MX2011005048A - Methods for minimizing fluid loss to and determining the locations of lost circulation zones. - Google Patents

Abstract

A method for determining a location of a lost circulation zone in a wellbore having a first wellbore fluid therein that includes allowing loss of the first wellbore fluid to the lost circulation zone to stabilize; adding a volume of a second wellbore fluid having a density less than the first wellbore fluid to the wellbore on top of the first wellbore fluid to a predetermined wellbore depth; determining an average density of the combined first wellbore fluid and second wellbore fluid; mixing the first wellbore fluid and the second wellbore fluid together; pumping a volume of a third wellbore fluid having a density greater the average density of the combined first and second wellbore fluid into the wellbore bottom until fluid loss occurs; and determining the location of the lost circulation zone is disclosed.

Description

METHODS FOR. REDUCE THE MINIMUM LOSS OF FLUID TO AND DETERMINE LOCATIONS OF CIRCULATION AREAS WITH LOSS BACKGROUND OF THE INVENTION Field of the Invention The embodiments described herein generally refer to leakage circulation experienced during drilling of a well. In particular, the above-described modalities relate to the identification or determination of the location or locations of loss zones in a well for circulation treatment with loss.

Previous Technique During the drilling of a well, various fluids are typically employed in the well for a variety of functions. The fluids can be circulated through a drill pipe and drill head or drill bit in the well, and then can subsequently flow upward through the well to the surface. During this circulation, the drilling fluid can act to remove drilling cuts from the bottom of the hole to the surface, to suspend the cuts and ballast material when the circulation is interrupted, to control sub-surface pressures, to maintain the integrity of the well until the section of the well is coated and cemented, · to isolate the formation fluids by providing sufficient hydrostatic pressure to prevent the ingress of formation fluids into the well, to cool and lubricate the drill string and the drill and / or to maximize the penetration rate.

Well fluids can also be used to provide sufficient hydrostatic pressure in the well, to prevent the ingress and egress of formation fluids and well fluids, respectively. When the pore pressure (the pressure in the pore space of the formation that is provided by the formation fluids) exceeds the pressure in the open well, the formation fluids tend to flow from the formation to the open well. Therefore, the pressure in the open well is typically maintained at a higher pressure than the pore pressure. While it is highly advantageous to maintain the well pressures on the pore pressure, on the other hand, if the pressure exerted by the well fluids exceeds the fracture resistance of the formation, a formation fracture and thus induced mud losses , they can happen. In addition, with a formation fracture, when the well fluid in the ring flows into the fracture, the loss of well fluid can cause the hydrostatic pressure in the well to decrease, which in turn can also it can allow formation fluids to enter the well. As a result, the formation fracture pressure typically defines an upper limit for allowable well pressure in an open well while the pore pressure defines a lower limit. Therefore, a major restriction in well design and drilling fluid selection is the balance between varying pore pressures and formation fracture pressures or fracture gradients across the well depth.

As stated above, well fluids are circulated to the bottom of the well to remove rock, as well as supply agents to combat the variety of aspects described above. Fluid compositions can be water or oil based and can comprise ballasting agents, surfactants, propellants and polymers. However, for a well fluid to perform all of its functions and allow the well operations to continue, the fluid must remain in the borehole. Frequently, undesirable formation conditions are encountered where substantial amounts or, in some cases, virtually all the well fluid can be lost to formation. For example, well fluid can leave the hole in the hole through large or small cracks or fractures in the formation or through a matrix of highly porous rock that surrounds the bore hole.

The circulation with loss is a recurrent problem of perforation, characterized by loss of drilling mud in formations inside the well. However, other fluids besides the "drilling fluid" can potentially be lost, including completion, drilling, production fluid, etc. Circulation with loss can occur naturally in formations that are fractured, highly permeable, porous, cavernous or vugular or hollow. These terrestrial formations may include shales, sand, gravel, shell beds, reef deposits, limestone, dolomite and chalk or calcium carbonate, among others.

