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EP2469020A1 - Procédé de fracturation hydraulique afin de créer une structure de pack d'agent de soutènement en couche le long des bords de la fracture afin d'empêcher la formation de fins pouvant endommager la conductivité de la fracture - Google Patents

Procédé de fracturation hydraulique afin de créer une structure de pack d'agent de soutènement en couche le long des bords de la fracture afin d'empêcher la formation de fins pouvant endommager la conductivité de la fracture Download PDF

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EP2469020A1
EP2469020A1 EP10016022A EP10016022A EP2469020A1 EP 2469020 A1 EP2469020 A1 EP 2469020A1 EP 10016022 A EP10016022 A EP 10016022A EP 10016022 A EP10016022 A EP 10016022A EP 2469020 A1 EP2469020 A1 EP 2469020A1
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Prior art keywords
proppant
fracture
fine
fracturing
fine grained
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German (de)
English (en)
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Claude Vercaemer
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Priority to EP10016022A priority Critical patent/EP2469020A1/fr
Priority to PCT/IB2011/003115 priority patent/WO2012085646A1/fr
Publication of EP2469020A1 publication Critical patent/EP2469020A1/fr
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    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK 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
    • E21B43/25—Methods for stimulating production
    • E21B43/26—Methods for stimulating production by forming crevices or fractures
    • E21B43/267—Methods for stimulating production by forming crevices or fractures reinforcing fractures by propping

Definitions

  • This invention relates to a method of hydraulic fracturing specially designed to address challenging reservoir conditions such as but not limited to poorly consolidated reservoirs.
  • proppant embedment and formation fines invasion are notorious to dramatically reduce fracture conductivity and therefore impair the performance of the well.
  • problems typically encountered with shales, coal and other soft rocks reservoirs But formation fines invasion and migration are taking place in many different cases, not just in soft rocks and are experienced in a large proportion of fracturing treatments.
  • the said Glossary is constantly up-dated.
  • the operation mainly consists of
  • Conventional hydraulic fracturing treatments generally are pumped in several distinct stages.
  • a fluid is injected through a wellbore into a subterranean formation at high rates and pressures.
  • the fluid injection rate exceeds the filtration rate (also called the leak-off rate) into the formation, producing increasing hydraulic pressure.
  • the pressure exceeds a threshold value, the formation cracks and fractures.
  • the hydraulic fracture initiates and starts to propagate into the formation as injection of fluid continues.
  • proppant is mixed into the fluid, which is then called the fracture fluid, frac fluid, or fracturing fluid, and transported throughout the hydraulic fracture as it continues to grow.
  • the pad fluid and the fracture fluid may be the same or different.
  • the proppant is deposited in the fracture over the designed length, and mechanically prevents the fracture from closure after injection stops and the pressure is reduced.
  • the reservoir fluids flow into the fracture and filter through the permeable proppant pack to the wellbore.
  • the production of reservoir fluids depends upon a number of parameters, such as formation permeability, proppant pack permeability, hydraulic pressure in the formation, properties of the production fluid, the shape of the fracture, etc.
  • the proppant materials into the fracturing fluid often results in the crushing of some portion of the proppant material as it passes through the pumping and mixing equipment to enter the subterranean formation.
  • This fine crushed material may have a particle size ranging from slightly below the size of the original proppant material to less than 600 mesh on the U.S. Sieve Series.
  • some crushing of the proppant material may occur producing additional fines.
  • the subterranean formation may itself release fines from the face of the created fractures as a result of spalling, scouring of the formation wall which causes formation particulate to be mixed with the proppant and the like.
  • These fine formation materials also may range from formation grain size to less than 600 mesh.
  • the fines may comprise sand, shale or hydrocarbons such as coal fines from coal degasification operations and the like.
  • sand shale
  • hydrocarbons such as coal fines from coal degasification operations and the like.
  • the fines also can flow with any production from the well-bore to the surface.
  • minifrac The purpose of the minifrac is to provide the best possible information about the formation, prior to pumping the actual treatment.
  • the minifrac is designed to be as close as possible to the actual treatment, without pumping any significant volumes of proppant.
  • the minifrac should be pumped using the anticipated treatment fluid, at the anticipated rate. It should also be of sufficient volume to contact all the formations that the estimated main treatment design is anticipated to contact.
  • a well planned and executed minifrac can provide data on fracture geometry, rock mechanical properties and fluid leakoff - information that is vital to the success of the main treatment.
  • Filter cake is the denomination used to describe the accumulation of organic or inorganic material accumulating on the surface of a permeable media when subject to a pressurized fluid containing said material too large to penetrate the openings of the permeable media. In the case of reservoirs to be fractured this takes place in particular but not limited at the aperture of natural fractures crossed by the main hydraulic fracture created by the treatment.
  • This filter cake is the direct result of the leak-off process in which the material contained in the fracturing fluid cannot penetrate the permeable portion of the rock, is filtered out of the fluid and accumulates on parts of the faces of the fractures.
