Determining effect of oxidative hydraulic fracturing

Abstract

Estimating permeability enhancement of a subterranean formation due to presence of an oxidizer in a fracturing fluid, including determining kerogen volume percent in the subterranean formation and estimating fractured kerogen porosity, wherein the fractured kerogen porosity is associated with presence of the oxidizer. The technique includes determining an increase in connected porosity in the subterranean formation correlative with the kerogen vol % and the fractured kerogen porosity.

Description

TECHNICAL FIELD

This disclosure relates to oxidative hydraulic fracturing of unconventional formations.

BACKGROUND

Hydraulic fracturing employs fluid and material to generate fractures in a subterranean formation to stimulate production from oil and gas wells. Hydraulic fracturing is a well-stimulation technique in which rock is fractured by a pressurized fluid that may be a fracturing fluid. The process can involve the pressure injection of fracturing fluid into a wellbore to generate cracks in the deep-rock formations through which natural gas, petroleum, and brine will flow more freely. The hydraulic fracturing typically generates paths that increase the rate at which production fluids, such as crude oil or natural gas, can be produced from the reservoir formations. The amount of increased production may be related to the amount of fracturing. Proppant may be employed to maintain the fractures as pressure depletes in the well during hydrocarbon production. The proppant may resist formation closure stresses to keep fractures open.

SUMMARY

An aspect relates to a method of estimating enhancement of porosity and permeability of a subterranean formation due to presence of an oxidizer in a fracturing fluid. The method includes determining kerogen volume percent (vol %) in the subterranean formation and estimating fractured kerogen porosity, wherein the fractured kerogen porosity is associated with presence of the oxidizer. The method includes determining an increase in connected porosity in the subterranean formation correlative with the kerogen vol % and the fractured kerogen porosity.

Another aspect is a method of evaluating effect of hydraulic fracturing fluid having an oxidizer on a subterranean formation. The method includes determining porosity of the subterranean formation before hydraulic fracturing the subterranean formation with the hydraulic fracturing fluid comprising the oxidizer, determining percent of the porosity that is connected porosity, and determining an increase in the connected porosity correlative with kerogen vol % in the subterranean formation and fractured kerogen porosity due to the oxidizer.

Yet another aspect is a method of determining effect of oxidative hydraulic fracturing on a subterranean formation. The method includes determining porosity of the subterranean formation before the oxidative hydraulic fracturing, determining percent of the porosity that is connected porosity, determining kerogen volume percent (vol %) in the subterranean formation, and estimating, via imaging of a sample of the subterranean formation, fractured kerogen porosity caused by an oxidizer of a fracturing fluid.

The details of one or more implementations are set forth in the accompanying drawings and the description below. Other features and advantages will be apparent from the description and drawings, and from the claims.

BRIEF DESCRIPTION OF DRAWINGS

FIG. 1 is a diagram of a well having a wellbore formed in a subterranean formation having organic matter, such as kerogen.

FIG. 2 a diagram of the well of FIG. 1 after a hydraulic fracture is formed and with the well in production.

FIG. 3 is four images of Fontainebleau sandstone samples.

FIG. 4 is eight images of a Finney pack with decreasing porosity noted by the numerical value for porosity above each image.

FIG. 5 is a diagram of a section of rock (e.g., shale rock) of a subterranean formation subjected to hydraulic fracturing including oxidative treatment via an oxidizer.

FIG. 6 is a diagram of an example list of input parameters that may be utilized to calculate and determine effects (e.g., permeability enhancement) of an oxidizing fracturing fluid on an unconventional rock formation.

FIG. 7 is a plot of an example empirical relation of kerogen density with hydrogen index.

FIG. 8 is a plot of an example empirical relation of kerogen density with Tmax (° C.).

FIG. 9 is a diagram of a user-interface (e.g., input pane) for dataset retrieval.

FIG. 10 is a diagram of a user-interface (e.g., output pane) for presenting treatment effects as calculated or determined, such as based at least in part on the input parameters of FIG. 6.

FIG. 11 are two images of the same shale sample, and associated with Example 3.

FIG. 12 is an image of the shale sample of FIG. 11 but with a grid placed over the image.

FIG. 13 is a block flow diagram of evaluating treatment effects of oxidative hydraulic fracturing.

FIG. 14 is a diagram of a computer that implements techniques herein.

DETAILED DESCRIPTION

Some aspects of the present disclosure are directed to determining porosity and permeability enhancement of hydraulically-fractured unconventional formations, such as hydraulically-fractured kerogen-rich shales. The permeability enhancement may be characterized as the increase (difference or ratio) in permeability and can be related to increase in connected porosity. The disclosure relates to oxidative treatment of unconventional formations in hydraulic fracturing with oxidative treatment fluids (e.g., fracturing fluids having an oxidizer). The permeability enhancement (or increase in connected porosity) may be determined based on comparison of hydraulically fracturing the subterranean formation with a fracturing fluid having an oxidizer versus the subterranean formation not hydraulically fractured. It can be noted that the permeability enhancement from an oxidative hydraulic fracturing treatment is expected to be higher than the permeability enhancement from a non-oxidative hydraulic fracturing treatment.

Embodiments of the present techniques may estimate effect (e.g., enhancement of porosity and permeability) on a subterranean formation due to presence of an oxidizer in a fracturing fluid. The technique may include determining kerogen volume percent (vol %) in the subterranean formation and estimating fractured kerogen porosity associated with presence of the oxidizer. In implementations, an increase in connected porosity in the subterranean formation may be determined correlative with the kerogen vol % and the fractured kerogen porosity. As discussed below, the fractured kerogen porosity may be estimated via imaging. The kerogen vol % may be based on kerogen weight percent (wt %) in the subterranean formation and kerogen density of kerogen in the subterranean formation. In certain implementations, the kerogen wt % and the kerogen maturity may be estimated via pyrolysis testing. The kerogen density may be estimated based on the kerogen maturity. The fracturing fluid having the oxidizer may be utilized in hydraulic fracturing of the subterranean formation.

Hydraulic fracturing may allow for the recovery of crude oil and natural gas from unconventional formations that geologists once believed were impossible to produce. Unconventional source rocks may be fine-grained, organic-rich sedimentary deposits, such as shales and mud rocks. Although unconventional rock formations or reservoirs are porous composites, their very small pore sizes and low permeability make them relatively resistant to economical hydrocarbon flow. The low permeability of the shale reservoir means that oil and gas typically are not economically produced from the well geometry, but rather through hydraulically fractured and stimulated wells. Unconventional formations typically include organic material (e.g., kerogen) intertwined with the rock matrix and the pores. In some circumstances, high-yield unconventional formations may be characterized or labeled as a kerogen-rich shale (KRS). The organic components of the source shale may include the hydrocarbon-source material kerogen and kerogen-produced components bitumen and pyrobitumen. Kerogen is a solid organic matter in sedimentary rocks, and is a natural organic biopolymer of irregular structure. Kerogen can range in degree of saturation where the ratio of the aliphatic to aromatic content contributes to thermal maturity designations. Kerogen is insoluble in normal organic solvents because of its high molecular weight. Upon significant heating, kerogen may convert to liquid or gaseous hydrocarbons.

