WO2004042189A1

WO2004042189A1 - Method to solids-pack non-vertical wellbores

Info

Publication number: WO2004042189A1
Application number: PCT/US2003/033764
Authority: WO
Inventors: William R. Wood; Paul M. Mcelfresh; Chad F. Williams
Original assignee: Baker Hughes Incorporated
Priority date: 2002-11-01
Filing date: 2003-10-28
Publication date: 2004-05-21
Also published as: AU2003286666A1; US20040084181A1

Abstract

A method of preparing a solids-pack for use in oilfield completion operations involves staged pumping using two distinct types of carrier fluid with distinct solids loadings during the solids deposition process. The method can be employed in packing of non-vertical oilfield wellbores for formation stabilization, fracture stabilization and/or sand control, particularly around sand exclusion devices. In preferred embodiments the method results in greater uniformity of packing, and also offers the advantage of much more rapid deposition and therefore of completion of the pack phase, reducing overall rig time.

Description

METHOD TO SOLIDS-PACK NON-VERTICAL WELLBORES BACKGROUND OF THE INVENTION

1. Field of the Invention

(0001) This invention relates to the field of oil or gas well completions. More particularly, it relates to the field of sand control and solids-packing of wellbores, and to the use of media for carrying gravels, proppants and other solids into the wellbore to a pack site during well completion operations.

2. Background Art

(0002) It is well-known that solid particles, such as gravels and proppants, must be transported during certain oilfield well completion operations. The reasons for such transport include, for example, to prop open fractures in a hydrocarbon recovery zone, to act as a filtering medium to prevent formation solids from flowing to the surface, or to stabilize a formation around the wellbore at the reservoir site. This transport procedure involves adding a desired concentration of the solid particles to a carrier fluid, then pumping this resultant slurry into the desired location in the wellbore such that the solids cover the entire interval of formation.

(0003) Uniformity in packing is particularly desirable when a vertical wellbore has been drilled in an unconsolidated sand reservoir. In these cases the transport may be intended to enable filling, or "packing", of the isolated annulus area around a sand exclusion device of some type, generally a cylindrical screen with a liner. The packed annulus area, along with the sand exclusion device, serves to filter out unconsolidated sand, known as "fines", during the hydrocarbon recovery from the reservoir. The reduction or elimination of the sand from the fluid hydrocarbon being recovered is important to increasing the purity of the recovered product and to preventing damage to equipment and/or undesired clogging of the production conduit.

(0004) Proppants are used to pack the annulus around a sand exclusion device. Proppant is defined as a natural or synthetic particulate solid that, when packed, exhibits an interstitial diameter that is less than that of the average sand particle in the unconsolidated sand formation. These materials range in composition from naturally occurring quartz sand to manufactured alumino-silicates which includes ceramics and, in cases where even greater pressure resistance is needed, sintered bauxite. These materials are also generically referred to as gravel.

(0005) In order to effect preparation of a solids pack as described hereinabove, a packer device is used to seal the wellbore and isolate the annulus area between the desired portion of the tool string and the wellbore at the pack site. As the gravel or proppant is pumped into the annulus area via a carrier fluid of some type, a crossover service tool directs the fluid/solids composition from its introduction means (the work string) to the annulus area. This enables deposition of the solids in the annulus area and subsequent removal of the circulated carrier fluid during a continuous pumping cycle.

(0006) Those skilled in the art know that to ensure the most consistent deposition throughout the annulus area it is necessary to use an appropriate pump rate and a correspondingly appropriate carrier fluid. If the two are not appropriately selected, the result may be uneven deposition and a poor pack that cannot fully meet its assigned requirements. In the case of a vertical wellbore, the presence of gravity tends to mitigate the factors that can result in a non-uniform gravel or proppant deposition in the pack. It is known in the art that a wide variety of carrier fluids and a wide variety of gravel loadings in the carrier fluid can be employed, at a variety of pump rates, for these wellbores with satisfactory results.