  • Well shut-ins occur very often over the life of a well and during many operations. In its simplest form it consists at closing the valve at the wellhead. No matter what the pressure at the bottom of the well is when the shut-in is initiated, this pressure will stabilize back to the pressure of the reservoir. If the permeability of the formation is low or very low, the time needed to get back the bottom-hole pressure back to the reservoir pressure can be very long.
  • the bottom-hole pressure is below the reservoir pressure and time to get it up back to the reservoir pressure can take many hours.
  • the bottom-hole pressure is higher than the reservoir pressure and the time it takes to get it back down to the reservoir pressure can also takes many hours.
  • valve at the well-head can be carefully open and some pressure released from the well-head. This is considered as part of a well shut-in operation.
  • This reverse flow lowers the pressure in the fracture at a faster rate and to a lower level than does merely shutting the well in and allowing fluid loss from the fracture to the formation to lower fracture pressure.
  • Reverse flow causes a higher rate of pressure change and thus creates a greater pressure differential between the formation and the fracture.
  • This pressure differential causes a higher rate of flow of the fracturing fluid across the fracture formation interface.
  • the higher differential pressure and flow rate generates correspondingly higher earth stresses on the fracture face and produces more spalls than does the shut in method described above.
  • the amount of earth stresses produced by the present invention is a direct function of the pressure differential between the matrix and the fracture.
  • a rapid drop in fracture pressure such as is accomplished by reverse flow, generates high earth stresses on the fracture face.
  • Dual fracturing consists of an initial "settle" fracturing treatment followed by a main treatment.
  • the settle-frac treatment features a low-viscosity fluid with high breaker loading and a proppant to create enough length and settled height. This treatment creates an artificial barrier that minimizes downward fracture growth and proppant convection.
  • Soft formations such as poorly consolidated or non consolidated sandstones, can be fractured and filled with proppant. However, as the fracture closes, the proppant becomes embedded or absorbed by the soft rock matrix.
  • TSO tip screenout
  • this bridge is created deliberately but at the tip of the fracture, ie. at its very end. And the proppant then accumulates behind the bridge at the tip of the fracture (Hence the name Tip Screen-out) and progressively completely fill the fracture.
  • This technique requires a good knowledge of the leak-off properties of the fracturing fluid. It is more delicate but allows for the creation of very wide, highly conductive fractures of great benefit in formations with good productivity.
  • Frrac faces or “Frac Walls” designate the faces of the hydraulic fracture created in the reservoir. Those faces are vertical in the most frequent case of a vertical hydraulic fracture. However one rarely creates fractures that are perfectly vertical. Most of the time they are slightly inclined relative to the verticality.
  • a fracturing operation has the objective of creating so called “fractures” into an oil reservoir when the natural permeability of the said reservoir is considered as too low to provide a sufficient flow of oil to the well-bore.
  • a chemical fluid or gel optionally loaded with a fine sand or a proppant, is pumped under heavy pressure into the "perforations" opened into the reservoir (see above section “Definitions") at such a pressure (applied from the surface) so as to literally “fracture” the rocks and propagating this hydraulic fracture into the reservoir as the pumping of the fracturing fluid continues at the top of the well.
  • a key objective of the operation is to fill the so-created "hydraulic fracture” with a "proppant pack” featuring a high “conductivity” that will keep the fracture open when the pumping is stopped and maintained a high fracture conductivity to let the fluids from the formation flow to the well-bore through the said pack.
  • “Fines” of different origins can impair the process. They can be present in the reservoir even before the treatment. They can be generated by the mechanical degradation of the fracture faces when the pumping is stopped and the reservoir pressure is applied against the fracture faces. Or they can come from a partial crushing of the proppant itself. These fines can be transported by the flow of reservoir fluids, oil, natural gas, water or any mix of, and migrate into the proppant pack where they will usually cause a reduction of its conductivity, sometimes in a spectacular fashion. Sometimes, successive fracturing operations have to be performed during the well life, so as to periodically restore the said conductivity.
  • the technical challenge is therefore to either eliminate or reduce the amount of the fines generated in the hydraulic fracturing process and/or to prevent these fines to reduce the conductivity of the proppant pack, not only just during the operation but for as long as possible during the life of the well.
  • Fines generated by the proppant Fines can be generated by the proppant itself. A high fracture closure stress may apply to the proppant a stress that is beyond its strength and some particles of proppant can break. To avoid this the industry is selecting the type of proppants to be used based on the closure stress to be expected during the life of the well. However even when the right proppant is selected one can still get some fines within the proppant pack resulting from the destruction of some proppant grains.
  • the tendency is to undersize the proppant pack to exclude the smallest formation grain sizes likely to be encountered.
  • the proppant pack designed as per this method has a low to very low conductivity and therefore the well has a productivity well below what is possible based on reservoir characteristics.
