Method and apparatus for production testing involving first and second permeable formations

When production testing a permeable first formation, fluid flowing out from the first formation is subjected to a pressure measurement and a flow rate control. In order to avoid bringing up the fluid flowing out during the production test to a surface position, where the fluid's inherent explosion and fire risk as well as poisonousness could cause substantial problems, a fluid flow path is arranged for fluid transfer only between the first and second formations. The fluid flow path which, in a suitable apparatus, is constituted by a channel-forming pipe. From this channel, the second permeable formation receives the fluid and keeps it for some time. In the position of use, the apparatus is assigned sealing devices such as annulus packers, which are placed such that fluid flow between the formations is limited to only follow the fluid flow path.

FIELD OF THE INVENTION
 This invention relates to a method and an apparatus for use in production
 testing of a formation expected to be permeable. After having pointed out
 the existence of hydrocarbons upon drilling for oil and gas, a so-called
 production test is carried out, in order to provide information about
 permeable layers outside the bore hole or well itself.
 BACKGROUND OF THE INVENTION
 Prior to a production test, when reservoir fluid is allowed to flow out of
 the formation, the well is provided with some equipment, including means
 to control the flow rate and measuring equipment to measure pressure and
 flow rate.
 A production test has two phases, each with a duration of e.g. 4 hours. In
 both phases, a constant fluid flow is established from the formation.
 In the beginning, it is fluid in the immediate neighbourhood of the well
 that flows into the well but, gradually, fluid from areas spaced at
 constantly larger distances from the well is drained off. The pressure
 within the well decreases due to the fact that the fluid must flow a
 constantly longer distance through the formation and, thus, is subjected
 to a constantly increasing pressure loss. Upon the maintenance of a
 constant flow rate, it is achieved that the course of pressure within the
 well only depends on the character of the formation, which can be
 examined. Therefore, the course of pressure, i.e. interdependent values
 for pressure and time, is recorded during the production test. In the
 second phase of the production test, following immediately after the first
 phase, the fluid low into the well is stopped.
 Then, the pressure within the well will gradually increase to formation
 pressure as the formation around the well is refilled by means of the
 fluid flow into the well from remote areas. Also in this second phase,
 values for pressure and time are recorded.
 Recorded pressure--time values in the two phases of the production test
 represent an important basis for subsequent analyses, appraisals and
 planning of further drilling activity and, possibly, development of an oil
 field. The question may well arise as to record other parameters, e.g.
 temperature, in addition to pressure and it is, of course, important to
 carry out chemical analyses of samples from the reservoir fluid.
 Sealing means, e.g. in the form of annulus packers, are also adapted to
 take care of security requirements.
 As explained below, the present invention is directed to a method and an
 apparatus for maintaining a constant flow of reservoir fluid in the well
 while pressure and, possibly, other parameters are read off.
 By a production test it is known to conduct fluid from the reservoir to the
 surface through a so-called tubing, which is installed in the well.
 Sealing means are disposed within the annulus between the production
 tubing and the well wall, preferably on a place where a well casing has
 been installed, so that reservoir fluid is conducted to the surface
 through the tubing and not through the annulus. At the upper end thereof,
 the tubing is assigned a valve adapted to control the fluid flow, and
 sensors and measuring equipment are disposed, at least for allowing the
 reading off and recording time, flow rate in the tubing and pressure
 within the well.
 It is known to install a downhole pump in order to achieve and maintain
 sufficient flow rate to carry out a production test if the pressure within
 the reservoir or the properties of the formation or reservoir fluid are
 such that this is required.
 Even if the described technique is well developed and has been is known for
 many years, it still suffers from a plurality of disadvantages and
 deficiencies.
 Reservoir fluid constitutes, when it reaches the surface, a safety risk due
 to danger of explosion, fire hazard and toxicity. Therefore, substantial
 security measures must be made in connection with a production test.
 Additionally, reservoir fluid constitutes an environmental problem because
 production tests naturally are carried out before one takes the costs of
 installing process equipment. Therefore, it has been customary to conduct
 reservoir fluid to a burner. Due to the fact that combustion causes
 unwanted release of environmental gases and release of uncontrolled
 amounts of hydrocarbons into the sea, there exist some places, such as on
 the Norwegian continental shelf, where, owing to restrictions on burning
 and limitation in periods during a year for testing, it has become
 interesting to collect produced reservoir fluid and convey it to a
 suitable process plant. Even if this is an environmentally satisfactory
 solution, it is, nevertheless, awkward, price-raising as well as
 exhibitting many restrictions both in time and with respect to weather
 conditions.
