow rate, temperature, and hydrocarbon-mixture composition. For example, as fluids enter the production flow path defined by innermost tubing  18 , through different entries  24 , they typically mix and travel uphole as a combined composition. Typically, fluid flow rate and fluid composition vary over different segments of the well  10 , including the spaces defined by the entry locations  24 , the production zones  26 , and the wellhead  22 . Commonly, the well  10  may be segmented by packers  28  in order to control the pressure and flow characteristics of the production stream  20  at the various entry points  24 . Preferably, a plurality of sensors  27  are deployed to take measurements at the various production zones  26  or other points of interest inside the wellbore  12 . The sensors  27  are preferably downhole temperature and pressure transducers coupled to a computer  32  by a wireline or wireless telemetry path  31 . The sensors  27  may include, but are not limited to, fiber optic distributed temperature sensing (“DTS”) systems, thermocouples, and thermistors as well as pressure transducers known in the art. 
   According to the invention, the computer  32  incorporates the functionality of a mathematical model  30  designed to simulate the physical processes of the flow of multi-phase fluid, which typically consists of oil, gas and/or water within the wellbore  12 . As used herein, the term “multi-phase fluid flow” will include fluid flow with just one phase, as well as fluid flow with two or more phases. Preferably this model  30  resides in a computer  32  and is provided with data  33  relating to known physical laws and standard geological and rheological data. The computer  32  typically includes display  35  and input devices  37 . 
   As explained in more detail below, the model  30  takes into account the conservation of energy and mass, and consequently simulates the evolution of the temperature of the flowing fluid, the properties of the static well  10  and the tubular members  14 ,  16 ,  18 , the stationary contents of the various annular spaces  20 , and the geological formation rock  34  surrounding the wellbore  12 . It is known that pressure and temperature of the flowing fluids change as they travel up or down a flow path inside a tubular  18  or, for example, in the annular space  20  as a result of heat conduction, heat convection, heat generation due to friction, heat absorbed or heat released due to the evaporation of the liquid phase (oil and/or water) or condensation of the gas phase. Therefore, model  30  should take such factors into consideration. Transient pressure changes due to both hydrostatic and dynamics of the flow as well as fluid friction are also included in the model  30 , and model  30  may include two or more simultaneous fluid flows in different flow paths, and each flow may be either uphole or downhole. As used herein, the term “transient” shall apply to those conditions where a sudden change in flow rates is due to one or more changes in the setting of the surface or downhole flow controls. The flow rate at each entry location  24  is assumed to stay constant or change slowly and monotonically in a predictable manner after resetting of the flow controls. In the constant flow case, no significant change in the flow rate at each entry location  24  is assumed to occur over the period of time in which the transient measurements are made. The temperature at each sensor location changes over time due to readjustment of the heat exchange between the wellbore flow and the surrounding formation. The pressure will also change in association with the temperature changes. 
   Thermodynamic calculations based upon physical laws known in the arts are preferably used to help determine the partition of the hydrocarbon mass between the liquid (e.g. oil) and gas phases. The thermodynamic calculations are also used along with published laboratory measurements of different fluid property parameters to calculate the various physical properties of each fluid phase. Preferably, the parameters, density, viscosity, specific heat capacity, and heat conductivity applicable to the well  10  are determined for use with the model  30 . 
   The user-specified geometry of the well  10  and its construction is used to constitute the static physical domain over which the flow and heat equations are solved. The surrounding rock  34  is included in the domain for calculation of the transient heat flow. The geological temperature distribution versus the depth in the wellbore  12  is typically used as a starting condition and a boundary condition for the heat flow computations. The user of the invention may specify, using a computer input device such as a keyboard  37 , the mass flow rate of each phase and the temperature at each entry point  24  within the well  10 . The fluid pressure may be specified at each one of the entries  24  or at the wellhead  22 . 