  • resin-coated proppants were initially developed to combat proppant flow-back which was one of the causes of poor fracture conductivity. But these resin-coated sands were also recognized for decreasing the amount of mobile fines produced by the crushing of the proppant when submitted to the fracture closure stresses and production cycling. However conventional resin-coated sands are not very effective in preventing fines invasion from the formation. Many types of resin coated materials were introduced over the years by a number of suppliers: different types of substrates: sand, ceramics, others. Different types of coatings: cured, curable or semi-cured based on a large variety of chemical compositions. Different structure of coatings: Single coat or multiple coats. Coatings applied in a plant or on-the-fly during the fracturing treatment.
  • Halliburton developed a hardenable resin that remains tacky after hardening, combining in doing so the flow back control and the control of fines within the pack ( US Patent 6,725,931 )
  • the same Applicant states that upon deposition of the coated material mixture in the formation the coating causes fine particulate adjacent the coated material to adhere upon contact with the coated material thereby creating agglomerates which bridge against other particles in the formation to prevent particulate flowback and fines migration.
  • the tackifying compound also may be introduced into the subterranean formation prior to or after introduction of the proppant particulate.
  • the coated material is said to be effective in inhibiting the flowback of fine particulate in a porous pack having a size ranging from about that of the proppant material to less than about 600 mesh in intimate admixture with the tackifying compound coated particulates.
  • Halliburton describes many types of chemical compounds providing surface tackiness. Any one can be used in our invention using the criteria defined by Halliburton.
  • the tackifying compound comprises a liquid or a solution of a compound capable of forming at least a partial coating upon the substrate material with which it is admixed prior to or subsequent to placement in the subterranean formation.
  • the tackifying compound may be a solid at ambient surface conditions and upon initial admixing with the particulate and after heating upon entry into the well-bore for introduction into the subterranean formation become a melted liquid which at least partially coats a portion of the particulate.
  • Compounds suitable for use as a tackifying compound comprise substantially any compound which when in liquid form or in a solvent solution will form a non-hardening coating, by themselves, upon the particulate and will increase the continuous critical resuspension velocity of the particulate when contacted by a stream of water as hereinafter described in Example I by in excess of about 30 percent over the particulate alone when present in a 0.5 percent by weight active material concentration.
  • the continuous critical resuspension velocity is increased by at least 40 percent over particulate alone and most preferably at least about 50 percent over particulate alone.
  • a particularly preferred group of tackifying compounds comprise polyamides which are liquids or in solvent solution at the temperature of the subterranean formation to be treated such that the polyamides are, by themselves, non-hardening when present on the particulates introduced into the subterranean formation.
  • a particularly preferred product is a condensation reaction product comprised of commercially available polyacids and a polyamine. Such commercial products include compounds such as mixtures of C36 dibasic acids containing some trimer and higher oligomers and also small amounts of monomer acids which are reacted with polyamines. Other polyacids include trimer acids, synthetic acids produced from fatty acids, maleic anhydride and acrylic acid and the like. Such acid compounds are available from companies such as Witco Corporation, Union Camp, Chemtall, and Emery Industries. The reaction products are available from, for example, Champion Technologies, Inc. and Witco Corporation.
  • the polyamides of the present invention are commercially produced in batchwise processing of polyacids predominately having two or more acid functionalities per molecule with a polyamine.
  • the polyacids and polyfunctional amines are introduced into a reactor where, with agitation, the mildly exothermic formation of the amide salt occurs. After mixing, heat is applied to promote endothermic dehydration and formation of the polymer melt by polycondensation. The water of reaction is condensed and removed leaving the polyamide.
  • the molecular weight and final properties of the polymer are controlled by choice and ratio of feedstock, heating rate, and judicious use of monofunctional acids and amines to terminate chain propagation.
  • an excess of polyamine is present to prevent runaway chain propagation. Unreacted amines can be removed by distillation, if desired. Often a solvent, such as an alcohol, is admixed with the final condensation reaction product to produce a liquid solution that can readily be handled.
  • the condensation reaction generally is accomplished at a temperature of from about 225 DEG F. to about 450 DEG F. under a nitrogen sweep to remove the condensed water from the reaction.
  • the polyamines can comprise, for example, ethylenediamine, diethylenetriamine, triethylene tetraamine, amino ethyl piperazine and the like.
  • the polyamides can be converted to quaternary compounds by reaction with methylene chloride, dimethyl sulfate, benzylchloride, diethyl sulfate and the like. Typically the quaternization reaction would be effected at a temperature of from about 100 DEG to about 200 DEG F. over a period of from about 4 to 6 hours.
  • the quaternization reaction may be employed to improve the chemical compatibility of the tackifying compound with the other chemicals utilized in the treatment fluids. Quaternization of the tackifying compound can reduce effects upon breakers in the fluids and reduce or minimize the buffer effects of the compounds when present in various fluids.