Unconventional source-rock formations may typically be known for their very low permeability and very low hydraulic conductivity. The permeability may be less than 1 millidarcy. Shale rock can be generally impermeable having nanodarcy permeability. Hydrocarbon production (crude oil and/or natural gas) from unconventional source rock formations has generally become economically viable, for example, through extended-reach horizontal drilling and the creative multistage hydraulic-fracturing operation. Unconventional source rock reservoirs may differ from conventional reservoirs due to the presence of the hydrocarbon-source material (kerogen and other abundant organic matter) in unconventional reservoirs. This irregular natural polymer often represents, for example, 8% to 15% by weight (or 16% to 30% by volume) of the sedimentary source-rock formation in an unconventional formation. The rock matrix of minerals may be interwoven and compacted together with the kerogen, bitumen, and other organic components that also have nanopore size that contribute immensely to the low permeability and the overall oil and gas flow. The kerogen and the other organic matter with elastomeric properties exposed after the hydraulic fracture operation on the fracture face are clearly masking any fluid flow and contributing to the very low permeability (see, e.g., FIG. 1) and the hydraulic conductivity of the fractured faces and handicapping the overall hydraulic fracture conductivity and well productivity. FIG. 1 is a schematic of hydraulic fracture extending from wellbore, where the fracturing fluid system encounters the ductile organic matter illustrated as spider webs.

FIG. 1 is well 100 having a wellbore 102 formed in a subterranean formation 104 having organic matter 106 (organic material), such as kerogen. The wellbore 102 is depicted as a circular cross section. The subterranean formation 104 is a geological formation in the Earth's crust and may be an unconventional source-rock formation having hydrocarbon. The subterranean formation 104 may be an organic-rich shale zone. The spider-web symbol represents the presence of the organic matter 106. In FIG. 1, a fracture 108 is being formed via injection of a fracturing fluid 110 (stimulation fluid) from the Earth's surface through the wellbore 102 into the subterranean formation 104. The fracturing fluid 110 may be injected at a specified flow rate (q₀). The flow rate (q₀) may be specified as a volumetric flow rate or mass flow rate. The fracturing fluid 110 may include proppant 112, such as sand or ceramic proppant. The fracture 108 may propagate perpendicular to a minimum principal stress 114 of the formation 104 and in a direction against a maximum principal stress 116 of the formation.

The schematic in FIG. 1 depicts the hydraulic fracture 108 extending from the wellbore 102. The fracturing fluid 110 system encounters the ductile organic matter 106 illustrated as spider webs. The presence of the organic matter 106 at the fracture face 118 may restrict the generation of permeable channels from the geological formation 104 into the fracture 108. Thus, the organic matter 106 may inhibit the subsequent production of hydrocarbon from the formation 104 into and through the fracture 108 to the wellbore 102 and Earth surface. The fracture face 118 may be an interface of the forming fracture 108 with the subterranean formation 104. The polymer-like organic material 106 may be intertwined within the organic material and with the rock. The organic material 106 affects fracturing (fracture) behavior and reduces resulting hydraulic conductivity.

The interwoven structure of organic matter and mineralogy seen in the offset image of the fracture face 118, which is a scanning electron microscope (SEM) image. The SEM image illustrates an example of what a fracturing fluid encounters at the fractured faces as the fracture tip and length extends into the source-rock formation (subterranean formation 104). The highly viscous polymer nature of the organic matter augments creep effects and proppant embedment, reducing the aperture of the induced hydraulic fracture. The SEM image shows that these organic macerals of kerogen and other organic components are much less porous that of the hosting mineral matrix, and can act as barriers to fluid flow from the stimulated formation 104 into the opened hydraulic fracture 108, thus limiting the source rock permeability and formation hydraulic conductivity while reducing the overall hydraulic fracture conductivity. These laboratory observations are a direct indication of what the field will encounter, in terms of permeability reduction and potential losses of the economic returns in the overall hydraulic fracturing operation.

FIG. 2 is a well 200 that is the well 100 of FIG. 1 after the hydraulic fracture 108 is formed and with the well 200 in production. FIG. 2 depicts the hydraulic fracture 108 extending from the wellbore 102. The fracture 108 has a length 202 and width 204. The fracturing fluid 110 (FIG. 1) that formed the fracture 108 was a fracturing fluid having an oxidizer that attacked the organic matter 106. Thus, the fracturing fluid 110 system caused organic matter 106 to crack open to generate permeable channels from the formation 104 into the fracture 108 and therefore provide for conductivity from the formation 104 through the fracture 108 to the wellbore 102. The well 200 as depicted is in production phase with produced hydrocarbon 206 flow from the geological formation 104 through the fracture 108 and wellbore 102 to the Earth surface. The flow rate of the produced hydrocarbon 206 may be labeled as Q₀ and may be a characterized as a volumetric flow rate or mass flow rate. Thus, FIG. 2 is a schematic of the hydraulic fracture 108 extending from wellbore 102, where the fracturing fluid 110 system caused the organic matter to crack open, creating brittle polymer with open channels and increased porosity, and thus giving increased formation 104 permeability. As indicated by FIG. 2, to address the challenges with the kerogen polymer and to improve the overall hydraulic fracturing conductivity, reactive (oxidizing) fluid additives are implemented in treatment fluid (e.g., hydraulic fracturing fluid 110) that can break down the polymeric structure, creating micro cracks in the organic matter encountered on the hydraulic fracture rock faces. In other words, kerogen and other organic matter (e.g., 16-30 volume percent of the formation 104) encountered at the fracture faces may become brittle and cracked with visible fractures (cracks) on the order of tens of microns (e.g., less than 100 microns) as noted under SEM imaging. These microfractures at the fracture faces 118, in turn, can generally lead to an increase in the porosity of the exposed formation 104 face and to enhanced permeability and fluid flow channels. This induced brittleness and cracking may reduce or minimize the potential for viscous kerogen creep and the masking of the overall matrix porosity and permeability. Again, FIG. 2 provides a schematic that shows an example of kerogen that has cracked open after exposure to the aqueous oxidizing conditions. SEM images of treated source shale samples indicate a range of effects. Whether the organic matter is rendered brittle and cracked or completely degraded (or nearly completely degraded), the hydrocarbon (e.g., gas and/or oil) stored in the source shale formation 104 may more readily find its way into the fractured width (w), thus largely increasing oil or gas production (Q₀ and Q-after) at the wellhead.