(0007) However, such is not the case with horizontal and certain deviated wellbores. Some of these non-vertical wellbores must be filled by a two-step process, which differs in important aspects from the one-step, bottom up process used for vertical wellbores. In filling such non-vertical wellbores, the first step is to fill the bottom two-thirds, approximately, of the annulus with solids. These solids progress to the end (or "toe") of the well by a "progressing dune" mechanism wherein suspended solids flow over deposited solids. This first step is denoted the "alpha wave". Once the alpha wave has reached the toe of the well, the solids then fill the remaining empty space in the annulus until the progressing dune once again reaches the crossover tool. This second step is called the "beta wave". Because of the limited annular clearances, the overall length of packed interval, and the pressure at which the formation will fracture, variables such as carrier fluid selection, gravel loading, and pump rate must be carefully determined and monitored to ensure that the formation does not fracture and that the annulus does not become plugged with solids which then operate to prevent some areas of the annulus from being uniformly packed. This plugging event is called "bridging". To overcome these problems, it is often effective to reduce the gravel loading while maintaining the pump rate such that the circulating fluid pressure does not exceed the fracture pressure of the formation. While the result of this adjustment procedure tends to improve pack consistency, the time to accomplish the deposition is significantly increased, sometimes to unacceptably long periods.

(0008) In view of the need for preparing consistent and uniform packs in a variety of non-vertical wellbores, it would be desirable in the art to develop a method of preparing such packs that overcomes these and related problems.

SUMMARY OF THE INVENTION

(0009) Accordingly, it is an object of the present invention to provide a method of solids-packing for use in non-vertical, including both horizontal and deviated, wellbores that ensures a highly uniform pack and reduces the time necessary to accomplish this task.

(0010) In carrying out this and other objects of the invention, there is provided a method that involves, first, pumping into the wellbore a high apparent viscosity carrier fluid, as defined, that contains a relatively higher amount of solid particles. This first stage of pumping is carried out until at least a major portion of the alpha wave deposition is accomplished. Thereafter a low apparent viscosity carrier fluid, as defined, containing a relatively lower amount of solid particles, is pumped to accomplish the remaining portion of the alpha wave deposition, if any, and also the entire beta wave deposition. Thus, a solids pack is formed. In preferred embodiments the solids pack deposition shows equal or superior uniformity with a deposition time that is significantly shorter than is often necessary to accomplish comparable results using heretofore known methods.

DETAILED DESCRIPTION OF THE INVENTION

(0011) The present invention accomplishes its objects via a novel approach which is easily adaptable to existing equipment onsite for transporting the solids and offers in particular a substantial reduction in the amount of time required to form the solids pack. Such time reduction translates, in the oilfield industry, into substantial cost savings. This novel approach is essentially a way to counteract many of the operational problems that result in the uneven or non-uniform gravel/proppant depositions encountered in horizontal and some deviated wellbores when packed using heretofore known methods. It offers the additional and important advantage of also enabling application of an increased gravel or proppant concentration which reduces the time required to perform such deposition, and therefore reduces what is referred to as overall "rig time", i.e., the cost overhead expense to operate a rig and its facilities. In the present invention, these advantages are achieved through specific "staged" combinations of carrier fluid and solids loading. It has been found that, by matching the identification of the carrier fluid and its specific solids loading to each wave or portion thereof, more solids per unit of time can be pumped as compared with conventional packing methods such as water packing. The result is that the entire procedure can be accomplished in much less time, with superior results.

(0012) As used herein, "alpha wave" refers to that part of the deposition that occurs first, from the portion of the sand exclusion device that is closest to the wellhead down to the toe of the wellbore. Throughout the alpha wave deposition an equilibrium dune height is maintained. As used herein, "equilibrium dune height" refers to the physical level of deposition at which, based upon the velocity (i.e., pump rate) and viscosity of the carrier fluid, deposition of the solids is approximately equal to re-suspension of the solids. Thus and in contrast, assuming that the pump rate has not changed, the "beta wave" refers to that part of the deposition that occurs second, where the equilibrium is no longer being maintained and the solids are being deposited again. This occurs particularly when the deposition pattern must change direction, such as occurs when deposition is completed to the toe and is now starting on essentially the opposite end of the wellbore, that is, deposition is now proceeding back toward the wellhead. Deposition is determined to be complete when solids completely surround the sand exclusion device as seen by a sharp pressure increase at the surface pumps.