  • Additional compounds which may be utilized as tackifying compounds include liquids and solutions of, for example, polyesters, polycarbonates and polycarbamates, natural resins such as shellac and the like.
  • a tackifying compound can also be produced by the reaction of a polyacid such as previously described with a multivalent ion such as calcium, aluminum, iron or the like.
  • a polyacid such as previously described with a multivalent ion such as calcium, aluminum, iron or the like.
  • various polyorganophosphates, polyphosphonates, polysulfates, polycarboxylates, or polysilicates may be reacted with a multivalent ion to yield a tackifying compound.
  • esters of the above compounds may be utilized which will then react with the multivalent ion as the esters hydrolyze at the subterranean formation temperatures in the treatment fluids.
  • chelates may be formed with known chelating agents such as citric acid, hydroxypropionates and the like to retard the rate of reaction. Further, it has been found possible to generate the tackifying compound in-situ within the subterranean formation by introduction of the polyacid to contact multivalent ions present in the treatment fluid within the subterranean formation.
  • the multivalent ions may be either naturally occurring in the formation or introduced with the treatment fluid.
  • Suitable surfactants include: nonionics, such as, long chain carboxylic esters such as propylene glycol, sorbitol and polyoxyethylenated sorbitol esters, polyoxyethylenated alkylphenols, alkyphenol, ethoxylates, alkyglucosides, alkanolamine condensates and alkanolamides; anionics, such as, carboxylic acid salts, sulphonic acid salts, sulfuric ester salts and phosphonic and polyphosphoric acid esters; cationics, such as, long chain amines and their salts, quaternary ammonium salts, polyoxyethylenated long chain amines and quaternized polyoxyethylenated long chain amines; and zwitterion, such as n-alkylbetaines.
  • nonionics such as, long chain carboxylic esters such as propylene glycol, sorbitol and polyoxyeth
  • a new concept is described to overcome the problem of formation fines invasion into the proppant pack in hydraulic fracturing operations.
  • This new concept consists in creating over the volume of the fracture a layered proppant pack structure:
  • the layers in contact with the fracture faces (the "External layers”) have a particle size distribution (PSD) selected to prevent the damaging fines coming from the formation to invade the proppant pack.
  • PSD particle size distribution
  • the Internal Layer a layer of larger proppant is placed to provide the fracture conductivity that is needed and whose PSD is selected so that it cannot be invaded by the particulates of the external layers.
  • the very core of the invention is the technique used to create this layered structure which could never be achieved until now.
  • This process involves several steps.
  • a "fine grained proppant” (hereafter also called “fine proppant” for simplicity), preferably but not necessarily “tacky”, is placed in the fracture created by a conventional hydraulic fracturing technique. Then the well is temporarily shut-in, optionally with some carefully controlled flow back or reverse flow so as to increase the rate of closure of the fracture upon the said first fine proppant, for a time sufficient for the said first proppant to be encroached/embedded into the walls of the fracture.
  • This new concept is based on the creation of a layered proppant pack structure placed in the fracture with an innovative 2 steps fracturing process with intermediate shut-in and re-opening of the fracture.
  • the process can be described as follows:
  • the core of the invention is in the specific process to achieve the effective placement of these "External Layers" of the fine proppant and to maintain these layers in place during the sub-sequent steps of the operation and in particular while placing the "Internal Layer” of larger proppant so that these "external layers” can provide the to-date unknown function of "support” that is minimizing the destruction of the rock hence the amount of fines generated, screening out the fines and allowing the large proppant pack conductivity to be unaffected by any particulate material coming from the reservoir so as to preserve its high and effective level of conductivity for a long period of time.
  • the invention concerns a method of hydraulic fracturing oil and or gas wells in order to create a layered proppant pack structure alongside the faces of the fracture to prevent formation fines to damage the fracture conductivity over time characterized in that it comprises the process to place an external layer of fine grained proppant 5 against most of each of the surface of the fracture faces 2 AND in ensuring that the said layers remain in place during the subsequent steps of the process by a shut-in and optionally the previous use of a tacky agent.
  • the external layers (5) deposited on each of the faces of the fracture cover the said faces to the maximum extent attainable by the current fracturing technologies. That is, the said fine grained proppant is transported by the said frac gel or fluid (20) to the extremity of the fracture, or close to, since it is known that it is not believed to be absolutely certain to reach the said extremities.
  • the skilled man knows how to evaluate such things given the fine grained sized considered here, and the known frac fluid or gel, as well as usual consideration of viscosity, flowrate, pressure etc., which are routine to him, a skilled man is able to appreciate what "most” means. The inventor believes it can be as much as 80 to 90 % of the global surface of each face, with a transport deep into the fracture since it is a fine grained proppant.
  • the invention essentially differ from the prior art in that it involves the process to place the external layer of fine grained proppant against most of the surface of the fracture faces AND in ensuring that they remain in place during the sub-sequent steps of the process by a shut-in and optionally the use of a tacky agent, what is called here a "support" function.
