Figure 1. Schematic Diagram of (a) Fractured Vertical Well (b) Plan View in the X - Y Plane
The stimulation method that is currently most often employed around the world is hydraulic fracturing. The selection of an appropriate hydraulic fracturing technique is very important. Carbonates have the option of either acid or supported fracture treatment. In this paper, the key arguments for propped hydraulic fracturing being preferred in carbonate reservoirs will be covered in depth.
Technology for well stimulation has been beneficial in enhancing hydrocarbon recovery ( Veatch & Moschovidis, 1986). To prevent skin injury caused by being too close to a wellbore, a well-known method known as hydraulic fracturing (HF) was first used (Clark, 1949). HF includes proppant and acid fracturing (Ben-Naceur & Economides, 1988). The basic goal of both techniques is to induce a conductive fracture that will improve formation and production. There is no quantifiable approach to determining whether acid fracturing or proppant fracturing is the preferred method of stimulation for carbonate deposits. Applications for HF now include reservoir stimulation.
Well stimulation is an intervention performed on an oil or gas well to increase production by improving the flow of hydrocarbons from the reservoir into the well bore. It may be done using a well stimulator structure or using offshore ships or drilling vessels, also known as "well stimulation vessels." Well stimulation is a necessary intervention intended to enhance permeability and improve the flow of hydrocarbons from the reservoir to the wellbore. This significantly enhances productive well capacity, allowing a more timely return on investment. Reservoir stimulation is done by hydraulic fracturing of horizontal wells. Horizontal well stimulation usually involves creating multiple fractures along the wellbore using different well completion techniques. These multiple fractures generate large contact areas with the reservoir and also increase reservoir permeability.
More than 65% of the world's oil reserves are represented by carbonate reservoirs. Only about one-third of the world's original oil has been recovered using traditional methods; the remaining 891 billion barrels or more are estimated. They might thus be seen as promising options for meeting future energy needs. However, they require certain unique hydraulic fracturing procedures for carbonate reservoirs in order for the majority of the oil to be economically recovered (Wang et al., 2006). Low ultimate recovery is caused by the perception that carbonate rocks are more oil-wet than water-wet. Additionally, the fractures' existence alters the fluid dynamics in the medium and presents recent difficulties with the flow of fluid.
HF develops highly conductive routes from deep within the reservoir to the wellbore for wells conducted in lowpermeability carbonate formations, with the goal of enhancing well productivity by expanding the effective wellbore radius.
Veatch and Moschovidis (1986) provide an overview of some of these advances to give the reader a perspective on the current fracturing state of the art. The discussion addresses economic design considerations, fracturing material behavior (propping agents, fracture conductivity, fluid loss, fluid rheology, and proppant transport), field-acquired fracture design, and diagnostic and analysis technology.
Vega et al. (1997) mention reservoir fluids have asphaltene concentrations of 5 to 8%, with 200 ppm of H2S and 6 to 10% of CO2 . These characteristics of the reservoir and the reservoir fluids represent high-risk conditions that have required exercising extreme care in handling the large volumes of crude produced from some 150 active zones. As early as 1991, sand production and asphaltene depositions combined to cause severe well plugging in the Carito Field, making it necessary to start a cleaning programme using snubbing units to return production to well potential.
Wang et al. (2006) show that the effect of cross-linked acid fracturing is better than mini gel acid fracturing, and hydraulic fracturing is the best technique compared with the others. The new idea and methods for the carbonate reservoir stimulation were derived from the success of the three tests on the well. The well was an open-hole well that was drilled on August 11th , 2004 to a depth of 4925 meters in the Ordovician. The target zone was 4913.5 – 4935.00 m, and the reservoir temperature was 120 °C. The show was good in the target zone when drilling, and the well flowed 28936 m3 /d of gas and a little crude oil with 8.825 MPa of tubing pressure using a 6 mm choke without any stimulation.
Wedman et al. (1999) depict a fracturing technique for Sand Control (FSC) with a Resin-Coated Proppant (RCP) for proppant-flowback control that proved feasible in laboratory testing. The initial attempts at field implementation were an investment in learning that resulted in a large number of first-order failures resulting from proppant and formation flowback. With these early failures, these attempts were not commercially viable. Laboratory investigations and field tests revealed the source of the problems and led to design changes and improvements in the implementation procedure.