(0013) It is important to note that the orientation of the wellbore affects the deposition pattern. For example, in the case of preparing a gravel-pack around a sand exclusion device in a horizontal or highly deviated wellbore (generally one oriented with its toe at an angle of greater than about 60 degrees from vertical), the "alpha wave" refers to the deposition that occurs in packing the bottom two-thirds, approximately, of the annulus area, and the "beta wave" refers to the deposition that occurs when packing the remaining one-third, approximately, of the annulus area. However, in the case of less deviated wellbores, for example, frequently those oriented with their toes at angles of less than about 60 degrees from vertical, alpha and beta wave deposition patterns are frequently not encountered because the solids can effectively pack by gravity alone from the toe back to the "heel", which is the upper demarcation of the pack site, in a one step process. Thus, the present invention is preferably applied to packing wellbores as to which discernible alpha and beta wave solids deposition patterns are encountered.

(0014) The present invention employs at least two distinct carrier fluids. The first is termed herein a "high apparent viscosity carrier fluid". The high apparent viscosity carrier fluid useful in the present invention preferably has an apparent viscosity of from about 5, more preferably from about 10, to about 20, more preferably to about 12, centipoise at a shear rate of 511 second^"1. It is important to note that these apparent viscosity ranges are as represented under downhole conditions. It will be evident to the skilled artisan that, under downhole conditions where temperatures and pressures may be much greater, the apparent viscosity of any given carrier fluid would be expected to be reduced when compared with its apparent viscosity under ambient conditions. Furthermore, such reduction in apparent viscosity can be predicted with relative accuracy. Therefore, it will also be clear to the skilled artisan that it is preferable to select as the high apparent viscosity carrier fluid a material having an apparent viscosity at ambient conditions which is higher than the preferred apparent viscosity range as represented under downhole conditions. As used herein, the phrase "as represented under downhole conditions" signifies that the apparent viscosity is given as actually measured at the downhole temperature and at test pressures from about 100 psig to about 1000 psig, although the actual measurement location is typically, for convenience's sake, at the earth's surface. These test pressures are generally lower than the actual downhole pressure encountered at the pack site, but the resulting measurements are adequately accurate for the purposes of the present invention because the apparent viscosity of a fluid is only weakly influenced by variations in pressure. Any viscometer typically used in the oilfield industry, which is capable of withstanding the applicable (downhole) temperature and selected test pressure, can be used to measure this apparent viscosity. The apparent viscosity can also be the calculated or modeled apparent viscosity of the downhole fluid based on measurement of the same fluid under ambient conditions. (0015) Essentially any carrier fluid that meets the apparent viscosity range given hereinabove and that exhibits non-Newtonian fluid behavior (a definitional requirement for apparent viscosity) is acceptable for use in the present invention as the high apparent viscosity carrier fluid. However, an additional caveat is that efforts should be made to ensure that the selection does not unacceptably interact with the formation, equipment, or solids particles to be employed.

(0016) In a preferred embodiment of the present invention a viscoelastic surfactant is selected as the high apparent viscosity carrier fluid. As used herein "viscoelastic" refers to a material having both viscous and elastic characteristics. This means that the material will deform when subjected to stress, but when the stress is removed only a fraction of the deformation will remain. In various embodiments this selection can be a liquid, solution, or gel, and can be representative of a wide variety of surface-active agents including, for example, emulsifiers, dispersants, oil-wetters, water-wetters, foamers and defoamers, combinations thereof, and the like. Those skilled in the art will recognize that the surface activity of a given molecule depends upon the molecule's structural groups. The preferred surfactants are members of the long-chained amine oxide and amido amine oxide families. As used herein, the term "long-chained" refers to compounds having preferred carbon chain lengths from 8 to 18, more preferably from 8 to 14. Such compounds may be either straight-chain or branched, and it is preferred that at least some unsaturation be present. These agents offer the additional benefits of being relatively simple to mix and non-harmful, in most cases, to producing formations. Also preferred in the present invention are compounds which are capable of self-assembly in solution and form a network of rod-like micelles.