  • Maintaining in place these 2 layers of fine grained proppant against the walls of the fracture during the placement of the large proppant can be significantly improved by the use of tacky materials as introduced by Halliburton. And this can be achieved in different ways.
  • the first option consists in pumping a "tacky" material as part of the fracturing fluid pumped in the first step but ahead of the fine grained proppant, ie in the pad volume of the first step fracturing operation.
  • This "tacky” compound or “tackiness-imparting compound” hereafter referred to as”tacky
  • This tacky material placed on the faces of the fracture will improve the adhesion of the fine grained proppant in particular during the shut-in operation and when the closure stress of the reservoir is fully active onto this material.
  • Another option consists in directly pumping the fine grained proppant whose particles have been treated on part of their surface by a tacky compound or pumping simultaneously untreated fine proppant particles and a tacky -product-containing fracturing fluid. That way, the fracture faces and some particles become tacky or partially tacky during the pumping which again should favor the immobilization of the fine grained proppant during the shut-in and sub-sequent operations.
  • the advantage of this option is that it can lead to the stabilization of several layers of fine particulate proppant. But it could be counter-productive to go too far in that direction.
  • tacky materials we use both mechanical and chemical mechanisms to ensure a good adhesion of the fine grained proppant against the faces of the fracture.
  • the type of proppant between sand, resin-coated sand or ceramic is mostly selected based on the confinement stress applied to the pack of proppant during production. Other important criteria are obviously the price and availability in the size desired. This selection is part of the overall hydraulic fracturing treatment design for which design and prediction software have been developed.
  • the particle sizes distributions of the proppants in the layers are selected as follows:
  • any criteria can be used if it is the belief of the operator that the ratio of the PSD to prevent invasion of fine particulate materials into a larger particulate material pack is appropriate.
  • the average PSD of the coarser proppants of the internal layer is selected using again the same ratio defined by Saucier: The average PSD of the coarser proppant of the internal layer must not be larger than 6 times the average PSD of the fine grained proppant of the external layers.
  • the "layered proppant pack structure" will be able to prevent the invasion in the internal layer of formation fines as small as 1/36th the average PSD of this layer. Formation fines smaller than that will be able to flow through the central layer without causing any damage.
  • the amount of fine grained proppant placed in the fracture will be such that after shut-in it will be able to form on the entire surface of each face of the fracture, a layer of fine grained proppant with a minimum thickness representing at least twice the average PSD of the fine proppant.
  • the thickness of the internal layer must be sufficient to provide the necessary conductivity. It should be at least 2 to 3 times the average particle size of the large proppant so that the pack can perform adequately.
  • the fine grained proppant for the external layers can be what the industry refers to as 100 mesh sand although it is in general a 50/140 mesh sand. In that case the proppant for the internal layer can be as large as a 12/20 sand and still meet the Saucier criteria. And obviously all the smaller most common proppant sizes such as 16/30, 20/40, 30/50, 40/70 can be used in conjunction with the 100 mesh fine grained proppant.
  • the largest possible PSD for the internal layer provides the highest conductivity in the proppant pack. However this may generate higher risk of premature screen-outs. And this determines also the smallest acceptable PSD for the fine material proppant.
  • Fracturing fluids selection is part of the common knowledge of the skilled man in the technique. Their composition and viscosity depend on the proppants they must properly carry into the fracture. As the proppant is lighter in density or smaller in size, the fracturing fluids can be less viscous down to what the industry refers to as "slick water” described in many publications and reference books. On the opposite, the transport of heavy, large proppant will require a very viscous cross-linked gel.
  • the present, inventive technique aims at minimizing the damage to the fracture conductivity over time once and for all.
  • the first step does not aim at producing commercial quantities of hydrocarbons.
  • the first step is specially designed to condition the faces of the fracture created in this step to optimize the performance of the second step of the fracturing treatment.
  • Operating conditions between the 2 steps are normally very different.
  • the first treatment aims at creating the fracture and placing a fine particulate material in it without necessarily creating a substantially conductive fracture. There is no need for high viscosity fluids in the said first step because sedimentation of fine particles is minimum. Hence no gel residue or very limited gel residue will remain in place.
  • the second step is the placement of the large, conductive proppant in the fracture that has already been created. There is no need any more for substantial amount of leak-off material. It has been put in place during the first step. Every variable is selected to maximize fracture conductivity as per the state of the art.
  • Pre-treatments to optimize actual fracturing treatments were introduced in the industry a long time ago. They were all, though, aiming at capturing data to optimize the design of the later fracturing treatment. They have become routine procedures in the industry under the names of "DataFrac”, “MiniFrac”, Diagnostic Fracture Injection Test (DFIT) or others. They are pre-treatments aiming at determining fracturing pressures, leak-off mechanisms and fluid-loss coefficients, spurt losses, closure pressures and generally all parameters useful in running fracturing models and optimizing fracturing operations. This is well described in US Patent 5,305,211 : Method for determining fluid-loss coefficient and spurt loss. It is also discussed in the first paper of the Conductivity Endurance brochure referred at the beginning of this memo: "Propping up production”.
