Abstract:
The present invention provides systems and methods for performing production testing in open holes and in cased holes that avoid transporting formation fluid to the surface. The invention essentially comprises a test string for testing a production zone intersecting a wellbore. The string further comprises a fluid communication member allowing flow of fluid therethrough, a sealing device for isolating a production zone intersecting said wellbore to allow fluid flow from said production zone into said fluid communication member, a second sealing device spaced apart from said first sealing device for isolating a second injection zone intersecting said wellbore, a pump for pumping fluid between zones, and flow control devices.

Description:
CROSS REFERENCE TO RELATED APPLICATION  
       [0001]    This application claims priority from U.S. Provisional Patent Application No. 60/174,777, filed on Jan. 6, 2000. 
     
    
     
       BACKGROUND OF THE INVENTION  
         [0002]    1. Field of the Invention  
           [0003]    This invention relates generally to oilfield well testing and more particularly to production testing of wells wherein fluid from a production zone is injected into a another subsurface zone.  
           [0004]    2. Description of the Related Art  
           [0005]    After drilling of a well to a known depth, a production zone or zones are identified by a variety of known techniques. “Production test” or “production testing” is carried out to obtain data to determine a variety of characteristics of the oil and gas reservoirs, including the flow characteristics of the reservoir fluid, such as permeability.  
           [0006]    A variety of production testing methods are known. Production tests are performed prior to completing a well (in open holes) as well as in cased or completed wells. Usually, a production test has two phases, each with a duration of several hours to a few days. In the beginning, the fluid adjacent the production zone flows into the well, but gradually the fluid from greater distances must flow into the well. The pressure in the well decreases because the fluid must flow over a longer distance through the formation, subjecting it to increasing pressure loss. When a constant flow rate from a particular zone is maintained, then the pressure in the well depends only on the character of the formation. During the first phase of a production test, pressure and temperature measurements over time are recorded, during constant flow rate. In the second phase of the production test, the fluid flow from the production zone being tested is stopped. The pressure within the well then gradually rises to the formation pressure as the formation around the well is filled with the fluid from the remote areas. The pressure build up over time and temperature over time are recorded. The pressure over time, temperature over time and the flow rate measurements are most commonly used to analyze the reservoir characteristics.  
           [0007]    During the first phase of the production testing, the reservoir fluid is conducted to the surface via a tubing. Packers in the annulus between the tubing and the well are placed to seal the annulus so the formation fluid will flow through the tubing and not through the annulus. A flow control valve at the upper end of the tubing at the surface is used to control the flow of the fluid from the formation. Downhole pumps are sometimes installed to maintain the desired fluid flow rate. The above-described and other known production testing methods usually require flowing substantial amounts of formation fluid to the surface during the first phase of the production test. Such methods suffer from a number of disadvantages.  
           [0008]    In open hole wells, there usually are no or very inadequate facilities at the surface to process the formation fluid brought to the surface. The reservoir fluid poses safety risks as it is flammable and hazardous to the environment. Therefore, substantial safety measures are taken in connection with such production tests. To reduce the environmental risks, the reservoir fluid is usually burned off at the well site. Combustion of hydrocarbons, however, produces unwanted gases which pollute the environment. Hydrocarbons also are often discharged into the environment. These problems are exasperated for offshore wells. In certain regions, such as the Norwegian Continental shelf, regulations restrict or prohibit burning of polluting matters. The operators in such regions collect the produced reservoir fluid and transport it to suitable offsite processing plants. Accordingly, it is increasingly becoming important to devise production testing methods which are safe, environmentally friendly and less weather dependent.  
           [0009]    Before conducting production testing, casing is often cemented in the well to insulate various permeable layers, and to comply with safety requirements. Usually, special production tubing is used down to the layer/bed (zone) to be tested. These preparations are time-consuming and expensive. Safety considerations make it sometimes necessary to strengthen an already set casing, perhaps over the entire or a substantial part of the length of the well; particularly in high pressure wells where it might be required to install extra casings in the upper parts of the well.  