(0017) When selected as at least one component of the high apparent viscosity carrier fluid, a viscoelastic surfactant has several important benefits in the present invention. It is, first and foremost, a viscosifier that leaves no residue. Residue can result in undesirable permeability reductions and voids in the solid pack.

(0018) Second, selection of a viscoelastic surfactant can reduce the impact of friction in the system. This reduction in friction (also referred to as "drag reduction") results in easier pumping and less energy use. It also decreases the risk of formation fracture because friction pressures are decreased. The result of these effects is more efficient solids deposition. (0019) Finally, use of a viscoelastic surfactant can promote and improve dehydration of the pack solids. A viscoelastic surfactant solution does not contain any solids; therefore, the solution cannot build a filter cake as it flows through the solids-pack and is therefore less likely to plug pore throats therein.

(0020) It should be noted that it is also possible to employ as or in the high apparent viscosity carrier fluid other well-known viscosifying agents exhibiting an apparent viscosity (non-Newtonian) effect. Examples of such agents can include some types of polymeric solutions, commonly referred to as "viscous gels". Nonetheless, because some viscous gels have a tendency to promote void formation and generally to result in looser packing which may, in turn, result in inconsistent or undesirable levels of containment of unwanted formation sands, such are generally not preferred in the present invention.

(0021) In the present invention the high apparent viscosity carrier fluid can be a single component or a mixture of components. When more than one component is to be used, a particularly beneficial choice is to include therein a proportion of a brine. "Brine" is defined herein as any saline liquid and can include solutions of chlorides, such as, for example, calcium chloride and sodium chloride; bromides; iodides; formates; combinations thereof; and the like. While brine alone may not exhibit sufficient viscosity to meet the requirements for the high apparent viscosity carrier fluid, it does have a density higher than that of fresh water and is extremely economical to use, thus cutting the incurred cost when compared with many possible one-component carrier fluid selections. Brine also lacks solid particles that can damage production formations, and lowers the risk of undesirable formation reactions. Since it is desirable to employ a brine in as large an amount possible in order to reduce the overall cost of the fluid, it is preferred that the fluid comprise from about 50, more preferably from about 75, still more preferably from about 90, most preferably from about 94, to about 99 percent brine by volume, based on total volume of the high apparent viscosity carrier fluid. The remainder can be one or more of the other possible high apparent viscosity carrier fluid selections, such as the viscoelastic surfactant. In a particularly preferred embodiment, from about 1 to about 6 percent by volume of the high apparent viscosity carrier fluid is a viscoelastic surfactant.

(0022) In the present invention the high apparent viscosity carrier fluid also includes, as a solids load, what is referred to herein as a "relatively higher amount of solid particles." This load is an amount of gravel or proppant that is preferably from about 3 to about 6, more preferably to about 4, pounds per gallon of the carrier fluid, which is referred to as "pounds per gallon added ("ppga")". While a greater concentration of solids can be employed, a loading that is significantly higher than about 6 ppga may present pumping and uniformity of deposition difficulties that outweigh any increase in speed of deposition. Therefore, such higher loadings are not preferred.

(0023) As is well-known in the art, typical gravels/proppants can be selected from natural and synthetic materials, including engineered compositions such as resin-coated materials and pressure-resistant materials. Choices can also include, for example, ceramics and other sintered materials. Where solids are being used to prepare a solids-pack around a sand exclusion device, it is preferred that the average particle diameter of the solid particles is selected to ensure that formation sand of undesirable particle size range is kept out of the wellbore while an appropriate level of permeability to the hydrocarbon is attained by the pack.

