WO2011005836A2 - Methods for treating a wellbore - Google Patents
Methods for treating a wellbore Download PDFInfo
- Publication number
- WO2011005836A2 WO2011005836A2 PCT/US2010/041176 US2010041176W WO2011005836A2 WO 2011005836 A2 WO2011005836 A2 WO 2011005836A2 US 2010041176 W US2010041176 W US 2010041176W WO 2011005836 A2 WO2011005836 A2 WO 2011005836A2
- Authority
- WO
- WIPO (PCT)
- Prior art keywords
- water
- fluid
- well
- based gel
- production zone
- Prior art date
Links
Classifications
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B33/00—Sealing or packing boreholes or wells
- E21B33/10—Sealing or packing boreholes or wells in the borehole
- E21B33/13—Methods or devices for cementing, for plugging holes, crevices, or the like
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/14—Obtaining from a multiple-zone well
Definitions
- Embodiments disclosed herein relate generally to improved methods for treating a wellbore.
- Hydrocarbons e.g., oil and natural gas
- Hydrocarbons are typically produced by drilling and casing a single, main wellbore downward from the surface into a lower, primary production subterranean geologic formation (i.e., a "reservoir") or zone within the formation.
- a primary production subterranean geologic formation i.e., a "reservoir” or zone within the formation.
- hydrocarbons In order for hydrocarbons to be "produced,” that is, travel from the formation to the wellbore (and ultimately to the surface), there must be a sufficiently unimpeded flow path from the formation into the wellbore.
- One key parameter that influences the rate of production is the permeability of the formation along the flow path by which the hydrocarbon travels to reach the wellbore. Sometimes, the formation rock has a naturally low permeability; other times, the permeability is reduced, for example, during drilling of the wellbore.
- Drilling fluids or "muds" are typically classified according to their base material, i.e., the drilling mud may be either a water-based mud having solid particles suspended therein or an oil-based mud with water or brine emulsified in the oil to form a discontinuous phase and solid particles suspended in the oil continuous phase.
- drilling fluids typically further include weighting agents (most frequently barium sulfate or barite is used), bentonite clay to help remove cuttings from the well and to form a filter cake on the walls of the hole, thinners (e.g., lignosulfonates, polyphosphates and tinnins) to reduce flow resistance and gel development, and various additives that serve specific functions, such as polymers, corrosion inhibitors, emulsifiers, and lubricants.
- weighting agents most frequently barium sulfate or barite is used
- bentonite clay to help remove cuttings from the well and to form a filter cake on the walls of the hole
- thinners e.g., lignosulfonates, polyphosphates and tinnins
- additives that serve specific functions, such as polymers, corrosion inhibitors, emulsifiers, and lubricants.
- the effectiveness of a drilling fluid, and also of the additives found in the drilling fluid is typically evaluated by measuring
- the mud is pumped downhole through a bore of the drillstring to the drill bit where it exits through various nozzles and ports. After exiting through the nozzles, the "spent" fluid returns to the surface through an annulus formed between the drillstring and the drilled wellbore. At the surface, the mud can be separated from the drill cuttings for reuse, and the drill cuttings can be disposed of in an environmentally accepted manner.
- wellbore fluids are circulated downhole to remove rock as well as deliver agents to combat the variety of issues described above.
- the fluid For a wellbore fluid to perform all of its functions and allow wellbore operations to continue, the fluid must stay in the borehole.
- undesirable formation conditions are encountered in which substantial amounts or, in some cases, practically all of the wellbore fluid may be lost to the formation.
- wellbore fluid can leave the borehole through large or small fissures or fractures in the formation or through a highly porous rock matrix surrounding the borehole.
- fluid loss or lost circulation is a recurring drilling problem, characterized by loss of wellbore fluids into downhole formations that are fractured, highly permeable, porous, cavernous, or vugular.
- Induced fluid losses may also occur when the fluid weight, required for well control and to maintain a stable wellbore, exceeds the fracture resistance of the formations.
- a particularly challenging situation arises in depleted reservoirs, in which the drop in pore pressure weakens hydrocarbon-bearing rocks, but neighboring or inter-bedded low permeability rocks, such as shales, maintain their pore pressure. This can make the drilling of certain depleted zones impossible because the fluid weight required to support the shale exceeds the fracture resistance of the sands and silts.
- Filter cakes are formed when particles suspended in a drilling fluid coat and plug the pores in the subterranean formation such that the filter cake prevents or reduces both the loss of fluids into the formation and the influx of fluids present in the formation.