Again, the present techniques may be applicable to shale formations and other unconventional formations. A fracturing fluid having the aqueous oxidizer as an additive may be pressure pumped to hydraulically crack and propagate the fracture. The oxidizer in the fracturing fluid may include, for example, hydrogen peroxide, inorganic peroxide, bromate (e.g., sodium bromate), persulfate (e.g., ammonium persulfate), permanganate, chlorite, hypochlorite, chlorine dioxide, chlorate, perchlorate, iodate, periodate, perborate, or any combinations thereof. The organic matter on the fracture faces exposed to the oxidizer may become brittle and break open. The newly-formed channels in the organic matter generally increase the porosity across the surface of the exposed fracture face that, in turn, may contribute to an increase in fractured formation face permeability. The SEM image of the fracture face 118 in FIG. 2 (as compared to the SEM image of the fracture face 118 in FIG. 1 prior to treatment) illustrates the depth scale of the effects of the invasive oxidizer additive into the fracture face and the extent to which the organic matter becomes brittle and physically cracks open.

Embodiments may predict and estimate the effects on the porosity and the opened formation-face permeability that such an oxidizing fluid treatment has or will have and, ultimately, how those effects influence the success of the hydraulic fracturing operation and the fractured well productivity. For instance, in particular, embodiments may estimate and calculate the increase in porosity and the enhancement of the formation permeability associated with the treated fracture faces. To this end, embodiments may include a technique that combines a series of formation properties with the results of laboratory experiments in order to calculate the amount of porosity and particularly connected porosity that are generated by the oxidizer fluid treatment.

The in-situ temperature, and the oxidizer composition and concentration in the treatment (e.g., fracturing) fluid, may also be factors considered that affect the degree of the organic matter degradation and hence in-situ connected porosity increase and hydraulic conductivity formation enhancement. Increasing in-situ temperature and increasing oxidizer concentration generally increase the degree of the organic matter degradation and thus may increase in-situ connected porosity and hydraulic conductivity. Increasing temperature generally escalates the rate of organic matter degradation and, thus, for a given amount of time, a higher temperature may result in more degradation. The in-situ temperature may be approximately the wellbore temperature or the subterranean formation temperature at the hydraulic fracturing.

To determine or estimate increase in porosity and formation permeability enhancement associated with the treated fracture faces, the analysis may rely on images (e.g., SEM images of formation samples) and calculations. The fracture face porosity and changes in fracture face porosity may be determined through visual inspection of SEM images or other types of images. The physical-structural changes that occur to the organic matter as a result of oxidative treatment can be visually inspected by high-resolution microscope (e.g., SEM). See, for example, FIG. 11. Imaging or microscopy other than scanning electron microscopy may be employed. Example calculations and equations are discussed below.

The analysis employing images and calculations can be performed before, during, and after the oxidative fracturing treatment of the subterranean formation. The techniques (e.g., relying on images and calculations) can be performed before the oxidative fracturing treatment on the subterranean formation to predict (estimate) what will be the effects of the oxidative fracturing treatment, and also performed after the oxidative fracturing treatment of the subterranean formation to estimate the realized effects of the oxidative fracturing treatment after the treatment.

The analysis may be performed before the oxidative fracturing treatment in the field occurs to predict the effects of the oxidative fracturing treatment on the subterranean formation. Before oxidative treatment in the field, a shale sample(s) from the subterranean formation may be collected (e.g., via core sampling) and analyzed in the laboratory before and after oxidative treatment in the laboratory. Thus, effects of the oxidative treatment in the field on the subterranean formation may be predicted. Moreover, in general, the oxidative treatment may be performed in the laboratory on several representative shale samples (e.g., collected via core sampling before oxidative treatment is implemented in the field on given unconventional formations) to construct a database from which predictive capabilities are built. For example, results of analysis performed on a treated shale sample that had a particular pre-treatment kerogen maturity and kerogen weight percent (and volume percent) in the rock can be applied or correlated to other pre-treated shales of similar composition. This may facilitate that laboratory tests and analyses can be utilized as a predictive tool for an engineer designing a hydraulic fracturing job in the field. Thus, the analyses may be by analogy to predict the effects of a potential oxidative fracturing treatment. By imaging and analyzing samples collected before and after oxidative treatment in the field, conclusions regarding analogous samples from a pre-treated formation may be drawn with respect to an oxidative treatment. Analogous samples may be samples (prior to oxidative treatment) composed of similar kerogen maturity (e.g., which includes density and porosity) and total organic content.

As mentioned, the aforementioned analysis (e.g., involving images and calculations) may be performed contemporaneous with or after oxidative fracturing treatment of the subterranean formation. The imaging and calculations may be performed with respect to samples collected during or after the oxidative fracturing treatment. SEM images of the samples may be inspected to determine changes in fracture-face porosity of the hydraulic fractures due to the oxidative treatment.

In the analyses (before or after the oxidative fracturing treatment), a permeability model may be employed. Permeability models may be relations or correlations that associate permeability with porosity. Examples of such relations include the Kozeny-Carman relation, Hagen-Poiseuille capillary tube models, and so on. The Kozeny-Carman relation (or similar correlation) or a capillary tube model may be employed to capture the induced porosity in shale from images and estimate the increase in permeability that results. The induced porosity may be the increase in porosity (e.g., at the fracture face) caused by the oxidative fracturing treatment.

In the Kozeny-Carman relation, the absolute permeability of a porous granular material is related to the porosity and the grain size. As indicated by Equation (1) below, absolute permeability may be directly proportional to the square of the grain size and the cube of the porosity. The Kozeny-Carman relation may be considered or utilized in modeling the permeability enhancement observed in, for example, kerogen-rich shale. Permeability can be predicted consistently in certain implementations with varying the number and type of conduit radii. In this technique, the absolute permeability k may be related to porosity ϕ (e.g., connected porosity) and grain size d, as indicated by the Kozeny-Carman relation given as Equation (1):k˜d²ϕ³  (1)

FIG. 3 is four images of Fontainebleau sandstone samples in which the depicted circular diameter of the imaged sample is about 2.5 millimeters (mm). The scale bar is 0.5 mm. Fontainebleau sandstone is composed generally of relatively well-sorted quartz grains. Fontainebleau sandstone may be considered a natural porous medium because of its mineral composition (e.g., 0.995 weight-percent Quartz) and generally constant grain size in relatively large sample blocks. FIG. 3 depicting the four Fontainebleau sand samples with varying respective grain size between the samples illustrates decrease in porosity according to the Kozeny-Carman approach. The four images are image 300, image 302, image 304, and image 306. A corresponding numerical value (units of mm) for grain size is given above each image for the respective sample. The Fontainebleau sandstone sample of image 300 has a grain size of 0.250 mm. The Fontainebleau sandstone sample of image 302 has a grain size of 0.167 mm. The Fontainebleau sandstone sample of image 304 has a grain size of 0.109 mm. The Fontainebleau sandstone sample of image 306 has a grain size of 0.072 mm. In accordance with the Kozeny-Carman relation, as the grain size decreases from 0.25 mm in the first image 300 to 0.072 mm in the final image 306, the porosity also decreases.