(0024) The second carrier fluid used in the present invention is termed herein a "low apparent viscosity carrier fluid". This refers to a carrier fluid having an apparent viscosity ranging preferably from about 0.25, more preferably from about 0.5, to less than about 5, more preferably less than about 4, and most preferably less than about 2, centipoise at 511 second^"1. Because of the low apparent viscosity, a majority of these fluids will tend to exhibit Newtonian flow behavior; however, it is not required that the fluid be characteristically Newtonian perse. Again, the apparent viscosity range is as represented under downhole conditions of temperature and pressure. As with the high apparent viscosity carrier fluid, it is anticipated that the exaggerated temperatures and pressures experienced at the downhole pack site during the deposition cycle will operate to reduce the apparent viscosity of the low apparent viscosity carrier fluid to a predictable extent. Therefore, again, it will be apparent to the skilled artisan that it is generally preferred to select a fluid with a higher apparent viscosity under ambient conditions in order to meet the defined apparent viscosity requirements under downhole conditions.

(0025) This second carrier fluid can be selected from a wide variety of known carrier fluids. For reasons of low cost and convenience, it is preferred that this carrier fluid also comprise a major amount of a brine as defined hereinabove. To aid in significantly reducing the apparent viscosity of the high apparent viscosity carrier fluid used in at least the earlier portion of the alpha wave deposition, in situ in the wellbore, a "viscosity reducer" can be included in the low apparent viscosity carrier fluid which is pumped during the later portion of the alpha wave deposition, if any, and throughout the beta wave deposition. Because the viscosity reducer "breaks", that is, rapidly reduces, the apparent viscosity of the in situ high apparent viscosity carrier fluid, the solids pack is fixed more tightly and the high apparent viscosity carrier fluid components, and particularly any surfactant that may be included therein, are more effectively removed from the wellbore and formation. This viscosity reducer is preferably a solvent, more preferably an organic solvent, which can be selected from, for example, isopropyl alcohol (C₂H₇OH), ethylene glycol monobutyl ether ("EGMBE"), acetone, combinations thereof, and the like. In general, most short-chained alcohols, alcohol ethers, aldehydes and ketones are effective in this function. Such are preferably, but not necessarily, water-soluble. As used herein, the term "short-chained" refers to compounds having 6 or fewer carbons, and includes both straight-chain and branched compounds.

(0026) It is preferred that the selected viscosity reducer be employed at a concentration of from about 1 to about 20, more preferably to about 10, percent by volume, based on total volume of the carrier fluid. Where a solvent is included in the low apparent viscosity carrier fluid, it is further preferred that the remainder be one or more brines, as defined hereinabove. In some instances, brine alone may efficaciously constitute all of the low apparent viscosity carrier fluid.

(0027) This low apparent viscosity carrier fluid preferably contains solid particles in a loading range of from about 0.1 , preferably from about 1 , to about 2.5 pounds per gallon added. This range is referred to herein as a "relatively lower amount of solid particles". It is preferred that the loading be maximized within this range in order to shorten packing time and therefore to optimize economics.

(0028) In the practice of the present invention the selected gravel or proppant, at the specified loadings, is pumped into the annulus around the sand exclusion device or otherwise around the appropriate section of the tool string within the wellbore, using equipment and under conditions typically employed by those skilled in the art. A crossover service tool is generally used to separate inflowing carrier fluid from outflowing carrier fluid.

(0029) Uniquely, the present invention stages the pumping, such that the high apparent viscosity carrier fluid, with its associated relatively higher solids concentration, is pumped to the pack site to accomplish at least about the first 70 percent of the alpha wave deposition, more preferably from about 70 percent, and most preferably from about 90 percent, to about 100 percent thereof. The alpha wave deposition is measured from volumetric calculations based on measurements taken during the construction of the wellbore and from solids dune heights calculated using mathematical relationships based on equilibrium slurry velocity above the dune. Immediately thereafter, the second carrier fluid, i.e., the low apparent viscosity carrier fluid, with its associated relatively lower solids amount, is pumped to the pack site to complete the alpha wave deposition, if not already completed using the high apparent viscosity carrier fluid, and also to accomplish the beta wave deposition. The completion of the beta wave deposition is determined by the appearance of a sharp pressure increase indicated by pressure monitoring gauges on the pumping equipment. Such monitoring devices are well-known in the art. It is understood by those skilled in the art that the time period needed to accomplish each portion of the deposition is predictable based on modeling that takes into account the pump rate (flow velocity), annulus area, solids loading, bulk density of the solids, and characteristics of the fluid.