Li et al. (2009) analyze acid fracturing, a conventional and effective stimulation method that has been widely used in carbonate formation. However, due to significant acid leak-off and rapid acid/rock reaction speed, the effective length of acid etched fracture is always limited, even when high viscosity acid and emulsified acid are used; additionally, the effective duration of etched fracture is short, especially in deep wells, due to the high closure stress acting on the fracture wall where the rock is significantly softened after contact with acid. Propped fracturing, on the other hand, can result in a longer conductive fracture.
The most productive and long-lasting processes in carbonate reserves are fracturing and acidizing. Fracturing is the best of the therapies currently in use. Due to a number of benefits, propped Hydraulic Fracturing (HF) is a more effective method in carbonate reservoirs (Zoveidavianpoor et al., 2011). The best matrix substitute has been found to be HF (Kudapa et al., 2017b). HF really turns into a common stimulation technique and demonstrates its capacity to sustain the conductivity of fractures in carbonate reservoirs (Fredd et al., 2000). Increasing the fracture that is produced in acid fracturing treatments is typically the goal since conductivity is thought to have a direct connection to the rate of rock disintegration (Roberts & Guin, 1975). Furthermore, proppant fracturing appears to give far better stability than acid treatments.
Properly applied HF was more expensive than acid jobs, but it provided more predictability of eventual recovery and higher rates of return. As Navarre (1998) point out, increasing the quantity of dissolved rock does not achieve this goal. Because of its elongated fracture length and long-term effective conductivity, HF is thought to meet the requirements of a reservoir.
Two well-known forms of HF are proppant and acid fracturing. The basic goal of both techniques is to develop a conductive fracture that will increase well formation and production. There is no quantifiable way to determine whether acid fracturing or proppant fracturing is the preferred stimulation technique for carbonate deposits. The benefits of propped fracturing compared to acid fracturing in carbonate formations are therefore reviewed here because of the substantial acid leak-off and the quick acid/rock interaction velocity, and acid fracturing has been extensively utilised in carbonate formations. Regardless of whether emulsified acid or high viscosity acid is used, the length of an efficient acid-etched crack is always limited. Additionally, etched fractures have a short effective life, particularly in deep wells (Cook & Brekke, 2002).
According to some studies, acid fracturing's effective penetration was insufficient to satisfy the tight gas reservoir's stimulation needs (Vega et al., 1997). Longer acid contact times with the formation provide more etched surfaces and higher fracture conductivities, but they also reduce the formation's compressive strength. Furthermore, when the amount of dissolved rock increases, fracture conductivity does not increase. Propped fracturing, on the other hand, can extend the area of drainage to some extent due to its deep penetration capabilities.
It was hypothesized that the acidic fracturing length is lower than propped fracture length under the high reservoir temperatures, and the quick acid reaction in the formations has large amounts of calcite. Due to the distinct fracture mechanics involved in both procedures, fracture lengths in acid fracturing and proppant fracturing might differ. The fracturing gel in proppant fracturing is not reactive with the formation and hence can penetrate deeper for a given fracturing fluid volume than acid fracturing, especially at high reservoir temperatures (Dora et al., 2022). As a result, proppant fracturing is expected to produce longer cracks than acid fracturing. Proppant hydraulic fracturing has been shown to be an effective stimulation method for increasing output in sandstone reservoirs (Daneshy, 2010). In some regions, this approach has been used for carbonate reserves. Propped fracturing was introduced in several carbonate fields due to its importance in sustaining fracture conductivity and the ability to penetrate deeper and for longer periods of time of fracture using proppant.
Proppant fracturing is conducted by proppant the crack to minimize the impact of the minimal horizontal stress from closing. When acid fracturing is completed, the etched, non-smooth layer with suitable roughness should leave open channels. The amount of the minimal horizontal stress (fracture closure stress) is crucial in the stimulation type selection. It was suggested that proppant fracturing is the top stimulation approach for reservoir with such a minimum horizontal stress greater than 5,000 psi since etching generated by fracture acidizing is unable to support such high stress.