           [0010]    It can be difficult to secure a good cementing. Channels, cracks or voids my exist in the cemented zones. In many cases, it is difficult to define or measure the quality of the cementing operation or the presence of cement. Unsatisfactory cementing can cause so-called cross flows to or from other permeable formations outside the casing. Cross flows may, to a high degree, influence the measurements carried out. Time-consuming and very expensive cementing repairs might be required in order to eliminate such sources of errors.  
           [0011]    Systems currently used can be adequate for take care of drilling wells in deep waters, but do not provide safe and secure production testing. In deep water operations, it is difficult to remain secure when the drilling vessel drifts out of position, or whenever the riser is subjected to large, uncontrollable and not measurable vibrations or leeway. Such a situation requires a rapid disconnection of the riser or production tubing subsequent to closing the production valve at the seabed.  
           [0012]    Further, in ordinary production it is usual to use various forms of well stimulation. Such stimulation may include injection of chemicals into the formation in order to increase the flow rate. A simple well stimulation includes subjecting the formation to pressure pulses so that it cracks and, thus, becomes more permeable. Such methods are referred to as “fracturing” of the formation. A side-effect of fracturing can be a large increase in the amount of sand accompanying the reservoir fluid. In connection with production testing, it may in some instances be of interest to be able to effect a well stimulation in order to observe the effect thereof. Again, the case is such that an ordinary production equipment is adapted to avoid, withstand, resist and separate out sand, while corresponding measures are of less importance when carrying out a production test.  
           [0013]    In some cases, it is useful to be able to carry out a reversed production test, i.e., pumping produced fluid back into the production formation. However, this presupposes that produced fluid can be kept at approximate reservoir pressure and temperature. This will require extra equipment, and it will be necessary to use additional safety measures. Further, it would require transfer of the production tubing. Probably, the production tubing would have to be pulled up and set once more, in order to give access to another formation. This is time-consuming as well as expensive. Therefore, it is not of actual interest to use such reversed production tests in connection with prior art techniques. During a reversed production test, a pressure increase is observed in the well while a reversed constant fluid flow is maintained. When the reversed fluid flow is interrupted, a gradual pressure reduction will be observed in the well. Reversed production test may contribute to revealing a possible connection in the rock ground between formations connected by the channel, and may in some cases also contribute to defining the distance from the well to such a possible connection between the formations.  
           [0014]    The present invention provides systems and methods for performing production testing in open holes and in cased holes that avoid transporting formation fluid to the surface.  
         SUMMARY OF THE INVENTION  
         [0015]    A main feature of the invention is that formation fluid is conducted from a first, expected permeable formation to a second permeable formation as opposed to prior art technique where fluid is conducted between a formation and the surface. According to the invention, prior to a production test, at least one channel connection is established between two formations, of which one (a first) formation is the one to be production tested. Further, sealing devices are disposed to limit the fluid flow between the formations through the channel connection(s). When fluid flow takes place from the first to the second formation the sealing devices, e.g. annulus packers, prevent fluid from flowing between the formations, outside the channel(s).  
           [0016]    Within the channel, flow controlling devices are disposed, which may include flow control valves and a pump, operable from the surface in order to control the fluid flow in the channel and, thus, between the formations. Further, within the channel, a flow rate sensor is disposed. This sensor may be readable from a surface location.  
           [0017]    Additionally, sensors adapted to determine pressure, temperature, detect sand, water and the like from the surface may be disposed. Of course, several sensors of each type may be disposed in order to monitor the desired parameters at several places within the channel. As discussed, sensors for pressure and temperature are disposed within the well. Likewise, equipment for timekeeping and recording of the measured valves are positioned in the well.  
           [0018]    During a production test, by using the flow rate sensor, the adjustable valve and, possibly, by use of said pump, a constant fluid flow is established and maintained in the channel, for fluid flowing from one formation to the other formation. Pressure and other well parameters are read and recorded as stated above. Thereafter, the fluid flow is ceased, and the pressure build up within the well is monitored and recorded as stated. This production test may be extended to a reversed flow through the utilization of a reversible pump so that fluid can be pumped in the opposite direction between the two formations.  