The circulation with loss can also result from pressure induced during drilling. Specifically, induced sludge losses can occur when the mud weight, required for well control and to maintain a stable well, exceeds the fracture strength of the formations. A particularly challenging situation arises in depleted reservoirs, where the drop in pore pressure weakens rocks containing hydrocarbons, but neighboring or inter-stratified low permeability rocks, such as shales, They maintain their pore pressure. This can make it impossible to drill certain depleted areas, because the weight of mud required to support the shale exceeds the fracture resistance of sand and silt. Another unintentional method by which circulation with loss can result is through the inability to remove low and high gravity solids from fluids. Without being able to remove these solids, the density of fluid can increase, thus increasing the pressure of the orifice, and if this orifice pressure exceeds the fracture pressure of the formation, fractures and loss of fluid can result.

Losing any fluid in the formation, for any reason, can be a costly result for the drilling, completion or production operation, due to the cost of the fluid as well as the non-operating time of the platform and rental of equipment. Mechanical and electrical methods exist to determine the fluid loss locations or zones; however, they require specialized equipment and repeated trips in and out of the hole. If this equipment is not available, the location of the leaking areas may not be currently determined but instead larger volumes than the necessary of circulation treatment with loss inside the well can be pumped with the hope that the treatment blocks the area where the losses are occurring, so that drilling operations (or others) can be resumed. Due to this inaccuracy, it is typically necessary to repeat the circulation treatments with loss, additionally increasing costs and non-operative time.

Accordingly, there is a continuing need for methods by which a loss zone can be determined more easily and more accurately, without the cost of specialized equipment, such that a loss zone can be identified and plugged further. quickly and resume regular drilling or other operations.

COMPENDIUM OF THE INVENTION In one aspect, the embodiments described herein relate to a method for determining a location of a leaky circulation zone in a well having a first well fluid, which includes allowing loss of the first well fluid to the circulation zone with loss to stabilize; adding a volume of a second well fluid having a lower density than the first well fluid to the well in the upper part of the first well fluid, at a predetermined well depth; determine an average density of first well fluid and the second well fluid combined; Mix together the first well fluid and the second well fluid; pumping a volume of a third well fluid that has a density greater than the average density of the first and second well fluids combined at the bottom of the well until fluid loss occurs; and determine the location of the circulation zone with loss.

In another aspect, the embodiments described herein relate to a method for minimizing loss of fluid to a circulation zone with loss in a well having a first well fluid, which includes allowing loss of the first well fluid to the zone. circulation with loss to stabilize; adding to the well a volume of a second well fluid having a lower density than the first well fluid, by the top of the first well fluid at a predetermined well depth; determine an average density of the first well fluid and the second well fluid combined; and pumping a third well having the determined average density of the first and second well fluids combined into the well to fill it.

In still another aspect, the modalities described herein relate to a method for determining a location of a circulation zone with loss in a well having a well fluid, which includes allowing loss of well fluid to the circulation zone with loss to stabilize; calculate the pressure gradient of the circulation zone with loss; increase the wellbore weight in the well from the bottom of the well up until fluid loss occurs; and calculate the location of the circulation zone with loss.

Other aspects and advantages of the invention will be apparent from the following description and appended claims.

BRIEF DESCRIPTION OF THE DRAWINGS FIGURES 1 to 6 show schematics of a well having a lossy circulation event and subjected to the methods described herein.

DETAILED DESCRIPTION The modalities described herein in general refer to the identification or determination of the location or locations of loss zones in a well. In particular, the modalities described herein relate to a determination of a circulation zone with loss, such that a circulation treatment with loss can be more accurately placed in the vicinity of the loss.

In particular, the method of this Description is based on the principles of pore pressure and pressure gradients within a well, to determine the location of a lossy circulation zone, instead of being based on costly and time consuming electrical or mechanical equipment to make those determinations. Specifically, the methods described herein may include determining pressure gradients to achieve a well balanced (or slightly over balanced) and then slowly introducing a heavier well fluid into the bottom of the well, such that when the heavier fluid arrives At the depth of the circulation zone with loss, additional fluid loss will occur, indicating that the location of the circulation zone with loss has been determined.