Hydraulic fracturing is a stimulation technique used to extract trapped hydrocarbons. When implementing the Fracpac applications, vertical wells were fractured for a variety of reservoir conditions ranging from tight gas formations to high permeability formations (Kudapa et al., 2017a). Horizontal wells were first fractured in the late 1980s to stimulate tight gas formations (Rückheim et al., 2005).The use of horizontal fracturing wells proved to be a critical technology in the development of unconventional reservoirs. With the development of the Barnett shale in the late 1990s, the technique was widely used.
Hydraulic fracturing is the key method used in shale gas production. It involves injections of highly pressurized water that contains chemical additives or another medium (e.g., carbon dioxide) or proppant. Hydraulic fracturing procedures are performed in vertical or horizontal sections of boreholes. A number of pumps and huge amounts of equipment and fracturing fluids are required at the drill site to produce a pressure surge that is high enough to break the rock. Hydraulic fracturing involves the injection of fracturing fluid into a sealed section of the borehole with perforated casing. The rock breaks, and the fracture begins to propagate in the gas bearing shale as pressure increases beyond the minimum stress tangential to the wellbore wall.
The hydraulically induced fracture always propagates in a direction that is approximately parallel to the maximum horizontal stress axis, at fracture pressures higher than the minimum contemporary stress. Proppant is injected with fracturing fluid into the network of induced fractures so as to prevent fracture closure while pressure drops on completion of the operation.
While the existence of natural fractures in shale oil and gas plays makes them good candidates for hydraulic fracturing, the key to a successful treatment is creating a complex network that connects newly created hydraulic fractures with pre-existing natural fractures (Agarwal & Kudapa, 2022a). This network of fractures, which consists of hydraulic fractures and primary and secondary natural fractures, is highly desired in low-permeability reservoirs where higher conductive connectivity can be achieved as opposed to connectivity created by planar fractures. Numerical simulations (Mayrhofer et al., 2008; Nagel et al., 2011; Warpinski et al., 2009; Cipolla et al., 2009) show that creating an interconnected network of fractures in nano-permeable reservoirs is a major factor in economic production.
Various methods have been applied to create this complex network and ultimately maximize the total Stimulated Reservoir Volume (SRV). Secondary fracture formation is critical for increasing reservoir contact. Secondary fractures can be created by multistage fracturing along a horizontal wellbore in a naturally fractured reservoir (Agarwal & Kudapa, 2022b). Different design parameters, including the number of perforation clusters per stage, the spacing between stages, the length of the horizontal well, the sequence of fracturing operations, and the type and quantity of proppant, should be optimized to create secondary fractures and a complex network of fractures (Mayrhofer et al., 2010). Among these parameters, spacing between perforation clusters as well as fracturing stages play major roles in fracture propagation and geometry. As noted by Soliman et al. (2008), the spacing between fractures is limited by the stress perturbation caused by the opening of propped fractures. However, fracture designs can be optimized if the original stress anisotropy is known and the stress perturbation can be predicted. Figure 1(a) shows the schematic diagram of a fractured vertical well, whereas the plan view in the X–Y plane is depicted in Figure 1(b).
Hydraulic fracturing, or "fracking," is a drilling method used to extract petroleum (oil) or natural gas from deep in the earth.
Figure 1. Schematic Diagram of (a) Fractured Vertical Well (b) Plan View in the X - Y Plane
In the fracking process, cracks in and below the earth's surface are opened and widened by injecting water, chemicals, and sand at high pressure. It is only vertical and also has horizontal laterals. Fracking uses fracking fluid to further expand the pockets of shale to enable the extraction of more oil and natural gas resources, while drilling simply pulls from the oil and natural gas readily available in the reservoir.
In the case of possible hazard areas, there must be consideration of the pressure zones as well as the groundwater areas.
The primary objective of a perforating gun is to provide effective flow communication between a cased wellbore and a productive reservoir. To achieve this, the perforating gun "punches" a pattern of perforations through the casing and cement sheath and into the productive formation. Bullet guns, abrasives, water jets, and shaped charges are perforating methods used to initiate a hole from the wellbore through the casing and any cement sheath into the producing zone and also start a fracture operation in a rock formation.