- a number of ways of forming filter cakes are known in the art, including the use of bridging particles, cuttings created by the drilling process, polymeric additives, and precipitates.
- Fluid loss pills may also be used where a viscous pill comprising a polymer may be used to reduce the rate of loss of a wellbore fluid to the formation through its viscosity.
- a fluid loss pill of polymers may be "spotted" into the wellbore to reduce or prevent such fluid loss by injection of other completion fluids behind the fluid loss pill to a position within the wellbore which is immediately above a portion of the formation where fluid loss is suspected. Injection of fluids into the wellbore is then stopped, and fluid loss will then move the pill toward the fluid loss location. Additionally, upon completion of drilling, the filter cake and/or fluid loss pill may stabilize the wellbore during subsequent completion operations, which typically include casing and cementing the well as well as installing any necessary production equipment.
- fluids can be produced from the various subsurface formations. Fluids may be recovered either through a single production zone or a plurality of production zones. There are several known methods for producing from a plurality of production zones, the simplest involving simultaneous production from all zones.
- production tubing is installed in a well that has been cased and cemented such that the production tubing and casing are perforated in the regions of the producing zones to allow hydrocarbons from each zone to simultaneously flow into the production tubing.
- cross-flow may occur, resulting in no production from one of the zones.
- cross-flow is used herein to refer to the situation where fluids from one zone (e.g., a high pressure zone) flow into a different zone (e.g., a low pressure zone) rather than into production tubing and out of the well. Due to the low productivity which may result from such cross-flow, it is usually impractical from a commercial standpoint to merely perforate the production tubing and casing adjacent these formations and commingle the production from the plurality of production zones. Similarly, in a horizontal well that extends through a single zone, perforations near the "heel" of the well (i.e., nearer the surface) may begin to produce water before those perforations near the "toe” of the well. The production of water near the heel reduces the overall production from the well.
- the quality of fluids produced from the different production zones may vary. That is, the quality of fluid produced from one zone may be greatly superior to that of another production zone, thus making it desirable to prevent the produced fluids from commingling. Also problematic is that, depending on the location of the well, there may exist regulations that forbid such commingling of fluids from separate production zones.
- One known method for preventing the commingling of fluids produced from a plurality of production zones involves drilling one or more "laterals" or “drain-holes” substantially horizontally outward into the production zones from the wellbore. As understood in the art, these laterals significantly increase the drainage area around the wellbore and provide an unrestricted flowpath for fluids from the outer regions of the formation directly into the wellbore.
- embodiments disclosed herein relate to a method of converting a completed well into a dual completed well that includes selectively pumping a water-based fluid into a first production zone of the completed well, wherein the water-based fluid has a pH of greater than about 5; allowing the water-based fluid to form a continuous, non-flowing water-based gel in the first production zone of the completed well, wherein the water-based gel has a pH of greater than about 5; disposing a layer of cement into the completed well above the water-based gel; perforating a second production zone of the completed well in a location above the layer of cement; drilling through the layer of cement; and breaking the water-based gel located in the first production zone of the completed well, wherein the breaking comprises: exposing the water-based gel to a breaker fluid, wherein the breaker fluid has a pH of greater than about 5.
- embodiments disclosed herein relate to a method of treating a well that includes selectively pumping a water-based fluid into a production zone of the well, wherein the water-based fluid has a pH of greater than about 5; allowing the water-based fluid to form a continuous, non-flowing water-based gel in the production zone of the well, wherein the water-based gel has a pH of greater than about 5; and breaking the water-based gel, wherein the breaking comprises: exposing the water-based gel to a breaker fluid, wherein the breaker fluid has a pH of greater than about 5.
- FIG. 1 shows a wellbore treated in accordance with embodiments of the present disclosure.
- embodiments disclosed herein relate generally to methods of selectively pumping a water-based fluid (prepared at the surface) into a production zone of a wellbore, allowing the fluid to form a continuous, non-flowing water- based gel that has properties capable of performing a variety of functions within the production zone of the wellbore, and subsequently breaking the water-based gel using a breaker fluid.
- a water-based fluid may be selectively pumped into a wellbore. Selective pumping of the water-based fluid may be accomplished by "spotting" the water-based fluid into a zone or zones of interest, for example, one or more production zones.
- a water-based fluid of the present disclosure should be pumpable, gellable, and breakable once gelled. That is, the water-based fluid should be pumpable initially and, over time, be capable of forming a breakable gel.