FIG. 4 gives eight images of a Finney pack with decreasing porosity noted by the numerical value for porosity (unitless) above each image and with the sphere radius increasing from 1.00 mm (first image 400) to 1.45 mm (final image 402). FIG. 4 indicates an example with the Kozeny-Carman relation that demonstrates the decrease in permeability as a result of increasing grain size.

As mentioned, capillary tube models may be employed. For example, the permeability k after oxidative hydraulic fracturing treatment may be estimated utilizing a capillary tube model based on Hagen-Poisseuille's law for flow in a tube. In this model, the permeability k is related to the porosity ϕ (e.g., connected porosity) and the tube diameter δ as given in Equation (2) below.

$\begin{array}{cc}k=\frac{\varphi {\delta }^2}{96}& \left(2\right)\end{array}$

Applicability of this tube model expressed as Equation (2) is indicated in FIG. 5 where cracked organic matter on the fracture faces of the rock (e.g., shale) connect to or form flow channels within the rock. FIG. 5 is a schematic illustrating the flow channels that extend from the fracture faces into the depth of the rock.

FIG. 5 is a section 500 of rock 502 (e.g., shale rock) of a subterranean formation subjected to hydraulic fracturing including oxidative treatment via an oxidizer. The subterranean formation may be a shale formation having organic matter such as kerogen. The depicted section 502 extends into the formation from a hydraulic fracture having fracture faces 504. At the fracture faces 504, organic matter cracked or broke open due to the oxidative degradation may form flow channels 506 into the rock 502 into the depth of the subterranean formation. Each ‘X’ may represent a crack in the organic matter. The depth of these flow channels 506 may be related to the concentration of the oxidizer in the hydraulic fracturing fluid in the hydraulic fracturing treatment. The tubes or channels may extend through layers of kerogen macerals. Again, utilizing this Equation (2) model, the permeability k is related to the porosity ϕ and diameter δ of the flow tubes.

Given the pre-treatment permeability input k₀ and the pre-treatment connected porosity ϕ₀, the average tube diameter δ₀ before treatment can be estimated using Equation (3) below.

$\begin{array}{cc}{\delta }_0=\sqrt{\frac{96k}{\varphi }}& \left(3\right)\end{array}$

After oxidative hydraulic fracturing, the average diameter of the tubes in fractured kerogen increases to δ_k. The δ_k can be estimated by taking the average of the width and depth of the fractures created by oxidative treatment (oxidative hydraulic fracturing). These may be input parameters, as discussed below. For an assumption that the average diameter of the tubes in other portions of the rock after treatment remains as δ₀, the average diameter of all tubes after treatment can be calculated as in Equation (4), where v_k is kerogen volume fraction which is an input parameter.δ=v_kδ_k+(1−v_k)δ₀  (4)

The average connected porosity of the whole rock after oxidative treatment (oxidative hydraulic fracturing) given as ϕ may be calculated. The estimated permeability after treatment, according to Equation (2) above may be given by Equation (5) below. The permeability enhancement factor may be k/k₀, which is the ratio of the permeability after treatment to the permeability before treatment.

$\begin{array}{cc}\stackrel{\_}{k}=\frac{\stackrel{\_}{\varphi }{\stackrel{\_}{\delta }}^2}{96}& \left(5\right)\end{array}$

The effects of an oxidizing fracturing fluid on an unconventional rock formation may be determined. For instance, the changes in fracture face porosity may be determined through visual inspection of SEM images and estimating the resulting changes in fracture-face permeability. Some input parameters for these types of calculations may be determined from field logs while other input parameters may be determined by performing laboratory tests. Multiple input parameters may be combined to estimate the positive changes in porosity and permeability that may occur in an unconventional formation (e.g., unconventional shale formation) subjected to oxidative hydraulic fracturing. The fracturing fluid has an oxidizer to attack organic matter in the unconventional shale formation including at fracture faces.

FIG. 6 is an example list of input parameters that may be utilized to calculate and determine effects (e.g., permeability enhancement) of an oxidizing fracturing fluid on an unconventional rock formation. The organic matter in the formation including at fracture faces includes kerogen. In the illustrated embodiment, the example input parameters are listed in a dialog box that may be a user interface of a computing device to receive or calculate values of the input parameters. The input parameters may be calculated or determined and input before, during, or after the oxidative fracturing treatment of the formation. The numerical values given for the input parameters listed in the dialog box are not limiting and only given as examples. The calculations can be for water-based hydraulic fracturing fluids with the oxidizer aqueous additive. No leakoff into the formation may be assumed in implementations.

Kerogen parameters 600 as input parameters may include kerogen density of kerogen in the subterranean formation, kerogen weight percent (wt %) of the rock in the subterranean formation, and kerogen volume percent (vol %) of the rock in the subterranean formation. The kerogen density may be, for example, in kilograms per cubic meter (kg/m3). The kerogen density may be estimated based upon its maturity. The kerogen vol % may be determined by combining wt % with density. The kerogen vol % can be determined correlative with kerogen wt % with kerogen density. The vol % of kerogen relative to the entire shale matrix may be determined by joining wt % with the density. With the mass and dimensions of the kerogen-containing rock sample as known, then the wt % of kerogen can be converted to a mass: kerogen wt %×mass of kerogen-rich rock=mass of kerogen. Then, the mass is converted to vol % using the density: mass of kerogen/density of kerogen=volume of kerogen. The kerogen vol % may be the volume of kerogen/volume of kerogen-rich rock×100%=kerogen vol %.

The kerogen parameters 602 may be determined, for example, via standard lab methodology utilizing a crushed rock sample. Rock-Eval® pyrolysis may be employed to determine kerogen wt % and maturity. Rock-Eval® pyrolysis (or similar pyrolysis testing analysis) may be performed to determine the percent weight of organic matter (delineate the amount of each organic matter component) and the overall maturity of the rock sample. Rock samples may be cut and milled, for instance, with a Retsch™ Mixer Mill MM400 to obtain a powder. The powder, e.g., about 60 milligrams (mg), may be subjected to a programmed temperature where the organic matter thermally decomposes over time and the resulting by-products of this decomposition are measured via a flame ionization detector. During the pyrolysis analysis a maximum temperature (Tmax) of complete combustion is reached and a pyrogram is produced that records the hydrocarbon generative potential of the kerogen, both of which can be used to define the maturity. Elemental analysis can also be performed on kerogen samples to determine concentrations of hydrogen, carbon, oxygen, nitrogen and sulfur. Because kerogen loses more hydrogen than carbon as kerogen is transformed into hydrocarbons, monitoring the changes in hydrogen relative to the carbon may be considered an indication of maturity. See Example 1 in the Examples section below in which Rock-Eval® pyrolysis was performed on about 60 mg of an unconventional rock sample.