The down-hole pump is a key component of the hydraulic pumping operation during an artificial gas lift from a wellbore. It basically helps lift the gas out of the well by imparting the required energy to move the fluid from the well bottom to the surface. Fracking fluid or frac fluid is a chemical mixture used in drilling operations to increase the quantity of hydrocarbons that can be extracted. The fluid prevents corrosion of the well. It also lubricates the extraction process and prevents clogs and bacterial growth, among other functions. The high-pressure fluid extends fractures.
Hydraulic fracturing produces fractures in the rock formation that stimulate the flow of natural gas or oil, increasing the volumes that can be recovered. Wells may be drilled vertically hundreds to thousands of feet below the land surface and may include horizontal or directional sections extending thousands of feet.
At enough depths, usually below 1000 m or 3000 ft., the minimum principal stress is horizontal; hence, the fracture faces have to be vertical. Horizontal (pancake) fractures will be built in shallow formations where the minimum principal stress is vertical.
The vertical stress v at a depth of H will be αv = ρH/144. The effective vertical stress will be given as Equation 1,
σ^' ν=σν-αР
(“P” is the pore pressure and α is the Biot's poroelastic constant, which for most hydrocarbon reservoir it is 0.7).
The vertical stress is converted horizontally through the Poisson (ν) relationship through Equation 2,
where, ν (the poisson's ratio is a measure of the poisson effect, the deformation (expansion or contraction) of a material in directions perpendicular to the specific direction of loading)
The absolute horizontal stress is given by Equation 3 as,
Horizontal stress is not uniform in all the directions in horizontal plane. Because of tectonic components, this stress (σ^'H) is the minimum horizontal stress due to tectonic components, whereas the maximum horizontal stress in situ stresses is given by Equation 4,
So, principal stresses acting on formations are α v, αH, min, and αH, max…ll Fracture propagation will be perpendicular to minimum stress. The magnitude of breakdown pressure is determined by the characteristics of the values and the respective differences of the principal stresses, the tensile stress, and the reservoir pressure.
As per Terzaghi, the breakdown pressure for a vertical well is given by the Equation 5,
where To is the tensile stress of the rock.
Figure 2 represents the strain effects in all 3 directions, namely the x, y, and z directions.
Figure 2. Represents the Strain Effects in all 3 Directions
A hydraulic fracture will move perpendicular to the minimum principal stress. For a vertical fracture, the minimum horizontal stress can be evaluated with the stated equation.
where,
σmin= the minimum horizontal stress,
ν = Poisson's ratio,
σ1 = overburden stress,
α= Biot's poroelastic constant,
pp = reservoir fluid pressure or pore pressure,
and σext= tectonic stress
When a rock formation fractures, cracks are created within the rock matrix, and fluid in the wellbore will be lost into the fractures. The pressure required to create a fracture is termed "fracture pressure." The maximum well pressure that does not fracture the formations is called the fracture pressure, and the formation fluid pressure is called the pore pressure. Therefore, pore pressure and fracture pressure are considered the most crucial parameters for drilling engineering planning and for launching new wells. The stress log permits identifying variations of horizontal stresses with depth and potential hydraulic fracture barriers measured in the well. Figure 3 depicts the pressure and depth that are acting on the fracture.
Figure 3. Pressure and Depth which is Acting on the Fracture
When a rock formation fractures, cracks are created within the rock matrix, and fluid in the wellbore will be lost into the fractures. The pressure required to create a fracture is termed "fracture pressure," and it is possible to hydraulically fracture a formation by applying pressure to the wellbore. When a rock formation fractures, cracks are created within the rock matrix, and fluid in the wellbore will be lost into the fractures. The pressure required to create a fracture is termed "fracture pressure." Formation of fracture pressure is an important parameter in hydraulic fracturing design and one of the parameters used to measure the maximum horizontal stress in a formation. Formation pressure is obtained during stress measurements conducted for hydraulic fracturing. Figure 4 shows the mechanisms causing excessive fracturing pressure.