, With reference to FIGS. 1 to 6, schematic illustrations of a well in incremental stages of the methods described herein are illustrated. Specifically, as shown in FIGURE. 1, a well 10 includes therein a first well fluid 20. This well fluid 20 can include any type of well fluid, including drilling fluids, completion fluids, reservoir drilling fluids, production fluids and the like, which they may include one or more liquid and / or gas phases. On the contrary, no limitation is imposed on the type of drilling fluid that may be present in the well when leakage occurs, and the present methods can be applied to determine the location of the leaky circulation.

When a lossy circulation event occurs, the loss of the first well fluid 20 occurs in the formation of the lossy circulation zone 16, and a drop in the fluid level is identified, for example, by periodic replenishment volumes or constant, or the inability to maintain circulation of well fluid. Once a lossy circulation event is detected according to the methods described herein, the pumping of the first drilling fluid is stopped, and the fluid level 20a is allowed to decrease or stabilize at a static point at equilibrium 12. The Stabilization occurs when the pressure is balanced, the formation exerted in the circulation zone with loss and the pressure exerted by the fluid in the well (or at least substantially balance).

By stabilizing the first well fluid 20, a second well fluid 22 lighter than the first well fluid 20 is added to the top of the casing (ie, over the first well fluid). 20) until the second fluid level in well 20a reaches a predetermined well depth (which, as shown in FIGURE 2, is a depth of zero, at the top of the casing. With respect to the first well fluid 20, the second well fluid (as well as any other well fluids) can include at least one liquid and / or gaseous component In a particular embodiment, the second well fluid 26 can be water. The volume of the second well fluid 20 added to the well 10 is measured and recorded.When the second well fluid 20 is added to the well 10, the level of the first well fluid 20a can fall to a greater depth D2 compared to Di due to the increased density / pressure of fluid added by the second well fluid to obtain a balanced pressure system.

By stabilizing fluids 20 and 22 inside the well and measuring / recording the volume of the second well fluid. 22 added to the well, the average fluid density between the first and second combined well fluids 20 and 22 can be determined. This determination can be made through the calculation of fluid volume fractions, well fractions, depth fractions, total pressure inside the well and / or density of average fluid gradient. However, a person skilled in the art will appreciate that the final determination (average fluid density) can be decomposed into multiple calculation steps and can be performed as a single long calculation.

By determining the average density for the wellbore fluid system in the well (the well fluid layers 20 and 22), the fluids can be mixed / homogenized or displaced (with a third well fluid) in such a way that the fluid 24 present in well 10 is a substantially uniform fluid having a density at the calculated density (of the first and second fluids of wells 20 and 22), such that the well remains balanced (or even slightly over balanced for safety reasons). ). Depending on the intention of the operator, drilling can continue at this density or the location of the circulation zone with loss can be determined. The drilling can continue without making this determination in this case when the operator does not care to determine the location of the circulation zone with loss, but on the contrary wishes to determine the maximum density of the well fluid that can be used to continue the drilling with minima loss of fluid.

However, if the operator wishes to determine the location of the circulation zone with loss, once the well has a fluid density that substantially balances the pressure gradient of the well, a fourth well fluid 26 can be pumped into and fill the drill string. The fourth well fluid 26 may have a slightly higher density than the wellbore fluid 24. This increase in density can be achieved by formulating a fluid 26 having a density greater than the average density of the first and second well fluids 20 and 22 (through general fluid components, including weight or ballast material) and / or add a weight material to the third displacement fluid 24 (if used). The amount of this increase in density (compared to the balanced fluid 24) can be selected based on the particular well; however, convenient intervals may include an increase of at least 60.05 g / 1 (0.5 ppg) in some modalities and at least 120.1 g / 1 (1.0 ppg) in other modalities. However, no limitation is intended in the scope of the present description. On the contrary, other density differentials can be used, without departing from the scope of the present description.

