Patent Grant
10851648
The disclosure relates to an apparatus, system and method for suspending and retrieving sensors in a borehole as well as to extract fluid samples from the borehole.
Reference to background art herein is not to be construed as an admission that such art constitutes common general knowledge.
Monitoring of aquifers positioned above, between, below or in close proximity to conventional reservoir formations containing hydrocarbons, such as sandstones and carbonates and unconventional reservoir formations, such as coal seams and shales, is often conducted in accordance with the policies of the operating energy companies, or under state or federal legislation. For instance, in Queensland, Australia, the Petroleum and Gas (Production and Safety) Act 2004 and Petroleum Act 1923 authorizes petroleum tenure holders to undertake activities related to the exploration for, and production of, petroleum and gas. This authorization also includes the right to take or interfere with groundwater. However, in Australia, the Water Act 2000 establishes responsibilities for petroleum tenure holders to monitor and manage the impacts caused by the exercise of these groundwater rights, including a responsibility to remedy any impairment of private bore water supplies.
Traditionally, when water is extracted from a gas well, groundwater levels decline in the area surrounding the well. If multiple gas fields are adjacent to each other, the impact of water extraction on groundwater levels from each well may overlap. In these situations, a cumulative approach may be necessary for the assessment and management of groundwater level impacts.
Conventional coal seam gas production involves pumping large quantities of groundwater from coal formations to reduce the water pressure in the coal seams, releasing the gas that is attached to the coal. For instance, coal seam gas is produced from the Walloon Coal Measures of the Surat Basin and the Bandanna Formation of the Bowen Basin. These coal-bearing formations consist of many thin coal seams separated by low permeability rock. The coal seams collectively comprise a small proportion of the total thickness of the coal bearing formations. The Walloon Coal Measures are a geologic layer of the Great Artesian Basin, which comprises layers of lower permeability rocks alternating with aquifers of high economic importance. The Great Artesian Basin also feeds springs of high ecological and cultural importance.
When water is extracted from coal formations, the water from surrounding aquifers may flow into the coal formations. The degree of interconnection among coal bearing formations and surrounding aquifers in part determines the extent to which water extraction from the coal seams affects water levels in bores in surrounding aquifers. When the water pressure in a coal formation is reduced, such as by removal of water from the coal formation, the coal formation is not dewatered, but remains saturated due to flow from the interconnected aquifer.
A reduction in water pressure in a confined aquifer will manifest as a decline in the water level in a bore that taps the aquifer. Water in the aquifers may be contaminated by ingress of water to the aquifer from coal formations.
Traditionally, the capital expenditure for tubing-deployed aquifer water level monitoring systems may be significant relative to the value of the aquifer and/or the coal formation. In certain traditional embodiments, a workover rig is required to install and retrieve a tubing-deployed aquifer level monitoring system, adding significant operational expenditure.
Conventional fluid sampling may be conducted by first bailing or swabbing out the contents of the monitoring boreholes using a wireline unit or swabbing unit respectively. Water from the surrounding the aquifer enters the bailed or swabbed out borehole. A water sampler on wireline is then lowered into the monitoring borehole to capture a sample of fluid. In an alternative conventional fluid sample technique, low-flow-rate bladder pumping systems are lowered and installed in the monitoring boreholes to extract fluid from the aquifers. Operation of low-flow-rate bladder pumps is traditionally limited to depths above 1000 ft. While submersible rotary or reciprocating pumps can be used in place of low-flow-rate bladder pumps for use at greater depths, submersible rotary or reciprocating pumps may be prohibitively expensive. In addition, all pumps are prone to periodic failure, necessitating retrieval and replacement, for instance, by using workover rigs.
The present disclosure is directed to a suspended fluid sampling and monitoring system. The suspended fluid sampling and monitoring system includes a BOP, the BOP attached to a wellhead. The BOP is positioned above a wellbore. The suspended fluid sampling and monitoring system further includes a TEC, the TEC connected to a sensor package. The TEC and sensor package extend through the BOP into the wellbore. The suspended fluid sampling and monitoring system also includes a fluid sample line, the fluid sample line extending through the BOP into the wellbore. The suspended fluid sampling and monitoring system also includes a fluid sample intake and filtration device, the fluid sample intake and filtration device mechanically coupled to the fluid sample line within the wellbore.