(0030) The result of this staged method of the present invention is preferably a solids-pack which exhibits superior uniformity and desirable density and permeability, with a relative absence of voids and undesirable porosity. Such pack preparation is preferably accomplished in a time that is significantly less than that needed to prepare equivalent diameter/length solids-packs using heretofore known solids-pack methods that lack, in particular, the present invention's novel staging and selection features. It is noted that the use of an organic solvent in the second carrier fluid (the low apparent viscosity carrier fluid) is particularly helpful in obtaining optimal performance via this invention. This is because these viscosity reducers rapidly "break" (reduce) the viscosity of the first carrier fluid (the high apparent viscosity fluid) upon contact. The result is that many or most of the possible detrimental effects that could potentially arise from use of the high apparent viscosity carrier fluid during the alpha wave of the deposition, such as void formation that could result in undesirably looser packing during that phase, are subsequently reduced or eliminated when the low apparent viscosity fluid is introduced. The inclusion of solvent thus helps to consolidate the alpha wave packing and enable rapid and comparably dense packing during the beta wave phase. (0031) The following examples are provided to further illustrate the present invention and are not meant to be, nor should they be construed as being, limitative in any way of its various embodiments.

EXAMPLES Example 1

(0032) About 510 gallons of 3% KCI brine are mixed at ambient temperature and pressure with about 10.25 gallons of a viscoelastic surfactant to yield a solution having an apparent viscosity of about 15 centipoise at 511 second^"1 as measured by a rotational, direct-indicating viscometer at ambient conditions. The viscoelastic surfactant is sold under the tradename of AMOMOX APA-T by Akzo Nobel, Inc.. This solution is designated as the high apparent viscosity carrier fluid.

(0033) To this high apparent viscosity carrier fluid is added about 3 ppga of 20/40 U.S. mesh gravel sold under the tradename BAKER LOW FINE by Baker Oil Tools, a division of Baker Hughes Incorporated. This gravel therefore constitutes approximately 26% by weight, based on total weight.

(0034) A second carrier fluid, designated the low apparent viscosity carrier fluid, is prepared by mixing, under ambient conditions, about 168 gallons of a 3% KCI brine with a density of 8.48 pound per gallon with about 5 gallons of ethylene glycol monobutyl ether. This fluid has a viscosity of about 1 centipoise at 511 second^"1 as measured under ambient conditions.

(0035) To this low apparent viscosity carrier fluid is added about 1 ppga of the BAKER LOW FINE gravel described hereinabove. This gravel therefore constitutes approximately 8.7% by weight, based on total weight of the low viscosity carrier fluid.

(0036) A simulated downhole horizontal gravel-pack of about 200 feet (61 meters) in length is prepared for the purpose of sand control around a sand exclusion device which has already been inserted into the simulated wellbore using methods and means known to those skilled in the art. The annulus area to be packed is known to be about 12 in² with a volume to be packed of about 122 gallons; the temperature at the gravel-pack site is ambient temperature; and the pressure is known to be about 14.7 psig. To prepare this gravel-pack, the high apparent viscosity carrier fluid is "infused" (that is, the gravel is added via a gravel infuser, which is a screw which turns and captures the gravel and progressively moves the gravel into a stream of liquid) with its 26% weight/weight gravel and pumped at a pump rate of about 3 barrels, or 126 gallons, per minute to the gravel-pack simulator. The pumping is continued for a period of about 3 minutes, which has been predetermined, via modeling based on the wellbore construction measurements of the simulated horizontal gravel pack model, to accomplish about 80 percent of the alpha wave deposition for the horizontal gravel-pack as described.