           [0019]    Storing produced reservoir fluid in a formation results in the advantage that the fluid may have approximately reservoir conditions when it is conducted back into the reservoir. Further, according to the invention, well stimulating measures in the formation being production tested may be used. Fracturing may be achieved by methods known in the art. To this end, the well is supplied with pressurized liquid, e.g., through a drill string coupled to the channel. Thereafter, a production test is carried out as described above. Additionally, a reversed production test may be conducted to obtain the production testing data from two separated layers without having to remove the test string.  
           [0020]    Examples of the more important features of the invention thus have been summarized rather broadly in order that the detailed description thereof that follows may be better understood, and in order that the contributions to the art may be appreciated. There are, of course, additional features of the invention that will be described hereinafter and which will form the subject of the claims appended hereto. 
       
    
    
     BRIEF DESCRIPTION OF THE DRAWINGS  
       [0021]    For detailed understanding of the present invention, references should be made to the following detailed description of the preferred embodiment, taken in conjunction with the accompanying drawings, in which like elements have been given like numerals and wherein:  
         [0022]    [0022]FIG. 1 shows, diagrammatically and in a side elevational view, a part of a sketch of a well where a channel has been disposed which connects two permeable formations.  
         [0023]    [0023]FIG. 1A corresponds to FIG. 1, but here is shown a minor modification of the channel-forming pipe establishing the fluid flow path between the two formations, the borehole through said second formation not being lined.  
         [0024]    [0024]FIG. 2 shows a part of a well having a channel, corresponding to FIG. 1, and where a pump has been disposed.  
         [0025]    [0025]FIG. 3 shows a schematic elevational view of a cased well that has been prepared for production testing wherein formation fluid from a production zone is injected into an injection zone below the production zone.  
         [0026]    [0026]FIG. 4 shows a schematic elevational view of a cased well that has been prepared for production testing wherein formation fluid from a production zone is injected into a formation above the production zone.  
         [0027]    [0027]FIG. 5 shows a schematic elevation view of an open hole that has been prepared for production testing according to one method of the present invention.  
         [0028]    [0028]FIG. 6 (FIGS. 6A and 6B) shows a schematic elevation view of a wellbore with multiple production zones that has been prepared for production testing of one or more zones according to one method of the present invention. 
     
    
     DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS  
       [0029]    In FIG. 1, reference numeral  1  denotes a part of a vertical well lined with a casing  2 . The well  1  is extended with an open (not lined) hole  3  drilled through a first, expected permeable formation  4  to be production tested. The casing  2  is provided with a perforation  5  in an area where the well  1  passes through a second, permeable formation  6 . According to FIG. 1A, second permeable formation  6  is not insulated or isolated by the casings  2 . One or both permeable formations  4  and  6  may be stimulated using chemicals or may be fractured using a fracture mechanism (not separately shown) to increase flow in the formations  4  and  6 . A well known device and method of fracturing a formation is a pump used to initiate pressure pulses for causing cracks to form in the formation.  
         [0030]    First formation  4  is insulated from possible permeable formations adjacent the bottom of the well by a bottom packer  7 . A tubular channel  8  extends concentrically with the well  1  from the area at first formation  4  to a place above the perforations  5 . Thus, an annulus  9  is formed between the channel  8  and the casing  2 .  
         [0031]    A lower annular packer  10  placed further from the bottom of the well  1  than first permeable formation  4 , defines the lower end of the annulus  9 . An upper annular packer  11  placed further from the bottom of the well  1  than the perforations  5 , defines the upper end of the annulus  9 . An intermediate annular packer  12  placed closer to the bottom of the well  1  than the perforations  5 , prevents communication between the perforations  5  and possible other permeable formations above the lower packer  10 .  