Another embodiment of the present disclosure is directed to a suspended fluid sampling and monitoring system. The suspended fluid monitoring and sampling system includes a BOP, where the BOP is attached to a wellhead, and the BOP is positioned above a wellbore. The suspended fluid sampling and monitoring system also includes a TEC, the TEC connected to a sensor package. The TEC extends through the BOP into the wellbore. The TEC has a free end located outside the wellbore. The suspended fluid sampling and monitoring system further includes a fluid sample line, the fluid sample line extending through the BOP into the wellbore. The fluid sample line has a free end located outside the wellbore. The fluid sample line terminates in a fluid sample intake and filtration device. The suspended fluid sampling and monitoring system includes an HWO, the HWO mechanically connected to the fluid sample line, and a EWO, the EWO mechanically connecting the TEC to a surface electrical cable.
Yet another embodiment of the present disclosure is directed to a method. The method includes providing a fluid sample line, the fluid sample line passing through a first port in a wellbore adapter spool and into a wellbore. The wellbore contains fluid. The wellbore adapter spool is in fluid communication with the wellbore. The method also includes providing a TEC, where the TEC passes through a second port in the wellbore adapter spool and into the wellbore. In addition, the method includes providing a BCM, where the BCM is connected to a blowdown port in the wellbore adapter spool. The method also includes providing a BOM, where the BOM is connected to a bleedoff port in the wellhead adapter spool. The method includes calibrating by blowing down the fluid from an initial fluid height to a fluid height after calibration and allowing the fluid to return to an initial fluid height. The method also includes initially blowing down the fluid from the initial fluid height after the calibration step to a second fluid height after purge using a first gas cap pressure. The method includes allowing fluid to enter the wellbore from an aquifer to reach the initial fluid height and blowing down the fluid from the initial fluid height to a fluid height after recovery using a second gas cap pressure.
The present disclosure may be understood from the following detailed description when read with the accompanying figures. It is emphasized that, in accordance with the standard practice in the industry, various features are not drawn to scale. In fact, the dimensions of the various features may be arbitrarily increased or reduced for clarity of discussion.
FIGS. 7B1-7B3 depict ram components consistent with at least one embodiment of the present disclosure.
A detailed description will now be provided. The following disclosure includes specific embodiments, versions and examples, but the disclosure is not limited to these embodiments, versions or examples, which are included to enable a person having ordinary skill in the art to make and use the disclosure when the information in this application is combined with available information and technology.
Various terms as used herein are shown below. To the extent a term used in a claim is not defined below, it should be given the broadest definition persons in the pertinent art have given that term as reflected in printed publications and issued patents. Further, unless otherwise specified, all compounds described herein may be substituted or unsubstituted and the listing of compounds includes derivatives thereof.
Further, various ranges and/or numerical limitations may be expressly stated below. It should be recognized that unless stated otherwise, it is intended that endpoints are to be interchangeable. Where numerical ranges or limitations are expressly stated, such express ranges or limitations should be understood to include iterative ranges or limitations of like magnitude falling within the expressly stated ranges or limitations (e.g., from about 1 to about 10 includes, 2, 3, 4, etc.; greater than 0.10 includes 0.11, 0.12, 0.13, etc.).
Certain embodiments of the present disclosure are directed to a suspended fluid sampling and monitoring system.
In the embodiment depicted in
Electrical power may be transmitted to sensor package 16 by a surface telemetry unit 3 via a surface electrical cable 4 and TEC 13. Surface electrical cable 4 may be electrically coupled to surface end 13b of TEC 13. As shown in
With further attention to
In the embodiment depicted in
In certain embodiments, TEC 13, fluid sample line 14, and sensor package 16 may be suspended from BOP 11. In other embodiments, fluid sample line 14 is suspended from BOP 11. In yet other embodiments, such as where BOP 11 is omitted, none of TEC 13, fluid sample line 14 or sensor package 16 are suspended from BOP 11. In embodiments where TEC 13 is not used, fluid sample line 14 may be attached to BHA toolstring 17 as described with respect to TEC 13, with fluid 24 entering fluid sample line 14 via fluid entry ports 107 (shown in
Surface electrical cable 4 may be mechanically and electrically connected to TEC 13 through electrical wellhead outlet (EWO) 30, as shown in
In yet another embodiment, shown in
In yet another embodiment, as shown in
In yet another embodiment, shown in
EWO 30 and HWO 50 may be designed to provide well pressure control after BHA toolstring 17 has been deployed on TEC 13 in borehole 1.