The pumping of fluid 26 from the drill string and into the well 10 occurs at a slow expense, and by measuring the pulses or strokes of the pump, such that the volume of the fourth well fluid 26 can be recorded. Additionally, pumping can occur at a slow pace, and with periodic stops so that fluid loss can be detected as soon as possible after it has occurred. As illustrated in FIGURE 5, there has been no loss of fluid in the formation 18 because the density of the fluid 24 over the low pressure pore area in the lossy circulation zone 16 is the same as the pressure exerted by the fluid. the fluid on the area. However, as shown in FIGURE 6, the loss of fluid occurs because the volume of fluid 26 pumped into the well increases such that the fluid level 26a approaches the circulation zone with loss 16, the denser fluid 26 exerts more pressure in the circulation zone with loss 16 than does the formation in the well fluid 24. As soon as fluid loss is detected, the measurement of the volume of fluid 26 pumped into the well (according to it is pumped from the bottom of the well upwards) can be used to determine the depth D3 or location of the circulation zone with loss 16 using known well dimensional values.

However, it is possible that a single well 10 can include multiple circulation zones with loss 16. In this case, the zones of circulation with loss can be determined in the bottom of the well upwards, repeating the steps described here until each, zone of circulation with loss is identified and treated locally.

After the determination of the location or locations of the circulation zone with loss 16, a circulation treatment with loss can be placed close to the location of the lost zone. Circulatory treatments with loss fall into two main categories: low fluid loss treatments where the fracture or formation is rapidly plugged and sealed; and high fluid loss treatments, wherein the dehydration of the material to prevent fracture loss or formation with high leakage of a carrier fluid fills a fracture and / or forms a plug which then acts as the base to seal the fracture. The mechanism by which fluid loss is controlled, ie, plugged, bridged and filled, can be based on particle size distribution, relative fracture opening, fluid leakage through fracture walls, and fluid loss to the tip of the fracture. Accurate placement of these materials can allow less non-operational time of the platform and more managed use of circulation treatments with loss.

Selection of the circulation treatments with loss can be made based on the quantification of type and analysis of losses, type of formation / fracture and pressures within the zone of loss, many of which can be quantified during the methods described here. The selection based on these factors can be described in greater detail in the U.S. Patent Application. Serial Number 61 / 024,807, which was assigned to the present assignee and is hereby incorporated by reference in its entirety.

The treatments of circulation with loss can include treatments based on particles and / or fraguables. Particle-based treatments may include the use of particles frequently referred to in the art as bridge materials. For example, these bridging materials may include at least one particulate solid substantially resistant to crushing or crushing, such that bridging materials support opening and bridging or plugging fractures (cracks and 'cracks) that are induced in the well wall . Examples of bridge materials suitable for use in the present disclosure include graphite, calcium carbonate (preferably marble), dolomite (MgCC> 3.CaCC> 3), celluloses, micas, propellant materials such as sands or particles. ceramics and their combinations.

In addition to these particle-based treatments, depending on the classified severity of the loss, a reinforcing plug, including plugs based on cement or resin, may be necessary to seal the fracture.

Suitable castable treatments for use in the methods of the present disclosure include those that can set or solidify over a period of time. The term "settable fluid" as used herein, refers to any convenient liquid material that can be pumped or emplaced at the bottom of the well, and will harden over time to form a solid or gelatinous structure and become more resistant to mechanical deformation . Examples of compositions that can be included in the carrier fluid to make it curable include cementitious materials, "prepared molding powders" and components of chemical or polymeric resins.

In addition, while the present description may relate to the use of these methods in traditional wells and / or traditional drilling operations, the present invention is thus not limited. On the contrary, specifically within the scope of the present invention the methods described herein can be employed in any well operations, including for example, drilling lining, cable drilling, conventional drilling, reverse circulation drilling and drilling with roller pipe, etc.