         [0032]    The channel  8  is closed at the upper end and, according to FIGS. 1 and 2, open at the lower end. In an area distanced from the upper end of the channel  8 , below the place where the upper packer  11  is mounted, the channel  8  is provided with gates  13  establishing a fluid communication between the channel  8  and the annulus  9  outside the channel. Thus, fluid may flow from the first formation  4  to the well  1  and into the channel  8  at the lower end thereof, through the channel  8  and out through the gates  13  and further, through the perforations  5 , to second formation  6 .  
         [0033]    In accordance with FIG. 1A, there is no need here for the perforations  5  as in FIGS. 1 and 2. The annulus packers  11  and  12  will then act against the wall defining the borehole. The packer  7  can also be a part of the channel-forming pipe  8  when the pipe wall is perforated  21  between the packer  7  and the packer  10 .  
         [0034]    When the annulus packer  7  is mounted to the channel-forming pipe  8 , the latter may be closed at the lower end thereof which, according to FIG. 1A, is positioned below the first, expected permeable formation layer  4 . In an area above the annulus packer  7 , the channel-forming pipe  8  is, thus, provided with through-going lateral gates  21  which, together with the through-going lateral gates  13 , establish fluid communication between the formations  4  and  6 .  
         [0035]    Referring to FIG. 1, in the channel  8 , a remotely operable valve (not shown) is disposed, said valve being adapted to control a fluid flow through the channel  8 . The valve may, as known per se, comprise a remotely operated displaceable, perforated sleeve  14  adapted to cover the gates  13 , wholly or in part, the radially directed holes  14   a  of the sleeve  14  being brought to register more or less with the gates  13  or not to register therewith.  
         [0036]    Further in FIG. 2, in the channel  8 , remotely readable sensors are disposed, inclusive a pressure sensor  15 , and a flow sensor  16  and a temperature sensor  17 . The channel  8  may be assigned a pump  18  adapted to drive a flow of fluid through the channel  8 .  
         [0037]    The pump can be driven by a motor  19  placed in the extension of the channel  8 . As known, a drive shaft  20  between motor  19  and pump  18  is passed pressure-tight through the upper closed end of the channel  8 . Advantageously, the motor  19  may be of a hydraulic type, adapted to be driven by a liquid, e.g. a drilling fluid which, as known, is supplied through a drill string or a coilable tubing, not shown. Also, an electrical motor can be used which can be cooled through the circulation of drilling liquid or through conducting fluid flowing in the channel  8 , through a cooling jacket of the motor  19 .  
         [0038]    In the annulus  9 , sensors may be disposed, in order to sense and point out communication or cross flowing to or from the permeable layers, above or below the annulus.  
         [0039]    [0039]FIG. 3 shows schematic elevation view of a cased well  101  that has been prepared for production testing according to one embodiment of the present invention. The well has been lined with a casing  103  that has perforations  105  adjacent a production zone or formation  106  to be tested and perforations  107  adjacent a permeable injection zone or formation  108 . The test string  110  generally includes a bottom hole assembly  100  conveyed in the well  101  with a drill pipe  112 . The bottom hole assembly  100  has a tubular member  115  that carries the various test devices. The test string  110  includes a lower packer or seal  120   a  and an upper packer  120   b  that respectively seal the annulus  123  between the tubing  115  (also referred to herein as the tubular channel or the channel) and the casing  103 . This ensures flow of formation fluid  109  only into the tubing  115 . Similarly, packers  122   a  and  122   b  seal the annulus  125  between the tubing  115  and the casing  103  below and above the perforations  107  ensuring that the fluid from the tubing  115  will only be pumped or injected into the formation  108 .  
         [0040]    The string  110  includes a motor  130  that drives a pump  132  disposed at a suitable location in the tubing  115 . A drive shaft  131  coupled to the motor  130  passes through the packer or seal  120   b  and drives the pump  132 . Seals  133  around the shaft  131  inhibit fluid communication through the packer  120   b . The motor  130  preferably is a mud motor which is driven when drilling fluid or mud  135  supplied to the drill pipe  112  under pressure from the surface. The mud  135  drives the motor  130  and re-circulates or returns to the surface via the annulus  138  when a motor exit valve  137  is opened. The motor  130  may also be an electric motor or any other type of suitable motor. The motor may be a reversible type so that fluid may be pumped in either the uphole or downhole direction. A stabilizer/centralizer  139  may be provided above the motor  130  to provide lateral or radial stabilization to the string  110 .  