Once the maturity is determined, the density may be obtained via empirical relationships. For examples of such empirical relationships, see Okiongbo, K. S.; Aplin, A. C.; Larter, S. R., Changes in Type II Kerogen Density as a Function of Maturity: Evidence from the Kimmeridge Clay Formation, Energy & Fuels 2005 19 (6), 2495-2499. The density may be correlated to maturity through the hydrogen index (e.g., FIG. 7) or through Tmax (e.g., FIG. 8).

FIG. 7 is a plot of an example empirical relation of kerogen density (grams per cubic centimeter or g/cm3) with hydrogen index having units of milligrams hydrocarbon per grams of total organic content (mgHC/g TOC). The data points of kerogen density versus hydrogen index are depicted at triangles on the plot. FIG. 8 is a plot of an example empirical relation of kerogen density (g/cm3) with Tmax (° C.). The data points of kerogen density versus Tmax are depicted at triangles on the plot. Hydrogen index (HI) and Tmax (maximum temperature) are determined by Rock-Eval® pyrolysis where peaks S1, S2, S3, and S4 are obtained and quantified. The equation HI=S2 (mg/g)/% TOC×100 is applicable. Tmax is determined directly from Rock-Eval® pyrolysis, where the maximum temperature is obtained upon complete combustion of the sample.

Fracture dimension parameters 604 as input parameters may include fracture length and fracture height that may be input, for example, in meters (m). The values for fracture length and fracture height may be estimated, for example, based on fracture-dimension data from similar wells in the same reservoir field of the subterranean formation. The values for fracture length and fracture height may be estimated from hydraulic fracturing simulation software, such as Gohfer® software (available from Halliburton Corporation having headquarters in Houston, Tex., USA), FracPro software (available from Carbo Ceramics, Inc. having headquarters in Houston, Tex., USA), etc. The length, width, and height of fractures may be estimated on the basis of the volume of hydraulic fracturing fluid and proppant pumped, as well as assuming there is no leakoff into the formation in implementations.

The porosity input parameters 606 as input parameters may include total porosity and percent (%) connected porosity. The total porosity and % connected porosity as input parameters 606 may be variables before hydraulic fracturing. The rock porosity can be determined, for example, either from well log measurements or by laboratory methods. The values will generally vary from one rock formation to the next. Again, values for the porosity input parameters 606 may be obtained, for instance, from well logs or from analysis of collected formation samples via standard laboratory methodologies. Moreover, as total porosity is a ratio or dimensionless, the units may be porosity units (PU) or %. The % connected porosity is the percent of the total porosity that is connected porosity. Analyses to obtain porosity values of samples may include mercury intrusion porosimetry, gas injection prorosimetry, and high-resolution imaging and digital image processing. The porosity of the formation may be determined from a nuclear magnetic resonance (NMR) log taken of the well. NMR logging measures the hydrogen nuclei of the fluids (oil, gas, water) in the pore space of reservoir rocks. The log provides information about the sizes of the pores containing these fluids such that the volume (porosity) and distribution (permeability) of the rock pore space can be determined. Alternatively, there are standard laboratory techniques for determining porosity and connected porosity including mercury intrusion porosimetry, gas injection porosimetry, and high resolution imaging in conjunction with digital image processing.

An additive/kerogen ratio 608 may be an input parameter 600. The additive may be the oxidizer in the fracturing fluid. The additive/kerogen ratio 608 may be a mass or weight ratio, for example, in kilogram (kg) per kg. The “additive/kerogen ratio” or “oxidizer/kerogen ratio” may be the mass of oxidizer per the mass of kerogen degraded or decomposed by the oxidizer. The additive/kerogen ratio may be the mass of additive in the fracturing fluid divided by the mass of kerogen that the fracturing fluid contacts or decomposes.

The additive (oxidizer)/kerogen ratio may be obtained from or determined by laboratory methods, e.g., at respective temperatures. For instance, rock samples may be cut and milled, for example, with a Retsch™ Mixer Mill MM400 to obtain a powder. In this implementation, the soluble bitumen from the rock powders may then then extracted using dichloromethane and the remaining rock matrix composed of silicates, aluminosilicates and carbonates was then digested using a combination of hydrochloric acid (HCl) and hydrofluoric acid (HF) to isolate and recover the remaining insoluble kerogen. The recovered kerogen may then be segregated into a float (e.g., <1.8 g/cc) versus sink (e.g., >1.8 g/cc) fraction employing a density liquid separation technique utilizing, for instance, zinc bromide. This segregation may facilitate for the use of kerogen containing less pyrite (float) versus kerogen with higher amounts of pyrite (sink) to test the sensitivity of the kerogen to the oxidizing fluids. In a particular implementation, oxidizer (e.g., 0.26 M oxidizer) is dissolved in water (e.g., 25 mL of water) in a pressure tube (e.g., 120 mL glass pressure tube). Isolated kerogen (e.g., 0.10 g of isolated kerogen) is added to the solution, and the pressure tube is sealed. The mixture is heated to (e.g., 100-150° C.) (determined by the bottom hole static temperature of the well of interest) in an oil bath (e.g., for 20 hours), then cooled to room temperature. The solid residue is filtered, rinsed several times, dried in an oven (e.g., at 60° C.), and massed. The oxidizer mass is divided by the decomposed kerogen mass (0.1 g—residue mass) to determine the additive/kerogen mass ratio. See Example 2 in the Examples section below giving an example of determining an additive/kerogen mass ratio. Again, the “additive” may generally refer to the “oxidizer” employed in the hydraulic fracturing fluid.

The treated fracture-faces parameters 610 may include fracture face depth affected and fractured kerogen porosity. Laboratory methods at respective temperatures may be utilized to determine the parameters 610. For instance, a laboratory technique may include to cut and polish a shale sample, heat the sample in fluid with additive (oxidizer), remove sample from fluid and dry sample, perform high-resolution imaging on dried sample, and determine depth of fracture face affected and the increase in porosity. Rock specimens may be cut from the same core from which the kerogen and bitumen samples were recovered. Each sample may be polished to expose parallel bedding planes of the shale to facilitate that the tests made on isolated kerogen could be compared to tests made on kerogen in the rock. See Example 3 in the Examples section below.

In certain implementations, an assumption may be that there is no hydraulic-fracturing fluid leakoff that occurs in the formation. Values for the aforementioned input parameters listed in FIG. 6 may be, for example: kerogen density (1.18-1.25 g/cm3 during early phase of petroleum generation and increases to at least 1.35 g/cm3 at higher maturities), kerogen wt % (2-20 wt % and 6-12 wt %), kerogen vol % (4-40 vol % and 12-24 vol %), fracture face depth affected (μm to mm for water-based fracturing), fracture length (100 to 400 m), fracture height (10 to 50 m), formation or fracturing temperature (80-150° C.), and additive/kerogen ratio (1 to 1000 wt/wt). These example value ranges of input values may be based on our knowledge of kerogen-rich source rock formations where hydraulic fracturing is performed. For example, in order for the formation to be sufficiently hydrocarbon rich to warrant hydraulic fracturing, the kerogen levels may generally be at least 2% but more likely at least 6%. Some input values (e.g., kerogen weight % and total porosity) may be based on well logs or standard laboratory tests. As discussed, fracture length and height may be obtained from standard hydraulic fracturing modeling software. Expected input values (e.g., for fracture face depth affected, fractured kerogen porosity, and additive/kerogen ratio) may arise from specific laboratory results based on the workflow in embodiments of the present techniques. The temperature of the experiments may be dictated by the bottom hole static temperature of the well or other temperatures or factors.