  • pre-treatments are done some time ahead of the main fracturing treatment so that the acquired data can be fed into the fracturing software to optimize the desing of the treatment.
  • pre-treatment must not mislead the reader: they are not actual pre-treatments but rather “testing preliminary operations” absolutely NOT aimed at being part of the following treatment itself.
  • the 1 st step treatment described in this invention IS designed to place fine particulate material in the formation as an integral part of the global treatment of the invention.
  • This technique (described in the SPE paper 5643: Prepack technique using fine sand improves results of fracturing and fracture acidizing treatments by B.D. Miller and P.A. Warembourg) has become a very standard practice in hydraulic fracturing operations. It consists in pumping fine particulate material such as 100 mesh sand in a pre-pack stage ahead of the main stages of the fracturing treatments. It is one stage of a multiple stages single fracturing treatment. The pumping operation is not stopped between stages as the fracture needs to remain open for the pumping of the following stages. This technique is especially beneficial to combat fluid losses into natural fractures and high permeability zones of the formation. It is mostly a leak-off control technique.
  • This leak-off control material creates a "cake" opposite the most permeable parts of the fracture face and could later act as a filter.
  • the pumping of the main proppant laden fracturing fluid can easily and quickly displace this small concentration of fine particles and most of the benefit in terms of filtering out formation fines is usually lost.
  • the amount of leak-off material added to the early stage of the fracturing is determined by the amount of leak-off expected in the reservoir. Highly natural fractured reservoirs usually command higher concentrations of leak-off material. Its impact on the treatment is expected only during the pumping of the fluids, specially the proppant laden fluids to avoid early screen-out.
  • PCT/Patent application (USA, European and others) referenced below is particularly related to the present invention in the fact that the various stages of pumping aim at creating a specific structure within the proppant pack to maximize its conductivity as described in the summary below.
  • the invention provides economically effective methods for hydraulic fracturing a subterranean formation that ensure improvement of the hydraulic fracture conductivity because of forming strong proppant clusters uniformly placed in the fracture throughout its length.
  • One of these methods comprises: a first stage that involves injection into a borehole of fracturing fluid containing thickeners to create a fracture in the formation; and a second stage that involves periodic introduction of proppant into the injected fracturing fluid to supply the proppant into a created fracture, to form proppant clusters within the fracture to prevent fracture closure and channels for flowing formation fluids between the clusters, wherein the second stage or its sub-stages involve additional introduction of either a reinforcing or consolidation material or both, thus increasing the strength of the proppant clusters formed into the fracture fluid.
  • Another method comprises: a first stage that involves injection of said fracturing fluid into a borehole, and a second stage that involves introduction of proppant into the injected fracturing fluid and further, involving periodic introduction of an agent into the fracturing fluid to provide formation of proppant clusters in the created fracture and channels for flowing formation fluids.
  • Still another method comprises: a first stage that involves injection of a fracturing fluid into a borehole; a second stage that involves continuous introduction of a proppant into the injected fracturing fluid, and a third stage that involves injection of a lower-viscosity, in comparison with fracturing, fluid into the fracturing fluid, the lower-viscosity fluid, owing to the difference in viscosity compared to the fracturing fluid, penetrating into the fracturing fluid in the form of intrusions that divide the proppant into discrete clusters to form channels between them through which formation fluids to pass.
  • Re-fracturing operations consist in fracturing again a reservoir that has been fractured before and put in production until the level of production is much lower than what is expected from the reservoir. There are many reasons that can cause the hydraulically fractured reservoir not to perform as expected over time. The conditions of the first fracturing treatment may not have been adequate to start with. Or the conductivity of the fracture may have been impaired over time. Whatever the reason operators tend to re-fracture such wells, in the same interval in the hope to revive the well and get its production back to where it is supposed to be. Re-fracturing consists then in placing new proppants in the previously fractured wells to create a larger proppant pack . This can be done using exactly the same operating conditions as for the first fracturing.
  • the initial frac is designed to be final and not to be a formation conditioner in order to maximize the benefit of the second frac.
  • the proppant pumped in the second fracturing treatment may accumulate in different parts of the fracture but in an uncontrolled manner.
  • the re-fracturing approach consists in doing what is essentially conventional fracturing operations twice in the same interval of the same well. And sometimes more than twice since there are wells that are now repeatedly re-fractured on a regular basis.
  • This concept of layered proppant pack structure can be combined with any fracturing technique developed for conventional proppant placement such as but not limited to the use of encapsulated chemicals, coating chemicals, porous particles impregnated with chemicals etc...
  • a bore-hole casing designated as WB
  • WB a bore-hole casing
  • the bore-hole casing is a conventional bore-hole casing, such as, for example, a cement (CMT) sheathed, metal-lined C bore-hole casing that has been perforated to provide a number of perforations at preselected intervals of the reservoir of interest.