Example The following example is used to demonstrate how the depth of a lossy circulation zone can be calculated and a treatment detected more quickly and accurately in the well.

For a given well (such as the one shown in FIGURE 1) that has a fluid leak observed from an original well fluid of 1321.13 g / 1 (11 ppg), fluid loss can be allowed to stabilize. After stabilization, a light density fluid (water, 1000.9 g / 1 (8.334 ppg)) can be added to the top of the well, as shown in FIGURE 2, and the volume of the light density fluid added to the well for filling it to a predetermined depth (ie, zero depth) is recorded (as shown in Table 1 below). From the lightest density fluid volume (12869 1) 3400 gal.), The diameter of the liner and drill pipe, the volume per depth (and depth) of the light density fluid can be calculated. In this way, when knowing the total drilled length, the well fractions of the fluid of original and light density, as well as the pressure total on the well, can be calculated. From this pressure value, the average fluid gradient is calculated (1210.5 g / 1 (10,079 ppg)).

Table 1 Volume / depth 40.74 of coating *** (3.2811) 1 / m (g / ft) Depth Calculated of Fluid 315.83 M (Ft) of Added Light Fluid *** (1036.2) light density TVD of Well 914.4 Total * (3000) M (Ft) Fraction of Well of Fluid Density 7745.2 Original *** (1123.3) Fraction kPa (psi) Fraction of Well of Fluid density 3096.3 light *** (449.07) Fraction kPa (psi) Total Pressure over 10841 kPa (psi) to the bottom Well *** (1572.3) from the hole Density of Fluid gradient 1210.52 g / 1 (pounds per Average *** (10,079) gallon) After mixing the original and light density fluid to form a homogeneous fluid (1210.52 g / 1 (10,079 ppg), a weight or ballast material (at +120.1 g / 1 (1 ppg)) can be added to the fluid to form a heavier fluid. The heavier fluid can be filled into the drillstring and slowly pumped to the bottom of the well. Pulses or pump strokes can be calculated, and pumping stopped periodically, so that fluid levels can be observed and fluid loss can be immediately detected. Upon detection of fluid loss, the number of pump pulses and / or volume of fluid pumped into the well can be recorded. From the heaviest fluid volume pumped to the well (as well as drill pipe and drill diameter), the volume per depth, as well as the total distance from the bottom of the well, of the heaviest fluid, can be calculated. The zone of circulation with loss will correspond to a heavier fluid height. From the heavier fluid height, the depth from the surface can be calculated, such that a lossy circulation treatment can be detected with relative accuracy.

Modalities of the present disclosure can advantageously provide at least one of the following. Losing any fluid in the formation, for any reason, can be a costly result from the drilling, completion or production operation, due to the cost of the fluid as well as the time not operative of the platform and equipment rental. Conventional reactions include the use of either mechanical or electrical equipment (with repeated trips in and out of the orifice) or larger than the required volumes of lost circulation treatments can be pumped into the well in the hope that the treatment will plug the area where losses occur so that drilling (or other) operations can be resumed. Due to this inaccuracy, it is typically necessary to repeat circulation treatments with loss, further increasing costs and non-operative time. However, according to the present disclosure, methods are provided by which a loss zone can be determined more easily and more accurately without the cost of specialized equipment, so that a loss zone can be identified and plugged more quickly and resume regular drilling or other operations.

While the invention has been described with respect to a limited number of embodiments, those skilled in the art, with the benefit of this disclosure, will appreciate that other embodiments may be designed which do not depart from the scope of the invention as described herein. Accordingly, the scope of the invention should be limited only by the appended claims.