FIG. 9 is a user-interface (e.g., input pane) for dataset retrieval. The techniques may provide for sets of input parameter values to be stored in a database for later retrieval. A database look-up can be performed by specifying the field name, well identifier, in-situ formation temperature, and kerogen maturity, as indicated in FIG. 9. In some implementations, pull-down menus may facility such specifying. Then, as the corresponding dataset is retrieved from the database, the stored input parameter values may be populated (e.g., automatically populated) in the input pane of the user interface. The input pane of FIG. 9 or similar interface as an implementation may provide for database look-up of stored input parameter values.

FIG. 10 is a user-interface (e.g., output pane) for presenting treatment effects as calculated or determined, such as based on the aforementioned input parameters. In implementations, these treatment effects affected by the additive/kerogen ratio. The additive/kerogen ratio can be relevant for determining treatment quantities to be implemented in the field. Again, in implementations, the additive/kerogen ratio is not directly utilized to calculate the treatment effects but instead to determine the treatment quantity.

After values of the input parameters are established and input (e.g., in FIG. 6), then calculations may be performed to determine the volume of porosity and % volume of porosity created by the oxidizer fluid additive treatment. The example specific values displayed in FIG. 10 are the output values associated with the input values shown in FIG. 6 for the input parameters. These treatment effects in FIG. 10 may include porosity-created variables 1000 and connected porosity-created variables 1002. In general, most or all treatment effects characterized may be outputs. The permeability increase or permeability enhancement may an output variable.

The porosity-created variables 1000 may include treatment effects of both bulk formation volume affected (e.g., cubic meters or m3) and void space created (e.g., m3). The porosity created may be calculated correlative with the bulk formation volume affected. Porosity created is the same as void space created. The bulk formation volume affected is the amount of the formation that was affected by the treatment. This is determined by multiplying the fracture length by the fracture height (surface area) times the “fracture face depth affected” times 2 (for the 2 fracture faces). The void space created may be determined by multiplying the “treated kerogen porosity” by the kerogen vol % times the bulk formation volume affected. The treated formation volume may be equal to the mathematical product of the fracture length·fracture height·fracture face depth·2. The “treated formation volume” is the same as “bulk formation volume affected.”

The connected porosity-created variables 1002 may include connected porosity before oxidative hydraulic fracturing (of the subterranean formation) and connected porosity after oxidative hydraulic fracturing. Again, oxidative hydraulic fracturing may be hydraulic fracturing of the subterranean formation with a fracturing fluid having an oxidizer. The connected porosity before oxidative hydraulic fracturing is not a treatment effect but is before treatment. The connected porosity before oxidative hydraulic fracturing may be equal to the mathematical product of % connected porosity (before oxidative hydraulic fracturing) multiplied by total porosity (before oxidative hydraulic fracturing). The connected porosity after oxidative hydraulic fracturing is a treatment effect and may be equal to the sum of the connected porosity before oxidative hydraulic fracturing plus the mathematical product of the fractured kerogen porosity multiplied by kerogen volume percent (vol %). Thus, the increase in connected porosity may be the fractured kerogen porosity multiplied by the kerogen vol % (in the rock). See Example 3 below in the Examples section, which is an example of evaluating treated fracture faces.

As discussed above, Rock-Eval® pyrolysis may be performed to interpret thermal maturity or other properties. Rock-Eval® pyrolysis was developed by Institut Français du Pétrole (IFP) (French Institute of Petroleum) based at Rueil-Malmaison, France. In such a pyrolysis analysis, a rock sample undergoes increasing temperature in an inert atmosphere where three peaks of released hydrocarbons can be measured. The first peak (S1) represents the volatilization of any previously generated hydrocarbons present in the rock, given that the rock has reached thermal maturity. The second peak (S2) indicates the thermal degradation of any remaining organic material into hydrocarbons. The final peak (S3) is any organic CO2 present in the rock. The temperature at which the S2 peak occurs may be an approximation of the thermal maturity of the rock. In addition to thermal maturation, pyrolysis peaks S1, S2, and S3 yield information about the type of organic material present in the rock. During the pyrolysis analysis, a maximum temperature (Tmax) of complete combustion may be reached and a pyrogram produced that records the hydrocarbon generative potential of the kerogen, both of which can be utilized to define the maturity.

Thus, the Rock-Eval® pyrolysis may be performed to interpret thermal maturity or other properties. Rock-Eval® pyrolysis as a pyrolysis technique may be pyrolysis that is the decomposition of organic matter by heating in the absence of oxygen. The pyrolysis may be employed to measure richness and maturity of potential source rocks. In a pyrolysis analysis, the organic content may be pyrolyzed in the absence of oxygen, then combusted. The amount of hydrocarbons and carbon dioxide released may be measured. In Rock-Eval® pyrolysis, a sample may be placed in a vessel and progressively heated (for example, to 550° C.) under an inert atmosphere. During the analysis, the hydrocarbons already present in the sample are volatized and the amount of these hydrocarbons measured and recorded as a peak known as S1. Next, the amount of hydrocarbons generated by pyrolysis of kerogen in the sample is recorded as an S2 peak. The amount of CO2 generated is recorded as the S3 peak. The amount of residual carbon is measured and recorded as S4. The percent total organic carbon (TOC) may be related to the S peaks.

Various water-based (aqueous) oxidative fracturing fluids may be employed. An oxidative fracturing fluid for hydraulic fracturing of subterranean formation is a fracturing fluid having an additive that is an oxidizer. Concentration of the oxidizer (e.g., less than 4 M) in that the oxidative fracturing fluid (e.g., an aqueous composition) may be specified based at least in part on an amount of organic matter or kerogen to degrade in the subterranean formation. The oxidative fracturing fluid having the oxidizer may be placed (pumped) through a wellbore into the subterranean formation to hydraulically fracture the subterranean formation and degrade the kerogen. The oxidizer in the fracturing fluid may include one or more oxidizers. The oxidizer may include hydrogen peroxide, an inorganic peroxide, a bromate, a persulfate, a permanganate, a hypochlorite, a chlorite, chlorine dioxide, a chlorate, an iodate, a perchlorate, a periodate, or a perborate, or any combinations thereof. The concentration of the oxidizer in the fracturing fluid may be less than 4 M, less than 2 M, or less than 1 M. The oxidative fracturing fluid may include produced water, flowback water, brackish water, Arab-D-brine, or seawater, or any combinations thereof. The oxidative fracturing fluid may include salt at less than 20 weight percent (wt %) in the aqueous composition. The salt may include, for example, potassium chloride, sodium chloride, lithium chloride, potassium bromide, sodium bromide, lithium bromide, ammonium chloride, ammonium bromide, ammonium iodide, calcium chloride, magnesium chloride, strontium chloride, calcium bromide, magnesium bromide, strontium bromide, calcium iodide, magnesium iodide, or strontium iodide, or any combinations thereof. The oxidative fracturing fluid for hydraulic fracturing may include an imidazolium, an imidazole, an ammonia, a pyrrolidinium, a pyrrolidine, pyridinium, a pyridine, a phosphonium, chloride, bromide, iodide, tetrafluoroborate, hexafluorophosphate, sulfonate, or proppant, or any combinations thereof. Other components are applicable. Other oxidative fracturing fluids may be employed. Discussion of hydraulic fracturing fluids having an oxidizer(s) for treating (degrading) organic matter or kerogen in the hydraulic fracturing of a subterranean formation may be found, for example, in U.S. Pat. No. 10,351,758, which is incorporated by reference herein in its entirety.