  • CMT cement
  • a fracturing gel or fluid (20) carrying a "large proppant" (30) is pumped through the perforations (1). Quite often, the fracture so opened intersects with naturally occurring transverse fractures TF.
  • the fracturing gel or fluid (20) is placed within the whole fracture volume transporting the proppant grains (30).
  • P is the pressure exerted by the surrounding matrix or formation M onto the faces F of the fracture.
  • Fig. 2 therefore shows the formation of additional fines during a standard, prior art fracturing operation.
  • Fig. 3 is also part of the prior art and represents the well when in production (production of oil id represented by the arrow). A migration of fines occurs. Those fines, mainly fines from the proppant (20) or from the crushed formation (40) have a tendency to plug the voids existing between the proppant grains (30) and therefore to reduce the "conductivity" of the proppant (30), that is to reduce the production of oil, down to production levels which can become quite insufficient.
  • Figs. 4 to 8 represent the process of the invention.
  • the formation is hydraulically fractured in accordance with the method of the present invention.
  • formation fines 10
  • these formation fines can be generated as a result of the mechanical interactions of the proppant with the formation under confinement stress.
  • these formation fines can be present in the formation from before the fracturing treatment and made mobile and movable as a result of the chemical interactions between the formation and the fracturing fluids.
  • Some of these fines can be forced mechanically to penetrate the fracture under the confinement stress. They can also be entrained by the formation fluid flowing into the fracture when the well is placed in production. In most cases both mechanisms are active and the fracture can be dramatically invaded during the fracturing or after the well is placed in production.
  • a fracture fluid containing a tackifying agent is injected through the well casing perforations into the formation or "matrix" M, as shown in FIG. 1 or 4 but with NO PROPPANT, at a pressure and pumping rate that will cause the formation to crack, creating what is referred to as hydraulic fractures.
  • a tackifying agent will cover the faces F of the fractures as they are created while the continuous pumping of the fracturing fluid propagates the fracture into the formation.
  • a small mesh particulate material such as 100 mesh sand, is mixed with the fracturing fluid, injected and placed in the fracture as the "fine grained proppant" (5).
  • the small particle size distribution of this particulate material facilitates its transport into the fracture which can be achieved with low viscosity fracturing fluids such as linear polymers solutions or even slick water.
  • the amount of fine material pumped during this step is such that at the end of this step the small particulate material is present over the full extent of the fracture in quantities that will allow this material to cover the entire surface of the fracture faces.
  • This fine particulate material is, in a preferred embodiment, partially covered with a tacky agent.
  • the covering with the tacky agent can be done before the pumping or during the pumping: the tacky agent and the fine particulate material are pumped together and during the transfer down-hole the tacky material adheres to the fine particulate material and covers from 20 to 80% of its total surface area.
  • Fig. 5 " SHUT-IN" stage
  • the pumping is stopped and the pressure within the fracture let decrease as a result of the filtration of the fracturing fluid into the formation.
  • the monitoring of the pressure at the wellhead versus time allows to determine the time when the fracture has closed over the small grain particle size material.
  • the well continues to be maintained closed after the fracture closure until the formation closure stress is applied to the particulate material. This is again monitored via the surface pressure at the wellhead, if this natural pressure decline process is too much time consuming, the well can be opened to let some fracturing fluids to be produced back at a production rate lower than 0.001 bpm per perforation to minimize the amount of fine particulate material produced back into the well-bore.
  • the opening of the well to permit some flowback can only be initiated once the fracture has closed on the fine particulate material as indicated by the record of the wellhead pressure versus time.
  • the formation closure stress when it is re-established at the end of the shut-in imposes a very strong interaction between the particulate material and the faces of the fracture first mechanically though embedment and then chemically because of the presence of the tacky material over the surface of the fracture walls, within the porosity of the formation area close to the fracture faces and on part of the surface of the fine particulate material.
  • a fracturing fluid without solid material is pumped so that the fracture can be re-opened without taking the risk of a screen-out (volume usually referred to the industry as the PAD volume).
  • a fracturing fluid with the larger conductive proppant (30) is placed into the fracture. Because of the larger average particle size distribution of this proppant (30) compared to the fine proppant (5) pumped in the first step a more viscous fracturing fluid is used, either a linear polymer gel of higher concentration or even a cross-linked polymer gel.
  • This larger proppant (30) typically a 20/40 mesh material --- is placed over the full extent of the fracture.
  • This large propping material can also be mixed with a tacky agent either before the pumping or during the pumping although this is not a preferred practice.
  • a cross-sectional end view of the reservoir fracture is shown in Fig. 6 and on the Fig. 7 showing the production.
  • a 20/40 mesh sand is used in the case described here but any size and type of proppant can be used as long as we maintain the right ratio of Average Particle size Distribution (Average PSD) .