In certain embodiments of the present disclosure, suspended fluid sampling and monitoring system 25 may omit one or more of sensor package 16, TEC 13, multi-line clamps 19, TEC reel 5, TEC spooling unit 8, EWO 30 (for example, in embodiments where TEC reel 5 is removed), surface electrical cable 4, and surface telemetry unit 3.
In some embodiments, as shown in
As shown in FIGS. 7B1-7B3, BOP rams 84 may include ram plate 85 and ram rubber 86. Ram plate 85 includes ram plate protrusion 85a. Ram rubber 86 may include ram rubber receiver 85b. Ram rubber receiver 85b may be adapted to receive ram plate protrusion 85a. Ram rubber 86 may be moulded with center conduit 86a to encompass fluid sample line 14 and TEC 13. During deployment of the BHA toolstring 17 on TEC 13 into borehole 1, BOP rams 84 are fully retracted. Once BHA toolstring 17 has reached a target depth in borehole 1, or in the event of a pressure anomaly in borehole 1, such as a pressure anomaly originating from the geological formation 15, BOP screws 83 may be actuated manually (using screw handles not shown) or hydraulically. The consequential rotation of BOP screws 83 causes inward motion of BOP ram plates 85, compressing BOP ram rubbers 86 around the fluid sample line 14 and TEC 13 to create a seal.
In certain embodiments of the present disclosure, installation of suspended fluid sampling and monitoring system 25 may include bleeding off pressure from wellhead 12 through a wing valve (not shown) on the wellhead 12. BOP 11, and in some embodiments wellhead adapter spool 40, is assembled onto wellhead 12. TEC spooling unit 8 and tube spooling unit 9 for TEC reel 5 and hydraulic tube reel 7, respectively, are positioned at surface 2 near borehole 1. TEC 13 and fluid sampling line 14 from TEC reel 5 and hydraulic tube reel 7, respectively, may be fed through sheave 10 suspended above BOP 11.
BHA toolstring 17 may be assembled by sliding fishing neck 101 and clamp housing 102 over TEC 13 before connecting downhole sensor package 103 onto TEC 13. Downhole wire clamp 104 may be mechanically coupled to TEC 13. Clamp housing 102 may be slid over downhole wire clamp 104 and screwed into sliding fishing neck 101. Sensor housing 105 may be slipped over downhole sensor package 103 and screwed into clamp housing 102, before making up bullnose 106 to sensor housing 105.
Fluid sample intake and filtration device split bodies 64 and 65 may be placed around TEC 13 above BHA toolstring 17, with cap screws inserted through split body 64 and screwed into the threaded holes 66 in split body 65. Fluid sampling line 14 may be terminated into fluid intake hydraulic conduit 61 and secured. As BHA toolstring 17 is lowered into borehole 1, multi-line clamps 19 may be installed at intervals, for example, approximately every 30 ft, around both TEC 13 and fluid sampling line 14. Multi-line clamps 19 may act to dissipate some of the weight of the BHA toolstring 17 and TEC 13 into fluid sample line 14.
Once the BHA toolstring 17 has been lowered to a target depth, TEC 13 and fluid sampling line 14 may be inserted into BOP multi-line clamp 20. BOP multi-line clamp 20 may be lowered to rest on a bowl profile machined into the internal face of BOP clamp housing 21 affixed to BOP 11. BOP ram rubbers 86 may be compressed onto TEC 13 and fluid sample line 14, and surface telemetry unit 3 may be connected to TEC reel 5 using surface electrical cable 4.
In another embodiment, installation of suspended fluid sampling and monitoring system 25 may include bleeding off pressure from wellhead 12 through a wing valve (not shown) on the wellhead 12. BOP 11, and in some embodiments wellhead adapter spool 40, is assembled onto wellhead 12. TEC spooling unit 8 and tube spooling unit 9 for TEC reel 5 and hydraulic tube reel 7, respectively, are positioned at surface 2 near borehole 1. TEC 13 and fluid sampling line 14 from TEC reel 5 and hydraulic tube reel 7, respectively, may be fed through sheave 10 suspended above BOP 11.