- pumpable is used herein to mean that the water-based fluid is in a flowing condition such that it may be easily pumped (i.e., it requires the minimum amount of pressure to force it through restrictions in the circulating fluid system, such as bit nozzles or down-hole tools) into the selected zone(s) of the wellbore, and, after placement, fully conform to the shape of the selected zone(s).
- gellable is used herein to mean that the water-based fluid is capable of forming a water-based gel once selectively pumped into the wellbore.
- breakable is used herein to mean that the water-based gel, once formed, is capable of being converted back into a water-based fluid that can be pumped out of the formation.
- Water-based fluids that may be used in embodiments of the present disclosure may include, for example, those described in U.S. Patent No. 7,098,172 and U.S. Patent Application No. 60/946,882, which are both assigned to the assignees of the present disclosure.
- U.S. Patent No. 7,098,172 and U.S. Patent Application No. 60/946,882 which are both assigned to the assignees of the present disclosure.
- One of ordinary skill in the art will recognize that these are only listed as examples and are not intended to be limiting to the present disclosure.
- the water-based fluid when pumped, should have sufficient viscosity and/or plugging efficiency to at least substantially reduce fluid leakoff into the formation during or subsequent to its placement. Because a water-based fluid of the present disclosure is preferably pumped into a production zone of the wellbore, the water-based fluid should be non-damaging to the production zone and thus, in preferred embodiments, should have a pH greater than about 5, and more preferably greater than about 7. Additionally, the water-based fluid should be relatively nontoxic and safe to handle.
- the pumpable water-based drilling fluid may be pumped into a wellbore at a rate below that capable of fracturing the formation. Furthermore, once selectively placed in the production zone(s) of the wellbore, the water-based fluid may be allowed to settle and form a continuous, non-flowing water-based gel that functions as a solid gel plug within the wellbore. The time required to let the liquid settle and form a water-based gel may vary, depending on the components used to form the gel.
- the water-based drilling fluid may be selectively pumped into a cased well which may or may not have production zone(s) that are substantially depleted. Additionally, the water-based fluid may be selectively pumped into a well during drilling, i.e., into a well that has not yet been completed, in order to preserve completion of a well as well as to convert a single completed well into a dual- or multi-completed well (i.e., a well having more than one production zone).
- the water-based fluid may harden to form a continuous, non- flowing water-based gel which may be used to plug a production zone of a formation in order to reduce or prevent fluid loss in the production zone during workover of a wellbore.
- the continuous, non-flowing water-based gel may be used to preserve the formation during the conversion of a single completed well into a dual- or multi-completed well, as is discussed below.
- the water-based gel should not significantly penetrate the formation matrix beyond a distance on the order of about 1 cm from the rock-face in order to reduce or prevent damage to the formation and allow for subsequent recovery or injection of fluids into the formation.
- the water-based gel similar to the water-based fluid, should have a pH of greater than about 5, and more preferably, greater than about 7. This is desirable as it may reduce or prevent damage to the formation.
- the amount of water-based gel used in the presently disclosed process may be dependent on the geological properties of the formation as well as the existing perforations in the well.
- the water-based gel should be breakable, i.e., reversible without the necessity of a strong acid.
- Conventional gels are typically broken by exposure to a strong acid.
- preferred embodiments of the present disclosure require that the water-based gel be breakable using a breaker fluid having a pH greater than about 5, and more preferably greater than about 7.
- a relatively basic (i.e., pH greater than about 5) breaker fluid so as to reduce or prevent formation damage that typically results when strong acids are injected into a formation, as well as to minimize corrosion of downhole equipment.
- sufficient breakers of the present disclosure include oxidative breakers, such as peroxides (e.g., sodium peroxide) and hypochlorite salts (e.g., lithium hypochlorite or sodium hypochlorite).
- the water-based gel may be converted back into a water-based "spent" fluid.
- This spent fluid preferably has a pH greater than about 5, and more preferably greater than about 7, similar as to when it was initially pumped into the wellbore, as discussed above, so as to reduce or prevent damage to the formation and/or damage to the drilling equipment.
- the breaker fluid may be incorporated into the initial fluid composition at the surface (as an internal breaker) to slowly break the gel over time, as, for example, through use of a chemically or thermally delayed oxidative breaker; or the breaker may be placed (e.g., selectively pumped) into the wellbore separately to reverse the gel on contact at the desired time.