(0037) At the end of about 3 minutes, the low apparent viscosity carrier fluid, which has been placed in a second, separate tank, is infused with its 8.7% weight/weight gravel loading and is pumped at the same rate for about 2.5 minutes to the gravel-pack site. This has been predetermined to complete the remaining 20% of the alpha wave deposition. The pumping is then continued for about 3 more minutes until the beta wave deposition is also completed. The total pumping time is about 8.5 minutes. At the end of that time the carrier fluid pumping is stopped because the gravel-pack has been completed.

(0038) The result is a horizontal gravel-pack exhibiting good, uniform density.

Example 2

(0039) The materials and methods described in Example 1 are used to establish a horizontal gravel-pack of the same description, except that pumping of the high apparent viscosity carrier fluid with its associated gravel loading is continued to complete 100% of the alpha wave deposition, and the low apparent viscosity carrier fluid with its associated gravel loading is subsequently pumped to accomplish the beta wave deposition.

Comparative Example A

(0040) A horizontal gravel-pack as in Example 1 is prepared using the high apparent viscosity carrier fluid and same gravel loading as in Example 1 , but no low apparent viscosity carrier fluid or associated relatively lower gravel loading is employed. Pumping is done at the same rate until both alpha and beta waves of deposition are completed.

(0041) The result is a horizontal gravel-pack exhibiting voids and undesirable porosity. Total pumping time needed to complete both alpha wave and beta wave deposition is about 5 minutes. Comparative Example B

(0042) A horizontal gravel-pack as in Example 1 is prepared using the low apparent viscosity carrier fluid and same gravel loading as in Example 1 throughout both waves of the deposition cycle. No high apparent viscosity carrier fluid or associated gravel loading is employed. Pumping is done at the same rate.

(0043) The result is a horizontal gravel-pack exhibiting voids and inconsistencies in the packing density, in part due to the occurrence of bridging.

Comparative Example C

(0044) A horizontal gravel-pack as in Example 1 is prepared using fresh (i.e., tap) water and a gravel loading of 1 ppga weight/volume. Pumping is done at 3 barrels per minute until both alpha and beta waves of deposition are completed.

(0045) The result is a horizontal gravel-pack exhibiting good, uniform density. Total pumping time needed to complete both alpha and beta waves of deposition is about 12 minutes, which is 3.5 minutes longer than in Example 1.

(0046) In the foregoing specification, the invention has been described with reference to specific embodiments thereof, and has been demonstrated as effective in preparing a solids-pack for use in oilfield completion operations. However, it will be evident that various modifications and changes can be made to the steps and components used in the method without departing from the broader spirit or scope of the invention as set forth in the appended claims. Accordingly, the specification is to be regarded in an illustrative rather than a restrictive sense. For example, specific combinations of brines and viscoelastic surfactants falling within the claimed parameters, but not specifically identified or tried in particular compositions, are anticipated and expected to be within the scope of this invention.

Claims

WHAT IS CLAIMED IS:

1. A method of solids-packing non-vertical wellbores comprising pumping into the wellbore a high apparent viscosity carrier fluid containing a relatively higher amount of solids during at least the earlier portion of alpha wave deposition, then pumping into the wellbore a low apparent viscosity carrier fluid containing a relatively lower amount of solids during the later portion, if any, of the alpha wave deposition and during beta wave deposition, such that a solids-pack is formed.

2. The method of Claim 1 wherein the high apparent viscosity carrier fluid has an apparent viscosity of from about 5 to about 20 centipoise at 511 second^"1, as represented under downhole conditions.

3. The method of Claim 2 wherein the high apparent viscosity carrier fluid has an aappppaarreenntt vviissccoossiittyy ffrroomm aabboouutt 88 ttoo aabboouutt 15 centipoise at 511 second^"1, as represented under downhole conditions.

4. The method of Claim 1 wherein the low apparent viscosity carrier fluid has an apparent viscosity of from about 0.25 to less than about 5 centipoise at 511 second^"1, as represented under downhole conditions.

