Abdus Satter, Ghulam M. Iqbal, in, 2016 Multistage hydraulic fracturingHydraulic fracturing design is based on sophisticated 3D modeling that takes into account the depth, thickness, lithology, fracture stress, and other properties of formation, among others. Models allow an optimized design of fracturing operation where the height, length, and orientation of the fractures can be most effective as well as economic. For example, horizontal well EUR was plotted against well lateral orientation in a study concerning Barnett shale development 8.

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A minimum of EUR could be identified for well laterals oriented at northeast 55˚ azimuth. This was the direction of principal horizontal stress and the fractures readily propagated along the above direction. Horizontal wells are drilled transverse to the direction of fracture orientation for maximum performance.Hydraulic fracturing is accomplished by injecting the fracturing fluid under very high pressure and at a predetermined rate that would prop open fractures in the ultratight shale and facilitate flow of gas.

The fracturing fluid is mostly water, about 98%. Sand is added to the fluid, which acts as proppant to keep the fractures open. Lubricants are added to facilitate the transport of various additives; hence, the fracturing fluid is referred to as slick water.

A small amount of chemical additives is also added. The chemical agents reduce friction; hence, the injected water is referred to as slick water. Furthermore, certain other chemicals are added to prevent the growth of microorganisms and clogging of fractures, and minimize corrosion. Typical constituents of hydraulic fracturing fluids are as follows 9:.Water: The major component injected into the formation to create, propagate, and enhance fractures.

The amount of water needed for each stage in the fracturing operation is quite substantial and water requirements for multistage fracturing can easily exceed a few million gallons.Sand: Used as proppant to keep the new fractures open and conductive in order to maintain the flow of gas. Three to five million pounds of proppants are required in each hydraulic fracturing operation.Resins: Resins are used to hold the proppants (sand and other materials) in place and prevent any loss.Ceramics: When a stronger proppant is needed to obtain the desired properties of fractures, ceramics can be used. Ceramics are lighter than sand and may be transport with relative ease.Gels: Used to transport proppants.Acids: Usually dilute hydrochloric acid is used to clean up perforations by removing the cementing materials.Biocides: Prevent bacteria from growing and fouling the wellbore.Potassium chloride: Prevents swelling of clay.Peroxydisulfates: Used as breakers to reduce the viscosity of gel and release proppant into the formation.Corrosion inhibitor: Acts to prevent any corrosion of metallic casing and tubing as acid is used. The length of the horizontal wells is usually long, 5,000–10,000 ft., where creating and maintaining high pressure by injecting fluid along the entire length is difficult.

Hence, a hydraulic fracturing operation is carried out in multiple stages by isolating small portions of horizontal wellbore at a time in order to maintain the requisite pressure along the entire length of the well. The spacing between stages can range from a few to several hundred feet along the lateral. A typical horizontal well several thousand feet long may have as many as 30–40 fracturing stages. Each stage consists of substages where predetermined quantities of water, sand, and chemicals are used.

Microseismic surveys can be conducted to determine the extent and orientation of the fractures created in the formation. A schematic of a horizontal well with multistage fracturing in a shale gas reservoir is presented in Figure 22.5. Boyun Guo Ph.D. Ali Ghalambor Ph.D., in, 2007 17.5.6 Production forecast and NPV AnalysesThe hydraulic fracturing design is finalized on the basis of production forecast and NPV analyses. The information of the selected fracture half-length x f and the calculated fracture width w, together with formation permeability (k) and fracture permeability ( k f), can be used to predict the dimensionless fracture conductivity F CD with Eq.

Hydraulic Fracturing Books Pdf

The equivalent skin factor S f can be estimated based on Fig. Then the productivity index of the fractured well can be calculated using Eq.

Production forecast can be performed using the method presented in Chapter 7. Another important concept in hydraulic fracturing design is the number of holes per stage. Designing the number of holes per stage in a conventional reservoir is completely different than in an unconventional shale reservoir. Limited entry is a term of art used in the industry and is referred to as the practice of limiting the number of perforations (holes) in a completion stage to help the development of perforation friction pressure during a frac stimulation treatment. The “choking” effect produces back pressure in the casing, which allows simultaneous entry of fracturing fluid into multiple zones of varying in situ stress states. Treatment distribution among zones can be controlled to a degree. Limited entry is known to increase perforation efficiency, and as a result, production in unconventional shale reservoirs ( Cramer, 1987).

Limited entry can be achieved using the following steps: 1.Determine the friction pressure of a single perforation for the limited entry design. A value of at least 200–300 psi is recommended since a value of this magnitude should be noticeable in the total surface-treating pressure.

2.Once the friction pressure is chosen, solve for rate per perforation to determine the rate per perf ( Q/ N). This new equation provides the rate per perforation needed to develop the friction pressure of a single perforation.

Yu-Shu Wu, in, 2016 12.2.1 Geomechanical EffectGeomechanics or rock deformation plays a critical role in multiphase flow during gas or oil production from unconventional reservoirs, because of the large variation in reservoir pressure during production and its impact on pore geometry. The scope spans from well stability, hydraulic fracturing design, to reservoir flow management. Stylus rmx sage converter lionel price. In conventional oil and gas reservoirs, the effect of geomechanics or rock deformation on permeability is generally small and has been mostly ignored in practice. However, in unconventional shale formations with nanosize pores or nanosize microfractures, such a geomechanical effect can be relatively large and may have a significant impact on both fracture and matrix permeability, which has to be considered in general in the analysis of production performance. (2009) showed that permeability in the Marcellus Shale is pressure dependent and decreases significantly with an increase in confining pressure (or total stress).