- embodiments of the present disclosure include a method for converting a single, completed wellbore into a dual-completed wellbore.
- Such methods include selectively pumping a gellable, pumpable water-based fluid into a first production zone 12 of a completed well 10, allowing the water-based fluid to solidify and form a continuous, breakable, non-flowing water-based gel in the first production zone 12 of the completed well 10, disposing a layer of cement 14 above the water-based gel, perforating a second production zone 16 located above the layer of cement 14, drilling a hole through the layer of cement 14 in order to gain access to the formed gel located in the first production zone 12, and then breaking the water-based gel located in the first production zone 12 of the completed well 10 wherein the breaking comprises injecting a breaker fluid substantially through the water-based gel.
- both the water-based fluid and the water- based gel preferably have a pH greater than about 5, and more preferably greater than 7.
- the water-based gel once formed, should possess sufficient strength and rigidity so as to both support the layer of cement disposed thereon as well as to provide an impermeable barrier to the flow of fluids from the first production zone.
- the layer of cement may have a thickness of at least about 4 meters. Additionally, the water- based gel should be able to withstand environmental well conditions, for example, increased temperatures that may be present downhole.
- the breaker fluid has a pH greater than about 5, and more preferably greater than about 7. This may reduce or prevent the breaker fluid from breaking (or otherwise impacting) the layer of cement disposed between the first and second production zones of the wellbore as well as reducing or preventing damage to the formation and/or any drilling equipment.
- the "spent" fluid (the fluid that results from breaking the gel) have a pH greater than about 5, and more preferably greater than about 7.
- production tubing may be installed to facilitate production from both the first and second production zones, either simultaneously or in such a manner so as to prevent the produced fluids from commingling. It may be desirable to prevent such fluids from commingling for a variety of reasons, as discussed previously.
- production tubing may be installed in the first production zone by drilling through the layer of cement after first perforating and installing production tubing in the second production zone.
- the water-based gel may be used to preserve completion of the well while drilling through a production zone in a well that may or may not be cased.
- a method of using the water-based gel to preserve completion may include drilling through a production zone of a wellbore, ceasing drilling in order to selectively pump a water-based fluid into the production zone, allowing the water-based fluid to form a continuous, non-flowing water-based gel in the production zone, resuming drilling of the production zone, and breaking the water-based gel upon completion of drilling, wherein the breaking comprises exposing the water-based gel to a breaker fluid, wherein the breaker fluid has a pH greater than about 5, and more preferably greater than about 7.
- the water-based fluid and water-based gel formed therefrom have a pH greater than about 5, and more preferably greater than about 7.
- the method may further comprise casing and cementing ("completing") the well after breaking the water- based gel.
- the well may be completed prior to selectively pumping the water-based fluid into the production zone.
- Embodiments of the present disclosure may provide for reduction or prevention of fluid loss and/or lost circulation when drilling according to conventional methods. This may occur prior to fluid loss and/or after fluid loss is detected. Additionally, embodiments of the present disclosure may allow for production from and zonal isolation within a dual- or multi-completed well such that fluids produced from each production zone are prevented from commingling.
- embodiments of the present disclosure may have utility over a broad range of operating conditions.
- the water-based fluid and the water-based gel should be effective in the presence of high salt concentration brines as well as be resistant to thermal degradation at temperatures generally encountered during drilling operations.
- the water-based gel should be formulated over a broad range of onset times and strengths while remaining relatively insensitive to minor variations in conditions under which it is formulated.
- the water-based gel should be readily suited for on-site preparation in the field where process controls are often imprecise, such as remote hostile onshore and offshore locations.
- embodiments of the present disclosure may offer practical advantages over conventional techniques for treating a wellbore.
- the methods disclosed herein are cost effective in that the components used to form the water- based fluid, and thus the gel, may be readily available and inexpensive while still being relatively non-toxic to the environment and safe to handle.