Figure 4. Mechanism Causing Excessive Fracturing Pressure
Borehole instability is the undesirable condition of an open-hole interval that does not maintain its gauge size and shape and/or its structural integrity. Coal fines detached during coal steam gas production have a dramatic impact on the hydraulic conductivity of the main advective flow path (fractures and proppant packs). Thus, we tested various formulations to stabilize such detached fines to minimize formation damage. The procedure requires continuous updating of the mesh around the crack tip to take into account the evolving geometry. Hydraulic fracturing mechanisms in coal differ in many aspects, namely the blocking of fractures by coal chips. The bottom-hole pressure of hydraulic fracturing in ductile reservoirs is high, and the fracture propagation path is more tortuous. The fracture tip is passivated by plastic deformation, forming a wide and short hydraulic fracture. However, the size obtained in the laboratory is in the order of centimeters to decimeters.
In the hydraulic fracturing process, first a mini-fracture test is performed, followed by planning a fracture treatment design, and then preparing for a fracture treatment.
Then, perform a fracture treatment, and finally, evaluate a fracture treatment. The mini fracture test can enhance the plan and execution of a hydraulic fracturing treatment by considering these measures. Then proceed to the estimation of fracture gradient, fluid leak off, and fracture closure pressure. Finally, recognize high fracture pressures.
Hydraulic fracturing fluids and formation fluids are both compatible. Those fluids are efficient at suspending proppant and taking it deep into the fracture. It is capable, through its inherent viscosity, of developing the necessary fracture width to accept proppant. These fluids are efficient due to their low fluid loss. It is effortless to take out of the formation, which cleans it up. They have less friction, which makes pumping easier. The preparation of the fluid should be uncomplicated and easy to perform in the field. It should be steady so that it will keep its viscosity throughout the treatment. The fracturing fluid should be cost-effective.
Hydraulic fracturing is classified into three types: water based gel, linear gel fluid, and cross-linked gel fluid. Secondly, foam-based or energized fluids. The gases that come under it are N2 and CO2 . Thirdly, oil-based fluids, which are further classified into gelled oil, cross-linked oil, and oil in water emulsion, and finally, the acid-based gel was sub-classified into gelled acid, cross-linked acid, and foamed acid. The different types of fluid used in hydraulic fracturing with the base fluid, fluid type with each and every fluid's main composition is tabulated in Table 1.
Table 1. Different Types of Fluids used in Hydraulic Fracturing
Hydraulic fracturing, commonly known as "fracking," is the process of injecting water, sand, and/or chemicals into a well to break up underground bedrock and free up oil or gas reserves. Fracking is essential for the production of natural gas and oil from shale formations, and with advances in fracking technology, it is becoming easier and more accessible to access natural gas. It has brought substantial benefits to the nation in terms of lower energy prices, greater energy security, reduced air pollution, and fewer carbon emissions, although it's long run impact on carbon emissions is less clear. Fracking is a drilling method used to extract petroleum (oil) or natural gas from deep in the earth. In the fracking process, cracks in and below the earth's surface are opened and widened by injecting water, chemicals, and sand at high pressure.
Considering the nature of natural gas, it is colorless and highly flammable. It often appears in association with crude oil. Also, these might include gases like carbon dioxide, hydrogen, hydrogen sulfide, nitrogen, helium, and argon (Agarwal & Kudapa, 2022c). When it is bypassed near the wellbore, damage increases well production by varying the flow regime from radial to linear. It reduces sand production and gives access to the reservoir from the well bore. 95% of US and Canadian fractures are in tight-gas or unconventional resource wells (Rückheim et al., 2005). The effect of hydraulic fracture on flow regime Hydraulic fractures, when properly designed, can change the flow regime from radial to linear.
Generally speaking, most formulas consist of 0.5 to 2 percent chemical additives and 98 to 99 percent water and sand. Although there are hundreds of chemicals that may be used in hydraulic fracturing, the vast majority of jobs use a relatively small number of these chemicals. The base fluids (make-up fluids), are water and oil. The energizing gases are utilized to support fracturing fluid recovery. (CO2 or N2or both). The gelling agents, which are viscosifiers, are utilized to thicken fracturing fluids to enhance fluid efficiency with no proppant transport.