BHA toolstring 17 may be assembled by sliding fishing neck 101 and clamp housing 102 over TEC 13 before connecting downhole sensor package 103 onto TEC 13. Downhole wire clamp 104 may be mechanically coupled to TEC 13. Clamp housing 102 may be slid over downhole wire clamp 104 and screwed into sliding fishing neck 101. Sensor housing 105 may be slipped over downhole sensor package 103 and screwed into clamp housing 102, before making up bullnose 106 to sensor housing 105.
Fluid sample intake and filtration device split bodies 64 and 65 may be placed around TEC 13 above BHA toolstring 17, with cap screws inserted through split body 64 and screwed into the threaded holes 66 in split body 65. Fluid sampling line 14 may be terminated into fluid intake hydraulic conduit 61 and secured. As BHA toolstring 17 is lowered into borehole 1, multi-line clamps 19 may be installed at intervals, for example, approximately every 30 ft, around both TEC 13 and fluid sampling line 14. Multi-line clamps 19 may act to dissipate some of the weight of the BHA toolstring 17 and TEC 13 into fluid sample line 14.
Once BHA toolstring 17 has been lowered to a target depth, TEC 13 and fluid sampling line 14 may be inserted into BOP multi-line clamp 20. BOP multi-line clamp 20 may be lowered to rest on a bowl profile machined into the internal face of BOP clamp housing 21 affixed to BOP 11. BOP ram rubbers 86 may be compressed onto TEC 13 and fluid sample line 14.
TEC 13 and fluid sample line 14 may be cut at TEC reel 5 and hydraulic tube reel 7, respectively, and routed through the bore of wellhead adapter spool 40, which is assembled on to the top of BOP clamp housing 21. TEC 13 connected to BHA toolstring 17 may be routed through ported bullplug 22 that is assembled onto the top of wellhead adapter spool 40, with TEC 13 terminated inside EWO 30 that is screwed into the threaded port in bullplug 22. Fluid sample line 14 extended through borehole 1 may be terminated into HWO 50 that is screwed into one of the four ports 41 in wellhead adapter spool 40. Surface telemetry unit 3 may be connected to EWO 30 using surface electrical cable 4.
In certain embodiments, such as the embodiments depicted in
In certain embodiments, a water sampling method may be used to extract volume Vs of fluid 24 from an aquifer not initially present, i.e., new water from the aquifer, in borehole 1 from geological formation 15 and displace volume Vs of fluid 24 to surface 2. In certain embodiments, the water sampling method includes:
1. Calibration blowdown step—determine the volume of fluid injected into geological formation 15 per unit volume of borehole fluid displaced through fluid sample line 14;
2. Initial blowdown step—displace additional fluid initially present in borehole 1;
3. Fluid level build-up step—allow fluid from the aquifer to enter borehole 1; during the fluid level build-up period, the fluid level is allowed to rise to its original level through discharge of fluid from geological formation 15 under available pore pressure;
4. Main blowdown step—recover sample of fluid 24 from borehole 1, i.e., fluid newly entering borehole 1 from the aquifer.
In the water sampling method, downhole pressure may be determined, for instance, by surface telemetry unit 3. In certain embodiments, the water sampling method may use blowdown control manifold (BCM) 120. BCM 120, as shown in
In an embodiment of the water sampling method, EWO 30 and HWO 50 are connected to other ports 41 in wellhead adapter spool 40. Bullplug 22 may be fitted to the top of BOP clamp housing 21. In certain embodiments, a pressure gauge may be connected to another port 41 in wellhead adapter spool 40 to monitor wellhead pressure. The pressure gauge may be part of bleed off manifold (BOM) 130 as shown in
Calibration Blowdown Step:
When pressure is applied to borehole 1, only a portion of the displaced volume of fluid 24 will emerge from borehole 1 at surface 2, such as through HWO 50. The remainder of displaced volume of fluid 24 volume will be injected into geological formation 15. In the initial calibration blowdown step, the gas cap pressure needed to displace a volume Vb of borehole fluid is determined.