 The preparations taking place before production testing comprise typically
 setting and cementing of casings for insulating various permeable layers,
 and to take care of safety requirements. Additionally, special production
 tubing is used down to the layer/bed to be tested. These preparations are
 time-consuming and expensive. Safety considerations make it some times
 necessary to strengthen an already set well casing, perhaps over the
 entire or a substantial part of the length of is the well; particularly in
 high pressure wells it might be required to install extra casings in the
 upper parts of the well.
 It can be difficult to secure a good cementing, and it may arise channels,
 cracks or lack of cement. In many cases, it is difficult to define or
 measure the quality of the cement or the presence of cement.
 Unsatisfactory cementing causes great possibility for the occurrence of
 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.
 Today's system can take care of drilling of wells in deep waters, but does
 not provide a safe and secure production testing. In deep water, it is
 difficult to take care of security in case 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 subsequently to the
 closing of the production valve at the seabed. Today's system is defective
 with respect to reacting on and pointing out dangerous situations.
 Further, in ordinary production it is usual to use various forms of well
 stimulation. Such stimulation may consist in the addition of chemicals
 into the formation in order to increase the flow rate. A simple well
 stimulation consists in subjecting the formation to pressure pulses so
 that it cracks and, thus, becomes more permeable, so-called "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 relations 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.
 In some cases, it would be useful to be able to carry out a reversed
 production test, pumping produced fluid back into the formation again.
 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 security 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 technique. 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 reveal a possible connection in
 the rock ground between formations connected by the channel, and may in
 some cases also contribute to define the distance from the well to such a
 possible connection between the formations.
 SUMMARY OF THE INVENTION
 The object of the invention is to provide a method and an apparatus for
 production testing a well where the described disadvantages of prior art
 technique have been avoided.
 The object is achieved by means of features as defined in the following
 description and claims.
 A main feature of the invention consists in that 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 means are disposed to limit the fluid
 flow to take place only between the formations through the channel
 connection(s). When fluid flow takes place from first to second formation
 in an upward direction (the fluid flow may occur in the opposite
 direction, the formation being production tested then lying above said
 second, permeable formation accommodating the fluid flow), the sealing
 means, e.g. annulus packers, prevent fluid from flowing between the
 formations, outside the channel(s)
 Within the channel, flow controlling means are disposed, inclusive a valve
 and, possibly, 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 sensor for flow rate in the channel is disposed.
 This sensor may, possibly, be readable from an surface position.
 Additionally, sensors adapted to read 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 desired
 parameters at several places within the channel. As previously known,
 sensors for pressure and temperature are disposed within the well and,
 moreover, known equipment for timekeeping and recording of measuring
 values are used.
 Upon a production test, by means of the flow rate sensor, the adjustable
 valve and, possibly, by means of said pump, a constant fluid flow is
 established and maintained in the channel, fluid flowing from one
 formation to the other formation. pressure and, possibly, other well
 parameters are read and recorded as previously known. Thereafter, the
 fluid flow is closed, and a pressure built up within the well is monitored
 and recorded as known. By means of the invention, a production test might
 be extended to comprise a reversed flow through the utilisation of a
 reversible pump, so that fluid can be pumped in the opposite direction
 between the two formations.
 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 as known per se. To this end, the well is
 supplied with pressurised liquid, e.g. through a drill string coupled to
 the channel. Thereafter, a production test is carried out, such as
 explained. Additionally, a reversed production test may alternately give
 both injection and production date from two separated layers without
 having to pull the test string.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS
 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 by
 means of casings (2 in FIG. 1).
 First formation 4 is insulated from possible permeable formations adjacent
 the bottom of the well by means of 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 wall defining the open hole 3 and between the
 channel 8 and the casing 2.
 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.
 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.
 In accordance with FIG. 1a, there is no need here for the perforations 5 in
 FIGS. 1 and 2. The annulus packers 11 and 12 will then act against the
 wall defining the bore hole. 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.
 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 (see FIG. 1b as well) which,
 together with the through-going lateral gates 13, establish fluid
 communication between the formations 4, 6.
 In the channel 8, a remotely operable valve 14 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' of the sleeve 14 being brought to register
 more or less with the gates 13 or not to register therewith.
 Further, in the channel 8, remotely readable sensors are disposed,
 inclusive a pressure sensor 15 and a flow sensor 16 and a temperature
 sensor 17. As shown in FIG. 2, the channel 8 may be assigned a pump 18
 adapted to drive a flow of fluid through the channel 8.
 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.
 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.