Claims (22)

1. A method for determining a location of a circulation zone with loss in a well, having a first well fluid, characterized in that it comprises: allowing loss of the first well fluid to the circulation zone with loss to stabilize; adding a volume of a second well fluid having a lower density than the first well fluid above the first well fluid to a predetermined well depth; determine an average density of the first well fluid and the second well fluid combined; mix the first well fluid and the second well fluid together; pumping a volume of a third well fluid that has a density greater than the average density of the first and second well fluids combined at the bottom of the well until fluid loss occurs; and determine the location of the circulation zone with loss.

2. The method according to claim 1, characterized in that it further comprises: pumping a circulation treatment with loss in the determined location of the circulation zone with loss.

3. The method according to claim 1, characterized in that the third fluid The well has a density of at least 60.5 g / l (0.5 ppg) more than the average density of the first and second combined well fluids.

4. The method according to claim 1, characterized in that pumping the volume of the third well fluid comprises: pumping the third well fluid to the bottom of a drilling assembly; and pumping and measuring pulses or pump strokes as the third well fluid exits the bottom of the drill assembly until loss of fluid is detected and pumping is stopped.

5. The method according to claim 1, characterized in that it further comprises: identifying the loss of the first well fluid to the circulation zone with loss.

6. The method according to claim 5, characterized in that it further comprises: stopping the pumping of the first well fluid into the borehole.

7. The method according to claim 1, characterized in that it further comprises: determining a location of the second circulation zone with loss in the well.

8. The method according to claim 1, characterized in that the mixing it comprises forming a homogeneous mixture of the first and second well fluids.

9. A method for minimizing loss of fluid to a circulation zone with loss in a well having a first well fluid there, characterized in that it comprises: allowing loss of the first well fluid to the circulation zone with loss to stabilize; adding a volume of a second well fluid having a lower density than the first well fluid to the well through the top of the first well fluid at a predetermined well depth; determine an average density of the first well fluid and the second well fluid combined; and pumping a third well that has the determined average density of the first and second well fluids combined in the well to fill the well.

10. The method according to claim 9, characterized in that it further comprises: drilling with the third well fluid having the determined average density.

11. The method according to claim 9, characterized in that it further comprises: pumping a third well having the average density of the first and the second well fluids combined in the well to fill the well; pump a volume of a fourth fluid from. well that has a density greater than the average density of the first and second well fluids combined at the bottom of the well until loss occurs, and determine the location of the circulation zone with loss.

12. The method according to claim 11, characterized in that it further comprises: pumping a circulation treatment with loss in the determined zone of the circulation zone with loss.

13. The method according to claim 11, characterized in that the fourth well fluid has a density of at least 60.5 g / 1 (0.5 ppg) more than the average density of the first and second combined well fluids.

14. The method according to claim 11, characterized in that pumping the volume of the fourth well comprises: pumping the fourth well fluid to the bottom of a drill assembly; and pumping and measuring pulses or pump strokes as the fourth well fluid exits the bottom of the drill assembly until loss of fluid is detected and pumping is stopped.

15. The method according to claim 9, characterized in that it also comprises: identify loss of the first well fluid to the formation.

16. The method according to claim 9, characterized by further comprising: stopping the pumping of the first well fluid to the well.

17. The method according to claim 11, characterized in that it further comprises: determining a location of a second circulation zone of loss in the well.

18. The method according to claim 9, characterized in that pumping the third well fluid comprises displacing the first and second well fluids from the well.

19. A method for determining a location of a circulation zone with loss in a well having a well fluid, characterized in that it comprises: allowing loss of the well fluid to the circulation zone with loss to stabilize; calculate the pressure gradient of the circulation zone with loss; increase the weight of the well fluid in the well from the bottom of the well up until loss of fluid occurs; and calculate the location of the circulation zone with loss.

20. The method of compliance with claim 17, characterized in that it also comprises: pump a circulation treatment with loss in the determined area of the circulation zone with loss.

21. The method according to claim 17, characterized in that calculating the pressure gradient comprises determining a well fluid density that balances or overpresses or slightly balances the pressure gradient.

22. The method according to claim 17, characterized in that the loss of fluid is stabilized when the pore pressure and the fluid pressure are substantially the same.