         [0041]    The test string  110  further includes a shut-in valve  140  which controls the flow of the fluid from formation  106  to the tubing  115 . An injection valve  142  controls the fluid flow from the tubing  115  to the injection zone  108 . A circulation valve  144  at the bottom of the tubing  115  may be provided to control fluid flow from the tubing  115  to the wellbore section below the string  110 . A float valve  146  may be provided inside the rotor to prevent the back flow of the produced fluid  109 . A bypass valve  145  is provided in the packer  120   b . During tripping of the string  110  into the well  101 , the bypass valve  145  is opened, which allows the mud  135  to return to the surface via the annulus between the tubing  115  and the casing  103  thereby cleaning the wellbore.  
         [0042]    The string  110  includes a variety of sensors. Pressure sensors P 1 , P 2  and P 3  respectively provide pressures in the tubing  115  adjacent the production zone  106 , in the intermediate zone  110  and the injection zone  108 . Temperature sensors T 1 , T 2  and T 3  provide temperatures corresponding to the pressures P 1 , P 2  and P 3 . Flow measurement devices (flow meters) such as “V” provides fluid flow rate through the tubing  115 . Other flow meters may be used to measure flow rates and to detect leaks.  
         [0043]    A fluid sampler  150  (also referred to in the art as fluid collection chamber or system) may be provided on the high pressure side (i.e. past the pump  132 ) to collect fluid samples. A variety of fluid samplers are known. Any suitable sampling or collection chamber device may be utilized for the purpose of this invention. In addition to the conventional pressure, temperature and flow rate measurements, the string  110  preferably includes a number of other sensors for determining reservoir characteristics. Such sensors include sensors for determining viscosity, density, bubble point, composition and other chemical characteristics of the formation fluid. The sensors are generally denoted by “RCI” in FIG. 3. For motion evaluation, sensors such as resistivity sensors, acoustic and gamma ray sensors are disposed to provide parameters of interest of the formation. Such sensors may be conveniently placed above the motor  139 . Such sensors are designated a measurement-while-drilling or “MWD” sensors and are denoted by numeral  152 . A retrievable downhole memory unit  154  is preferably utilized to store the production testing data, which is downloaded at the surface for further analysis. The memory unit  154  can be retrieved by a wireline or coiled tubing if the string  110  gets stuck in the well.  
         [0044]    To conduct the production test, the string  110  is conveyed into the wellbore. The packers  120   a  and  120   b ,  122   a  and  122   b  are set at the preferred locations. The precise location of the zones may be determined from the MWD sensors  154 . The drilling fluid  135  is supplied under pressure, which rotates the motor that drives the pump  132 . The mud  135  returns or re-circulates to the surface via the motor exit valve  139 . The shut-in-valve  140  and the injection valves  142  are controllably opened to control the flow of the formation fluid from the production zone  106  to the injection zone  108 . The pressure, temperature and flow measurements are continuously or periodically recorded into the memory  154 . Electronic circuitry  153  preferably including microprocessor-based unit in the string  110  determines the values of various desired parameters from the downhole measurements. These measured values and data may be transmitted to a surface controller or processor which may be a computer system. The downhole processor and/or the surface control unit are programmed to control the various flow control devices, and may be programmed to control the fluid flow rate from the production zone  106  to the injection zone  108 .  
         [0045]    Once the first phase of the production test has been completed, the shut-in-valve and the injection valve are turned off, and the fluid communication between the production and injection zone stopped. The pressure in the zone  123  starts to rise. The pressure over time and temperature over time measurements are recorded until the pressure P 1  builds up to the formation pressure or for a selected time period.  