EXAMPLES

The Examples are not intended to limit the present techniques and are given only as examples. Example 1, Example 2, and Example 3 are presented.

Example 1

Example 1 is associated with the kerogen parameters 600 discussed above with respect to FIG. 6. Table 1 below gives results of Example 1 in which Rock-Eval® pyrolysis was performed on about 60 mg of an unconventional rock sample containing type II-S kerogen. The results of the test are shown in Table 1. The maturity was determined to be late oil based on the Tmax value and the hydrocarbon generative potential. The properties in Table 1 include are 51 (milligram per gram or mg/g), S2 (mg/g), S3 in (mg/g), (productivity index), Tmax (° C.), HI (hydrogen index), O1 (oxygen index), and H/C (hydrogen to carbon ratio), and maturity. S1, S2, and S3 are pyrolysis peaks. S1 is free hydrocarbons present in the sample before the analysis. S2 is the amount of hydrocarbons that formed during thermal pyrolysis of the sample (utilized to estimate the remaining hydrocarbon-generating potential of the sample). S3 is the CO2 yield during thermal breakdown of kerogen.

TABLE 1
Rock Eval pyrolysis parameters determined for a source rock sample
S1	S2	S3		Tmax	TOC
(mg/g)	(mg/g)	(mg/g)	PI	(° C.)	(wt %)	HI	OI	H/C	Maturity
0.74	5.92	0.51	0.11	465	10.93	54	10	0.612	Late

Example 2

Example 2 is associated with the additive/kerogen ratio 608 discussed above with respect to FIG. 6. Example 2 is an example of determining the additive (oxidizer)/kerogen weight (mass) ratio. In Example 2, 1.0 g NaBrO₃ was dissolved in 25 mL of water in a 120 mL glass pressure tube. Then, 0.10 g of isolated type II-S kerogen with late oil maturity was added to the solution, and the pressure tube was sealed. The mixture was heated to 150° C. in an oil bath for 20 hours, then cooled to room temperature. The solid residue was filtered, rinsed several times, dried in an oven at 60° C., and massed. The oxidizer mass is divided by the decomposed kerogen mass (0.1 g-0.0797 g) to determine the additive/kerogen mass ratio of 49 in Example 2.

Example 3

Example 3 is associated with the fracture-faces parameters 610 discussed above with respect to FIG. 6 and treatment effects discussed with respect to FIG. 10. Example 3 is an example of evaluating fracture faces treated with an oxidizer. In Example 3, shale rock specimens were cut from the same core from which the kerogen and bitumen samples were recovered. Each sample was polished to expose parallel bedding planes of the shale to facilitate that the tests made on isolated kerogen could be compared to tests made on kerogen in the rock. These source shale samples were mechanically polished with the Allied High Tech MultiPrep™ system (available from Allied high Tech Products Inc. having headquarters in Compton, Calif., USA) first using 600 and 1200 grit silicon carbide paper, and then with progressively finer diamond suspensions beginning at 3 microns (μm) and continuing until reaching 0.05 μm. The small polished source shale samples (<10 mm in each dimension) were imaged via SEM (e.g., SEM image 1100 in FIG. 11)). Specific organic matter features were identified, and then SEM images were obtained. Each sample and image were then analyzed with energy-dispersive x-ray spectroscopy (EDS) to confirm the carbon nature of the features. The sample was then unmounted and added to the treatment fluid containing 0.0087 molar (M) ammonium persulfate, 0.013 M sodium bromate, and 0.27 M potassium chloride in 10 mL of water for 20 hours at 100° C. The fluid was then cooled, and then the sample removed from the fluid and dried in an oven at 80° C. After drying, SEM imaging (e.g., SEM image 1102 in FIG. 11) was again performed, and the location of the previous organic matter features were identified and reimaged via SEM and EDS. The fractured kerogen porosity was estimated by identifying the new pores and new fractures (e.g., microfractures) generated in the kerogen by the treatment process. The fracture face depth affected was also estimated from the electron microscope images.

FIG. 11 are SEM image 1100 and SEM image 1102, each of the same shale sample pre-oxidative treatment and post-oxidative treatment, respectively, and associated with Example 3. The SEM image 1100 is an SEM image of a shale sample that has not been treated with an oxidizer. The SEM image 1102 is an SEM image of that shale sample after being treated with an oxidizer. Thus, with respect to oxidative treatment, image 1100 is a before image and image 1102 is an after image. As discussed in Example 3, the shale sample was treated with an aqueous treatment fluid (solution) having two oxidizers 0.0087 M ammonium persulfate and 0.013 M sodium bromate, as well as the salt 0.27 M potassium chloride, for 20 hours at 100° C. Items 1104 in the shale sample in the SEM image 1102 (the after image) are new items that increase total porosity of the shale sample. These new items (items 1104) were caused by the shale sample being subjected to a treatment fluid having oxidizer. The items 1104 are artifacts caused by the oxidative treatment and that contribute to total porosity. In other words, the items 1104 are new pores (new microfractures) formed in and around the organic matter (kerogen) and that increase total porosity of the shale sample.

FIG. 12 is an image 1200 that is the SEM image 1102 of FIG. 11 but with a grid placed over the SEM shale image. To give the image 1200, a grid pattern is drawn over the surface of the SEM shale image 1102. In this illustrated example, the grid is 8 rows by 15 columns. Thus, there are 15 blocks (squares) in each of the 8 rows, and there are 8 blocks (squares) in each of the 15 columns. The grid is placed over the SEM shale image to estimate the surface area covered by the new items 1104 (new pore features) that increase total porosity of shale sample.

In this example, a scale of numbers 0, 1, 2, or 3 for each square of the grid represents an estimate of area coverage of items 1104 within the given square, where 0=0%, 1=33%, 2=67%, and 3=100%. As tabulated below in Table 2, these numbers of 0, 1, 2, or 3 from the scale that are assigned for each square are summed to estimate the added total porosity of 34% to the shale sample due to the oxidative treatment. Knowing this 34% facilitates determine permeability enhancement or increase in connected porosity. This 34% would be utilized as the treated kerogen porosity (0.34) and would be utilized to determine the void space created.