   A better understanding of the invention may be obtained by reference to  FIG. 2 , which shows a block diagram for a system, denoted generally as  38 , according to the invention that utilizes multi-phase fluid flow rate model  30  in estimating multi-phase fluid flow rates in a subterranean well. Typically, the system  38  can take the form of software residing on a computer  32 , although it may alternatively reside in a network  46 , which may be coupled to the computer  32  through a communications link  48 . The model  30  may be stored by generally available means for storing pre-programmed, machine readable instructions, as known in the art. 
   A data path  31  extends into the wellbore  12 . The data path  31  supplies transient data to the model  30 , such as, for example, measured pressure data  42  and temperature data  43  measured at multiple downhole locations. Additional data  44  relating to the transient conditions of the well may also be provided, such as, for example, whether particular valves have been opened or closed or whether particular production fluids have been introduced into the wellbore  12 . Additionally, static data  40 , such as data describing physical laws and properties of oil configurations and/or materials may also be provided to the model  30 . Although the compilations of data are shown separately in  FIG. 2 , the data may reside in computer  32  or elsewhere, such as in an external database distributed throughout the network  46 . It should also be understood that the computer  32  may be located at the wellhead or offsite many miles away. 
   In the model  30 , a method of finite difference is preferably used to solve the partial differential equations known in the arts for fluid flow and heat flow. The well domain is subdivided with a grid that covers the vertical and radial spatial domain. The time evolution of the flow and heat variations over the spatial domain are calculated by subdividing the time in variable steps. At each time step, the fluid flow along the flow path is calculated using an explicit method of solution. The heat flow equation is preferably solved using the Alternate Direction Implicit (“ADI”) method known in the arts, although other techniques may be used. 
     FIG. 3  is a process flow diagram illustrating a preferred implementation of the method of multi-phase fluid rate of the invention operating using the preferred techniques described above. As shown at step  100 , an initial estimate of the flow rate from each stratum or zone to be produced is acquired and input to the calculations. At step  102 , static data, preferably including properties of the well  10  such as the geometry of the wellbore  12 , properties of well fluids and solids, Pressure/Volume/Temperature (“PVT”) data for hydrocarbons and water, formation properties, and undisturbed temperature distribution in the formation is entered into the model  30 . Initial conditions from the well bore may be entered into the model  30  as well. The initial conditions may either be initial static conditions or initial steady-state flow conditions. 
   In circumstances where neither the static temperature profile for a zero flow condition is known, nor an initial flowing condition temperature profile is known, the model  30  may be loaded with an initial condition data set from another source. A non-limiting example of such an initial condition data set may be when a service company arrives at a well site which has already installed temperature and/or pressure sensors, and the well is already flowing, and opportunity for shutting the well or running a production log does not exist or is cost prohibitive. The service company may interface to a surface box which receives the measurements from the DTS and/or pressure sensor outputs, and take an “initial condition” reading set while the well is in production flow. This initial condition reading set is then inputted into the model  30  along with “initial” flow profile derived from a separate theoretical model, actual offset well data, field/reservoir empirical model, field or reservoir statistics, or any alternative modeling approach. From this starting point, measured changes in the temperature and pressure profile over time is inputted into the iterative model  30 . Of course, other parameters germane to a particular well may also be input for incorporation into the model  30 . 
   As used herein, the term “steady-state flow” shall apply to those situations where after a long period of production, the flow-rates from the different entries  24  have settled down to constant values, as have the pressure and temperature profiles in any wellbore flow path. The well is now in a steady-state condition (or nearly so, so that it can be modeled using a steady-state solution to the simulation problem) at the start of the measurement process. Steady-state flow data may be used as the initial condition of the model  30 , from which the subsequent transient flow can be assumed to occur and modeled. Thus, the steady-state flow condition may replace the “static” initial condition. Additionally, the initial steady-state multi-phase flow rates entering the wellbore  12  at each entry point  24  may be estimated along with the same flow rates after the change that caused the transient condition. 