  • Resin-coated materials can also be used either as a tail-in or for the entire volume of large proppant (30) to avoid proppant flow back during the production operations.
  • the well is closed to allow for the pressure in the fracture to decline in the same manner as it was done during shut-in, again with a well controlled flow-back to accelerate the pressure decline if necessary and apply the formation closure stress onto the larger proppant and from there onto the fine material that will be definitely immobilized as a layer between the fracture faces and the pack of larger proppant.
  • the 100 mesh particulate material layer (5) up against the fracture face and the 20/40 particulate material layer (30) will block formation fines (10) to invade the coarse proppant and maintain its conductivity over the life of the well.
  • Other sizes of both materials can be used as long as the correct ratio of average PSD (particle size) is maintained.
  • EXAMPLE 1 Small Treatment. Shallow formation. Tacky agent pumped in both phases of Step 1 but not afterward.
  • phase 1 of step 1 consists in pumping 2,000 gallons of 15% acetic acid to facilitate the penetration of the fluid into the formation and transmit the fluid pressure into the formation to initiate the creation of the fracture. Then 5,000 gallons of 20 lb/1000gal of HPG polymer solution containing 50lb/1000gal of a tacky material is injected into the reservoir; Then and without interrupting the pumping operation, 10.000 gallons of the same fracturing fluid mixed with concentrations of 100 mesh sand increasing from 2lb/gal up to 6 lb/gat mixed with 2% of active tacky material by weight of particulate material are pumped in order to place the fine particulate material over the full extent of the fracture. All fluids in this step 1 are pumped at a rate of 20 barrels per minute.
  • the fracture is re-opened and the coarse proppant placed into the fracture.
  • This is done by pumping in a first phase 5,000 gals of fracturing fluid containing 40lb/1000gal of HPG and then in the second phase but without interruption of the pumping 12,000 gallons of fracturing fluid containing 40lb/1000gal of HPG, 1lb/1000gal of cross-linker and concentrations of 20-40 mesh proppant increasing from 2lb/gal up to 8lb/gal for a total average concentration of 5lb/gal.
  • the cross-linker was eliminated and the pumping rate reduced to 5 barrels per minute.
  • the well is opened with the same precautions that were taken for the shut-in. First the well is maintained closed until the fracture closure is detected by monitoring the surface pressure at the wellhead. The well is maintained close for another 30 minutes and then the surface valve opened and reverse flow allowed at a controlled flow rate of 0.001 bpm per perforation to minimize proppant flow-back.
  • EXAMPLE 2 Large Treatment. Deeper formation. Tacky agent mostly pumped in phase 1 of step 1

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EP10016022A 2010-12-23 2010-12-23 Procédé de fracturation hydraulique afin de créer une structure de pack d'agent de soutènement en couche le long des bords de la fracture afin d'empêcher la formation de fins pouvant endommager la conductivité de la fracture Withdrawn EP2469020A1 (fr)

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PCT/IB2011/003115 WO2012085646A1 (fr) 2010-12-23 2011-12-22 Procédé de fracturation hydraulique afin de créer une structure de pack d'agent de soutènement stratifiée le long des faces de la fracture afin d'empêcher que des fines de la formation affectent la conductivité de la fracture

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WO2016014489A1 (fr) * 2014-07-25 2016-01-28 Schlumberger Canada Limited Prévention des pertes de fluide
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WO2016175765A1 (fr) * 2015-04-28 2016-11-03 Halliburton Energy Services, Inc. Formation de canaux arqués conducteurs dans des fractures de formation souterraine
US9862881B2 (en) 2015-05-13 2018-01-09 Preferred Technology, Llc Hydrophobic coating of particulates for enhanced well productivity
US10590337B2 (en) 2015-05-13 2020-03-17 Preferred Technology, Llc High performance proppants
US10280363B2 (en) 2015-07-07 2019-05-07 Halliburton Energy Services, Inc. Method of using low-strength proppant in high closure stress fractures
US11208591B2 (en) 2016-11-16 2021-12-28 Preferred Technology, Llc Hydrophobic coating of particulates for enhanced well productivity
US10696896B2 (en) 2016-11-28 2020-06-30 Prefferred Technology, Llc Durable coatings and uses thereof
US12330186B2 (en) 2017-11-02 2025-06-17 Preferred Technology, Llc Continuous mixers and methods of using the same
US11313214B2 (en) 2018-08-10 2022-04-26 Halliburton Energy Services, Inc. Creating high conductivity layers in propped formations
US11441406B2 (en) 2018-12-21 2022-09-13 Halliburton Energy Services, Inc. Forming frac packs in high permeability formations
US11143008B1 (en) 2020-04-24 2021-10-12 Saudi Arabian Oil Company Methods of hydraulic fracturing
WO2021216117A1 (fr) * 2020-04-24 2021-10-28 Saudi Arabian Oil Company Procédés de fracturation hydraulique
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