(12.5) P c = 2 σ cos θ rin which σ is the Inter-Facial Tension (IFT); r is the pore or pore-throat size; and θ is the contact angle. Because it is difficult to build the direct relationship between pore size and effective stress for varying pore size in porous media, the Leverett J-function approach ( Leverett, 1941) may be used to obtain the capillary pressure, based on measured capillary-pressure curves at reference condition, to correlate with saturation, and stress-dependent permeability and porosity. Tarek Ahmed, D. Nathan Meehan, in, 2012 7.5 Rate Acceleration InvestmentsAn acceleration investment may be defined as a supplementary investment made for the purpose of increasing the rate at which the income is received from a project already in place.

Typically in the minerals industry, this has involved the investment in some process to speed up the production of reserves for which a basic recovery capability is already available. The drilling of infill wells to accelerate the depletion of a reservoir being adequately drained by existing wells at a slower rate provides a good example. In reality, infill wells often lead to increased recoveries due to previously unseen reservoir heterogeneities, the ability to lower total reservoir pressure due to smaller drainage area, improved volumetric sweep efficiency, etc.The basic approach to evaluating a rate acceleration project is simply a comparison of alternatives.

The net present value of the rate acceleration case must be calculated and compared to the net present value if the base or unaccelerated case (i.e., continuing existing operations). If the NPV of the rate acceleration case exceeds the NPV of the base case, then the project is a candidate for consideration. DCFROI is generally not attractive for evaluating such projects for multiple reasons. In our initial tight gas spacing case, we compared a tight gas case on well spacings ranging from 40 to 640 acres in a homogeneous reservoir. We had several unrealistic assumptions including that all of the wells were being drilled simultaneously and put on production at the same time, that all hydraulic fractures were of identical length and conductivity, and (most importantly) that permeability was isotropic and homogeneous.

We also assumed that there were no rate limitations due to surface facilities or contract constraints. AssumptionsWell cost (prior), $2,950,000Well cost (optimized), $1,300,000Operating costs, $/well/month2000Royalty,%20Production taxes,%7.5Initial gas price, $/Mcf4.50Escalation rate,%4.0Maximum years for escalation20Discount methodMMPDiscount rate (annual%)10With these assumptions we can calculate monthly gas prices, operating costs, production, cash flows, and all other criteria needed for the evaluation. In the above table, the most glaring assumption is the drilling cost. In the discovery well, numerous cores, advanced logs, testing, and so forth raised drilling costs substantially. The lower cost is a “target” cost if many wells are drilled based on a combination of improved drilling performance, optimized casing designs, improved hydraulic fracturing designs, etc. Major reductions in well construction costs are almost always possible when many wells are drilled and suitable engineering analysis is applied. Comparison320–60–160Incremental NPV10$5,251,031$3,871,971$(230,042)Incremental NPV10 ratio$4.0$1.5$0.0While the 320-acre case on its own had a NPV10 ratio of more than 6.0, it still has a high degree of capital efficiency incrementally over the 640-acre case.

The 160-acre case generates a significant amount of additional NPV10; however, it comes at the cost of two additional wells and has only modest incremental capital efficiency. Even in sensitivities where the 80-acre case would generate greater NPV10 than the 160-acre case, the 80-acre case will have relatively low capital efficiency. Gas price sensitivity for tight gas spacing. 7.5.1 Present Value Ratio (PVR)While NPV fails to deliver a measure of capital efficiency, the Present Value Ratio index calculates a measure of investment efficiency that is very useful in ranking projects with significant capital investment. It is the ratio of the discounted (after-tax) net cash generated by a project to the discounted pre-tax cash outlays (or investment). Discounting for both measures is at the corporate discount rate. Note that the numerator is not revenue, but net cash generated.

Operating expenses would be subtracted from the revenue along with taxes, royalties, etc., and not discounted back as part of the investment. Some companies use a version of PVR that is one plus this definition and is analogous to a discounted version of NTIR. A project with a PVR of one is equivalent to a project with an after-tax (ATAX) PV equal to zero and a DCFROI equal to the discount rate.PVR has many of the advantages of NPV in that there is no confusion about corporate reinvestment rates, no multiple solutions, etc. In the examples with Projects A–D, the PVR always ranks the projects in a way that generates the greatest NPV “bang for the buck.” 7.5.2 Growth Rate-of-Return (GRR)PVR has the weakness that it does not have the same intrinsic feel of an interest rate as does DCFROI.

GRR is a measure that translates cash flows into an interest rate-like measure that will always rank projects the same way as PVR. To calculate GRR, all positive cash flows are compounded forward at the corporate discount rate to some time horizon, say t years in the future.

Cash flows past that date are discounted back to the point t. This calculates the total equivalent amount of cash generated (say B) at time t assuming all cash flows are reinvested at the corporate discount rate. The negative net cash flows (excluding operating costs, taxes, etc.) are discounted back to time zero to get an equivalent time zero investment I. If we were to put these I dollars in the bank, and they grew to B at time t, the interest rate required would be the GRR.

For ANEP compounding, the equation is. A perpetuity is a series of cash payments that continues indefinitely. While there are no real perpetuities, the theoretical value of a perpetuity can be useful in approximating the value of certain cash flow streams, including real estate and the terminal value of a going concern. The valuation of a perpetuity assumes either constant periodic payments at regular time intervals infinitely into the future or payments that increase or decrease with a given growth rate g. The value of the perpetuity is finite because payments received in the distant future are discounted to negligible present values.

The theoretical value of a perpetuity is.