Abstract
Description
Claims
Priority Applications (4)
Application Number | Priority Date | Filing Date | Title |
---|---|---|---|
BR112012000483A BR112012000483A2 (en) | 2009-07-09 | 2010-07-07 | methods for treating a wellbore. |
EP10797766A EP2452041A2 (en) | 2009-07-09 | 2010-07-07 | Methods for treating a wellbore |
US13/382,391 US20120273200A1 (en) | 2009-07-09 | 2010-07-07 | Methods for treating a wellbore |
MX2012000373A MX2012000373A (en) | 2009-07-09 | 2010-07-07 | Methods for treating a wellbore. |
Applications Claiming Priority (2)
Application Number | Priority Date | Filing Date | Title |
---|---|---|---|
US22437809P | 2009-07-09 | 2009-07-09 | |
US61/224,378 | 2009-07-09 |
Publications (2)
Publication Number | Publication Date |
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WO2011005836A2 true WO2011005836A2 (en) | 2011-01-13 |
WO2011005836A3 WO2011005836A3 (en) | 2011-04-21 |
Family
ID=43429812
Family Applications (1)
Application Number | Title | Priority Date | Filing Date |
---|---|---|---|
PCT/US2010/041176 WO2011005836A2 (en) | 2009-07-09 | 2010-07-07 | Methods for treating a wellbore |
Country Status (5)
Country | Link |
---|---|
US (1) | US20120273200A1 (en) |
EP (1) | EP2452041A2 (en) |
BR (1) | BR112012000483A2 (en) |
MX (1) | MX2012000373A (en) |
WO (1) | WO2011005836A2 (en) |
Cited By (1)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
WO2014085055A1 (en) * | 2012-11-28 | 2014-06-05 | Halliburton Energy Services, Inc. | Methods of enhancing the fracture conductivity of multiple interval fractures in subterranean formations propped with cement packs |
Families Citing this family (1)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
WO2015171139A1 (en) * | 2014-05-07 | 2015-11-12 | Halliburton Energy Services, Inc. | Imidazolinium compounds as dual corrosion inhibitors |
Citations (2)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US7098172B1 (en) | 2002-06-05 | 2006-08-29 | M-I L.L.C. | Prevention and treatment of lost circulation with crosslinked polymer material |
WO2009006253A2 (en) | 2007-06-28 | 2009-01-08 | M-I Llc | Degradable gels in zonal isolation applications |
Family Cites Families (7)
Publication number | Priority date | Publication date | Assignee | Title |
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US3815681A (en) * | 1972-05-24 | 1974-06-11 | Shell Oil Co | Temporarily plugging an earth formation with a transiently gelling aqueous liquid |
US4819727A (en) * | 1986-07-21 | 1989-04-11 | Mobil Oil Corporation | Method for suspending wells |
US4957166A (en) * | 1989-07-14 | 1990-09-18 | Marath Oil Company | Lost circulation treatment for oil field drilling operations |
US5413178A (en) * | 1994-04-12 | 1995-05-09 | Halliburton Company | Method for breaking stabilized viscosified fluids |
US20050227874A1 (en) * | 2004-04-06 | 2005-10-13 | Berger Paul D | Composition and method for fracturing subterranean reservoirs |
US8895480B2 (en) * | 2004-06-04 | 2014-11-25 | Baker Hughes Incorporated | Method of fracturing using guar-based well treating fluid |
US8096358B2 (en) * | 2008-03-27 | 2012-01-17 | Halliburton Energy Services, Inc. | Method of perforating for effective sand plug placement in horizontal wells |
-
2010
- 2010-07-07 WO PCT/US2010/041176 patent/WO2011005836A2/en active Application Filing
- 2010-07-07 EP EP10797766A patent/EP2452041A2/en not_active Withdrawn
- 2010-07-07 BR BR112012000483A patent/BR112012000483A2/en not_active IP Right Cessation
- 2010-07-07 MX MX2012000373A patent/MX2012000373A/en active IP Right Grant
- 2010-07-07 US US13/382,391 patent/US20120273200A1/en not_active Abandoned
Patent Citations (2)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US7098172B1 (en) | 2002-06-05 | 2006-08-29 | M-I L.L.C. | Prevention and treatment of lost circulation with crosslinked polymer material |
WO2009006253A2 (en) | 2007-06-28 | 2009-01-08 | M-I Llc | Degradable gels in zonal isolation applications |
Cited By (1)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
WO2014085055A1 (en) * | 2012-11-28 | 2014-06-05 | Halliburton Energy Services, Inc. | Methods of enhancing the fracture conductivity of multiple interval fractures in subterranean formations propped with cement packs |
Also Published As
Publication number | Publication date |
---|---|
US20120273200A1 (en) | 2012-11-01 |
MX2012000373A (en) | 2012-03-29 |
WO2011005836A3 (en) | 2011-04-21 |
BR112012000483A2 (en) | 2016-02-16 |
EP2452041A2 (en) | 2012-05-16 |
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