   Transient well data is measured, step  104 , preferably including pressure and temperature data in the wellbore  12  above each flow entry being produced. It should be understood that the measurement above each flow entry is not required for the solution of the inverse problem. Pressure and temperature measurements may also be obtained for various other locations downhole and at the wellhead  22 . Volumetric flow rate measurements for each phase at the wellhead  22  are also obtained. In step  106 , the mathematical model for the wellbore  12  is run to calculate the expected pressure and temperature values at the downhole sensor locations, the expected volumetric phase flow rates at the wellhead  22 , and sensitivity coefficients of the model response to each phase flow rate at each fluid entry location. 
   With continued reference to  FIG. 3 , in step  108 , the expected wellhead volumetric flow of each phase calculated in step  106  is compared with the measured volumetric phase flow rate obtained in step  104 . Also in step  108 , the model-calculated expected pressure and temperature values for various well locations of step  106  are preferably compared with the measured temperature and pressure values obtained in step  104  with respect to those same well locations. Thus, at step  108 , the actual transient data is compared with the calculated expectations of the model. Preferably, acceptable tolerance levels are preselected for the comparisons. 
   As shown by arrow path  110 , in step  112 , the deviation between the calculated and measured quantities (of step  108 ) may be used with the sensitivity coefficients of the model (from step  106 ) to determine changes necessary for the estimate of phase flow rates at each well entry point. In this way, the modeling comparisons may be reiterated, following arrow path  114 , until an approximate match (within acceptable tolerances) is obtained between the calculated well properties and related flow rates and the measured well properties and flow rates. As shown by arrow path  116 , if the measured volumetric phase rates and pressure and temperature readings are in tolerable agreement with the expected values predicted by the model  30 , the final estimates of the multiphase flow rates are provided as shown at step  118 . 
     FIG. 4  is an architectural block diagram showing the various inputs used by a model, such as model  30 , which can be used by system  38  for estimating multi-phase fluid flow rates according to the invention. As shown in  FIG. 4 , the model  30  may reside on a computer  32 . Of course, it is contemplated that the computer  32  may actually take the form of multiple computers linked in a distributed computer network and that the model  30  may be accessed and implemented either at the wellhead  22  or offsite. 
   Static physical characteristics  60  of the subterranean well are measured, such as well geometry, and are provided to the model  30 . Similarly, known rheological characteristics of fluids being produced by or introduced into the well are provided to the model at block  62 . Static thermal characteristics, represented by block  64 , of both the wellbore  12  and the surrounding formation and fluids are also provided to the model  30 . Preferably, as shown at blocks  66  and  68  respectively, transient pressure and transient temperature are measured at a plurality of locations downhole for provision to the model  30 . Of course, the relationship between pressure and temperature may also be used to supplement or substitute for selected transient pressure and temperature data. 
   Preferably, as shown in box  70 , the wellhead flow rate is also provided to the model  30 . The transient data, in this example represented by blocks  66 ,  68  and  70 , are provided continuously to the model  30  or may be provided at regular intervals. The model  30  uses the static or steady-state flow initial condition data and measured transient data as are available to solve for estimated multi-phase flow rates as indicated at block  72 . The estimated multi-phase flow rate  74  may also be used in an iterative process to adjust the model  30 . 
   Thus, the invention uses static or steady-state flow initial condition data and measured transient data as are available to create a model  30  for the particular well as indicated at block  72 . Using the model and ongoing measurements collected from the well, the systems and methods of the invention determine accurate and timely estimates of downhole multi-phase fluid rates thereby providing significant advantages in improved multi-phase flow profiling, production monitoring, and injection, work-over and stimulation decisions. 
   The embodiments shown and described above are only exemplary. Even though numerous characteristics and advantages of the present invention have been set forth in the foregoing description together with details of the method and device of the invention, the disclosure is illustrative only and changes may be made within the principles of the invention to the full extent indicated by the broad general meaning of the terms used in the attached claims.