         [0046]    As noted above, the production testing measurements may be recorded in downhole memory  154  and/or transmitted to a surface controller. The valves  137 ,  140 ,  142 ,  145 , and  146  and other such devices are remotely controllable. The system can control the flow of fluid from the production zone  108  to the injection zone at any desired flow rate. The system is a closed loop system, wherein the operating parameters may be altered downhole, from the surface, or any other remote location.  
         [0047]    Simultaneous to the pressure and temperature measurements of the production zone, pressure and temperature measurements for the injection zone also may be recorded, which provides data for characterizing the injection zone during a single trip. During the production testing phase, the fluid samples may be analyzed downhole by the reservoir characterization instruments (“RCI”). Fluid samples are collected by the sampler  150  and are analyzed upon retrieval of the string  110  to the surface.  
         [0048]    [0048]FIG. 4 is an example of the implementation of production testing in a cased well wherein the production zone  206  is below or downhole of the injection zone  208 . The operation of the various valves is the same as described above. The sampler  250  is disposed above the pump  232  since that is the high pressure side. In this configuration, the packers  220   a  and  220   b  isolate the production zone  206  while the packers  222   a  and  222   b  isolate the injection zone  208 . For convenience the remaining elements are identified by the same numerals as shown in FIG. 3.  
         [0049]    [0049]FIG. 5 shows an example of implementation of the production testing method of the present invention in an open hole  301 . The system  300  is substantially identical to the system described in reference to FIG. 4, except that suitable open hole packers and stabilizers are utilized. In FIG. 5, the open hole packers  320   a  and  320   b  isolate the production zone while packers  322   a  and  322   b  isolate the injection zone. Formation evaluation measurements made by the MWD sensors  156  may be utilized to precisely position the string  300  in the wellbore.  
         [0050]    The above-described systems may be utilized when an upper portion of a well is cased with a lower open hole. Appropriate sealing devices, such as packers are utilized depending whether the well section is cased or not.  
         [0051]    [0051]FIG. 6, which comprises FIGS.  6 A and FIG. 6B, shows an implementation of the present method for testing multiple zones. FIG. 6 shows three production zones  406 ,  408  and  410  and one injection zone  412 . Each of the production zones is isolated. For example, packers  420   a  and  420   b  isolate zone  406 , packers  422   a  and  422   b  isolate zone  408  and packers  424   a  and  424   b  isolate zone  410 . Each production zone has a corresponding shut-in-valve. Valves  416 ,  418  and  420  respectively control the flow from the production zones  406 ,  408  and  410  into the tubing  415 . A common motor  430  and pump  432  may be utilized to pump the fluid from any of the producing zones into the injection zone  412 .  
         [0052]    To test a particular zone, for example  406 , the shut-in-valves  418  and  420  are closed, while the valve  416  is opened. This only allows fluid from formation  406  to enter the tubing  415 . This fluid is then pumped by the pump into the injection zone  412 . The production testing is completed with respect to the zone  406  in the manner described above in reference to FIG. 5. To test the production zone  408 , the zones  406  and  410  are shut off. The system of FIG. 6 also allows for testing zones sequentially or simultaneously. For example, any two of the three zones or all of the three zones may be tested simultaneously. The flow rate of each zone is independently controlled by the surface and/or downhole controller.  
         [0053]    In the above-described systems, additional downhole instruments and sensors may easily be deployed. For example, one or more types of known fluid analysis devices may be disposed prior to the sample collection chamber (sampler) or they may be positioned at any other suitable location. Such sensors may include acoustic sensors, near infrared sensors, density measurement devices, chemical analysis devices etc. The system is adapted to control operations downhole and/or from the surface. The system provides the production testing measurements, fluid sampling and in-situ fluid analysis. Reservoir characterization instrumentation is disposed downhole to provide substantially real-time information.  
         [0054]    The foregoing description is directed to particular embodiments of the present invention for the purpose of illustration and explanation. It will be apparent, however, to one skilled in the art that many modifications and changes to the embodiment set forth above are possible without departing from the scope and the spirit of the invention. It is intended that the following claims be interpreted to embrace all such modifications and changes.