The cross-linkers are used to super-thicken fracturing fluids (100s to 1000s of centipoise). Friction reducers are used in slick water fracturing to reduce friction losses in the pipe while injecting fracturing fluids. The breakers are used to decrease the viscosity of fracturing fluids after the treatment to let fluids flow out more easily for Dsurfactants and non-emulsifiers. The non-emulsifiers block treatment fluids and reservoir liquids from emulsifying, the temporary clay control agents, halt clay swelling and minimize the migration of clay fines to 1-7%. The biocides destroy bacteria in the fluids that make up the wastewater. It is used to reduce reservoir souring caused by the injection of polluted surface water, as well as prevent bacteria in makeup water from spoiling gelling agents prior to the treatment being pumped.
Considering the polymer systems, they are classified into aqueous methanol-based fluids and non-aqueous methanol-based fluids. When it comes to the non polymer systems, the classifications are surfactant gels (VES), VES foams, N2 foams, hydrocarbon-based ones, and also the liquid CO2-based ones.
Sand pumped downhole is known as "proppant," which keeps fractures "propped" open. It comes in three major forms: untreated sand, resin-coated sand, and coated for strength in harsh conditions.
Artificial proppant is very strong at high pressures. It is said to be in short supply, so more people are turning to resin coated sand, which is chosen for its strength and size.
The embedment of the soft formation into the matrix is determined by the hardness of the coal. Enclosing a larger volume of fines by proppant leak the sand-bearing fluid into secondary fissures and cleats.
In carbonated reservoirs, Hydraulic Fracturing (HF) is seen as an appropriate choice for damage reduction and increased hydrocarbon recovery. These requirements for carbonate reserves were most recently reported (Zoveidavianpoor et al., 2011). The benefits of propped fractures over acid fractures in carbonate reservoirs are discussed in (Wedman et al., 1999). However, the potential for spontaneous fractures and the rock's hardness can make it difficult to fracture carbonate deposits (Li et al., 2009). The capacity of propped fracturing to link to a natural fracture or fissure is low as the fracturing fluid is not reactive with the formation, despite the fact that it can provide a longer fracture and a longer effective period.
While fracturing limestone formations, as opposed to sandstone, difficulties arise from high leak-off, such as opening a natural crack, and trouble producing a fracture because of the rock's hardness. There is no proppant used and acid fracturing is simpler. However, the inability to precisely manage the fracture length and conductivity makes the design process more challenging. The former is controlled by the chemical interaction of the rock and fracturing fluid, while the latter is controlled by the development of etching patterns by the reacting acid. In a depleted reservoir, the effect of increased effective stress should be investigated for the exact determination of the lowest horizontal stress in addition to fracture and matrix permeabilities. This is crucial as many wells in carbonate rocks are becoming dry because natural fracture systems have been harmed by scale or have simply stopped communicating with the wellbore naturally. The economic life of these wells should be extended by appropriate stimulation techniques and the ensuing opening of the natural cracks.
Proper hydraulic fracturing is a preferable kind of HF in carbonate reservoirs due to several benefits. The most significant disadvantage of propped fracturing is the high operational cost. Skin-bypass fractures are inexpensive, require little equipment, and are simple to perform. They are used all over the world, where factors like cost, deck area, deck loading, and crane size frequently preclude traditional HF from being used. Skin bypass fracturing is an effective alternative to matrix acidification. By performing the HF through skin bypass, this procedure will be a viable alternative to matrix acidizing and acid fracturing, especially in reservoirs with asphaltene precipitation and positive skin values.
The greatest option for enhancing oil recovery in carbonate reservoirs is hydraulic fracturing. Proper hydraulic fracturing is a more effective form of hydraulic fracturing in carbonate reservoirs compared to acid fracturing because of a number of benefits. The purpose of the hydraulic well stimulation is to enhance openings and increase the pathways for gas to flow. The well stimulation technique involves the high-pressure pumping of a fluid into the well to cause it to break below ground. The ultimate solution to fracking is to abandon the practice, become less dependent on fossil fuels, and increase investment in sustainable energy production. In the long term, we must divert investments and subsidies from fossil-fuel production into more sustainable energy sources.