5. The method of Claim 1 wherein the relatively higher amount of solids is from about 3 to about 6 pounds per gallon added.

6. The method of Claim 5 wherein the relatively higher amount of solids is from about 3 to about 4 pounds per gallon added.

7. The method of Claim 1 wherein the relatively lower amount of solids is from about 0.1 to about 2.5 pounds per gallon added.

8. The method of Claim 1 wherein the high apparent viscosity carrier fluid comprises a brine, a viscoelastic surfactant, or both.

9. The method of Claim 8 wherein the high apparent viscosity carrier fluid comprises both a viscoelastic surfactant and a brine, and the viscoelastic surfactant is present in an amount from about 1 to about 6 percent by volume based on total volume.

10. The method of Claim 1 wherein the low apparent viscosity carrier fluid comprises a brine, a viscosity reducer, or both.

11. The method of Claim 10 wherein the low apparent viscosity carrier fluid comprises both a brine and a viscosity reducer, and the viscosity reducer is present in an amount from about 1 to about 20 percent by volume based on total volume.

12. The method of Claim 11 wherein the viscosity reducer is present in an amount from about 1 to about 10 percent by volume based on total volume.

13. The method of Claim 1 wherein the high apparent viscosity carrier fluid is used during about the earlier 70 to 100 percent of the alpha wave deposition, and the low apparent viscosity carrier fluid is used during about the later 0 to 30 percent of the alpha wave deposition and during beta wave deposition.

14. The method of Claim 13 wherein high apparent viscosity carrier fluid is used during about the earlier 90 to 100 percent of the alpha wave deposition, and the low apparent viscosity carrier fluid is used during about the later 0 to 10 percent of the alpha wave deposition and during beta wave deposition.

15. The method of Claim 1 wherein the solids pack is a gravel-pack -surrounding a sand exclusion device or a proppant pack in a reservoir fracture zone.

16. A method of solids-packing of non-vertical wellbores comprising pumping into the wellbore a high apparent viscosity carrier fluid, having an apparent viscosity of from about 5 to about 20 centipoise at 511 second^"1, the high apparent viscosity carrier fluid containing a relatively higher amount of solids, during at least the earlier portion of alpha wave deposition; then pumping into the wellbore a low apparent viscosity carrier fluid, having an apparent viscosity of from about 0.25 to less than about 5 centipoise at 511 second^"1, the low apparent viscosity carrier fluid containing a relatively lower amount of solids, during the later portion, if any, of the alpha wave deposition and during beta wave deposition; both apparent viscosities as represented under downhole conditions; such that a solids-pack is formed.

17. The method of Claim 16 wherein the high apparent viscosity carrier fluid contains from about 3 to about 6 pounds per gallon added of solids, and the low apparent viscosity carrier fluid contains from about 0.1 to about 2.5 pounds per gallon added of solids.

18. The method of Claim 17 wherein the high apparent viscosity carrier fluid includes a brine, a viscoelastic surfactant, or both, and the low apparent viscosity carrier fluid includes a brine, a viscosity reducer, or both.

19. A method of solids-packing of non-vertical wellbores comprising pumping into the wellbore a high apparent viscosity carrier fluid, having an apparent viscosity of from about 5 to about 20 centipoise at 511 second^"1, the high apparent viscosity carrier fluid containing from about 3 to about 6 pounds per gallon added of solids, during at least the earlier portion of alpha wave deposition; then pumping into the wellbore a low apparent viscosity carrier fluid, having an apparent viscosity of from about 0.25 to less than about 5 centipoise at 511 second^'1, the low apparent viscosity carrier fluid containing from about 0.1 to about 2.5 pounds per gallon added of solids, during the later portion, if any, of the alpha wave deposition and during beta wave deposition; both apparent viscosities as represented under downhole conditions; such that a solids-pack is formed.

20. The method of Claim 19 wherein the high apparent viscosity carrier fluid comprises a brine, a viscoelastic surfactant, or both, and the low apparent viscosity carrier fluid comprises a brine, a viscosity reducer, or both.