Without being bound by theory, injecting a gas at pressure P into head space will depress a fluid column height h at speed v equating to volumetric rate Q. Some fluid will be discharged up the sampling tube at rate Q2 with remainder injected into the reservoir at rate Q3. Bernoulli's Solution indicates that to achieve a given Q2:
Q3 will increase with injectivity Index
Q3 will increase with increasing head space height
Q3 increases with increasing tube friction loss (which increases with well depth and decrease in sample tube diameter
Again, without being bound by theory, Bernoulli's Solution may be stated as:
In certain embodiments of the present disclosure, control valve 121 in BCM 120 may be set to a calibration gas cap pressure and sample release valve 53 in HWO 50 may be opened. Isolation valve 122 in BPM 120 may be opened, allowing gas from gas source 123 to enter borehole 1, depressing the fluid column down borehole 1 from hi (initial fluid 24 height) to hc (fluid 24 height after calibration) as shown in
Vr=(Vb−Vt)/Vt Equation 1
The volume Vd1 to be displaced in the subsequent first initial blowdown step is then given by the following equation:
Vd1=Vs(Vr+1)2 Equation 2
The volume Vd2 to be displaced in the main blowdown step following the fluid level build-up period is then given by the following equation:
Vd2=Vs(Vr+1)+Vcl Equation 3
where Vcl is the volume of the fluid sample line.
In certain embodiments, a blowdown volume calculator may be used to determine a gas cap pressure needed to displace a specific volume of fluid from borehole 1 as a function of the current measured downhole pressure displayed in surface telemetry unit 3 and other input data shown in Table 1.
Values for displacement volumes Vd1 and Vd2, the associated changes in fluid height hi and h1 and gas cap pressures P1 (first gas cap pressure) and P2 (second gas cap pressure) needed to induce these changes may be computed by a blowdown volume calculator once Vb and Vt are measured. P1 and P2 may be different or the same. The blowdown volume calculator may also compute the volumes Vw1 and Vw2 recovered at HWO 50 during the initial and main blowdown steps respectively. An example of the computed data output by the blowdown volume calculator is shown in Tables 2A and 2B.
After completion of the calibration blowdown step, in certain embodiments, the pressure of borehole 1 may be allowed to return to the initial borehole pressure and the height of fluid 24 allowed to return to the initial height hi. In other embodiments, after the calibration blowdown step, borehole pressure and height of fluid 24 do not return to the initial borehole pressure and initial height hi.
Initial Blowdown Step:
As shown in
Fluid Level Buildup Step:
As shown in
Main Blowdown Step:
As shown in
Once the desired volume Vs of water has been collected at surface 2, sample release valve 53 in the HWO 50 is then closed and the isolation valve 122 closed at the BCM 120. BOM valve 132 on BOM 130 is opened to bleed off the gas cap pressure in borehole 1. BCM 120 and BOM 130 may be detached from wellhead adapter spool 40, with plugs screwed into the exposed ports 41.
In some embodiments, sample release valve 53 in HWO 50 is adjusted to maintain a backpressure on the fluid emerging from fluid sample line 14 during the main blowdown step to capture pressurized samples. In those embodiments, the pressurized samples may include solubilized gasses.
Depending on the context, all references herein to the “disclosure” may in some cases refer to certain specific embodiments only. In other cases it may refer to subject matter recited in one or more, but not necessarily all, of the claims. While the foregoing is directed to embodiments, versions and examples of the present disclosure, which are included to enable a person of ordinary skill in the art to make and use the disclosures when the information in this patent is combined with available information and technology, the disclosures are not limited to only these particular embodiments, versions and examples. Other and further embodiments, versions and examples of the disclosure may be devised without departing from the basic scope thereof and the scope thereof is determined by the claims that follow.
This application is a National Stage Entry of PCT/US16/34951, filed May 31, 2016; which itself claims priority from U.S. provisional application No. 62/168,981, filed Jun. 1, 2015. The entireties of both PCT/US16/34951 and U.S. 62/168,981 are incorporated herein by reference.
| Filing Document | Filing Date | Country | Kind |
|---|---|---|---|
| PCT/US2016/034951 | 5/31/2016 | WO | 00 |
| Publishing Document | Publishing Date | Country | Kind |
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| WO2016/196425 | 12/8/2016 | WO | A |
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| Number | Date | Country | |
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| 20180163536 A1 | Jun 2018 | US |
| Number | Date | Country | |
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| 62168981 | Jun 2015 | US |