Computer digital-image processing may be employed in determining coverage (and thus added total porosity) of the items 1104 (new pores/microfractures) in and around the organic matter (kerogen) of the shale sample as imaged at the surface (face) of the shale sample.

TABLE 2
Assigned numerical scale values for each square of 8 × 15 grid
	1	2	3	4	5	6	7	8	9	10	11	12	13	14	15	T
1	1	1	1	1	1	0	0	0	0	0	0	2	1	0	0	8
2	2	2	2	1	1	1	0	0	0	0	0	0	0	0	0	9
3	1	0	1	1	1	2	3	2	2	1	0	0	2	1	1	18
4	1	1	3	1	2	1	1	1	0	1	1	2	2	2	3	22
5	1	0	1	1	1	0	1	1	1	1	2	3	1	1	0	15
6	1	1	2	2	2	3	3	3	3	3	3	2	1	2	3	34
7	0	0	1	0	1	1	1	1	1	0	2	0	1	0	0	9
8	0	0	1	1	1	1	0	0	0	0	1	1	1	1	1	9
																124

Table 2 depicts the grid of 8 rows by 15 columns. The T (total) per row of the scale numbers of squares in that row is given. The sum of the T for the grid is 124. The total 100% (scale number 3) coverage for an 8×15 grid is 120 0.3=360. Thus, the added total porosity is estimated at 124/360=34%. Thus, for instance, if the total porosity was 25%, this added 34% can mean that the total porosity is increased to 59%. The added total porosity may be the fractured kerogen porosity. The added total porosity may be additional connected porosity.

FIG. 13 is a method 1300 of evaluating or determining effect of hydraulic fracturing fluid having an oxidizer on a subterranean formation with the oxidative hydraulic fracturing on the subterranean formation. The method can be characterized as estimating enhancement of porosity and/or enhancement of permeability of a subterranean formation due to presence of an oxidizer in a fracturing fluid. The fracturing fluid is utilized in hydraulic fracturing of the subterranean formation.

At block 1302, the method includes determining porosity (e.g., total porosity) of the subterranean formation before the oxidative hydraulic fracturing of the subterranean formation. In other words, this can be the porosity of the subterranean formation before the hydraulic fracturing of the subterranean formation with the hydraulic fracturing fluid having the oxidizer. This subterranean formation porosity (including rock porosity) can be determined, for example, from well log measurements or by laboratory methods, and the like. The values can generally vary from one rock formation to the next. Again, the porosity (before oxidative hydraulic fracturing) may be obtained, for instance, from well logs or from analysis of collected formation samples via standard laboratory methodologies. This porosity may be compared to porosity after the oxidative hydraulic fracturing. As for units of the porosity values, because porosity is a ratio or dimensionless, the units may be porosity units (PU), dimensionless, or %.

At block 1304, the method includes determining the percent of the porosity (from block 1302) of the subterranean formation before oxidative hydraulic fracturing that is connected porosity. The percent of the total porosity that is connected porosity can be determined, for example, via standard laboratory techniques on samples of the subterranean formation collected before oxidative hydraulic fracturing. The connected porosity before oxidative hydraulic fracturing may be equal to the mathematical product of % connected porosity (before oxidative hydraulic fracturing) multiplied by total porosity (before oxidative hydraulic fracturing). This connected porosity or percent connected porosity may be compared to the connected porosity or percent connected porosity after the oxidative hydraulic fracturing.

At block 1306, the method includes determining kerogen vol % in the subterranean formation. The kerogen vol % can be determined based on (correlative with) the kerogen wt % and the kerogen density. Thus, the kerogen vol % may be determined, for example, by determining kerogen wt % in the subterranean formation and determining kerogen density of kerogen in the subterranean formation. Therefore, the method may include estimating kerogen wt % in the subterranean formation. The method may include estimating the kerogen wt % and the kerogen maturity via pyrolysis testing of a sample of the subterranean formation. The method may include estimating kerogen density of kerogen in the subterranean formation based on maturity of the kerogen. In implementations, the estimating of the kerogen density based on the maturity may involve employing an empirical relationship.

At block 1308, the method includes determining (e.g., estimating) fractured kerogen porosity of the subterranean formation as subjected to oxidative hydraulic fracturing. The fractured kerogen porosity is generally associated with presence of the oxidizer. The method may include estimating, via SEM imaging of a sample of the subterranean formation, the fractured kerogen porosity caused by an oxidizer of a fracturing fluid.

The estimating of the fractured kerogen porosity may involve, after oxidative treatment via the oxidizer, imaging (e.g., SEM imaging) a sample of the subterranean formation. The sample may be collected from the subterranean formation before hydraulic fracturing of the subterranean formation with the fracturing fluid having the oxidizer, and the oxidative treatment is performed on the collected sample (e.g., in the laboratory). On the other hand, the sample is collected from the subterranean formation after hydraulic fracturing the subterranean formation with the fracturing fluid having the oxidizer, and thus the oxidative hydraulic fracturing is the oxidative treatment of the sample (before collection). However, again, the estimating of the fractured kerogen porosity may involve imaging a sample of the subterranean formation (before oxidative hydraulic fracturing) with the sample subjected to oxidative treatment (e.g., in the laboratory) via the oxidizer. Indeed, in some implementations, samples are generally not collected from the formation after hydraulic fracturing. Instead, samples are from core sample obtained before the well is completed. In those cases, samples imaged before and after treatment are from laboratory treatment and may be utilized as a proxy for the actual hydraulic fracturing treatment. A core sample may generally be a cylindrical section obtained by drilling with special drills into the subterranean formation, such as with a hollow steel tube or a core drill. In the coring technique, the sample may be pushed more or less intact into the tube.

The method may include estimating the fractured kerogen porosity via imaging a sample of the subterranean formation, wherein the sample is treated with the oxidizer or wherein the subterranean formation is treated with the oxidizer. The imaging can involve image processing to estimate the fractured kerogen porosity. Estimating the fractured kerogen porosity via the imaging may include identifying items of the sample in an image of the sample, wherein the items are caused by the oxidizer. The items may be, for example, pores associated with organic matter caused by attack of the organic matter by the oxidizer. The items may be items in or adjacent organic matter at an external surface of the sample, wherein the items contribute connected porosity. In all, the estimating of the fractured kerogen porosity via the imaging can involve identifying items on the sample in an image of the sample caused by the oxidizer, wherein the items include pores or fractures, or both, in or adjacent organic matter of the sample.

At block 1310, the method includes determining the increase in connected porosity caused by an oxidative hydraulic fracturing. The method may include determining (e.g., estimating) the increase in connected porosity in the subterranean formation correlative with (based on) the kerogen vol % and the fractured kerogen porosity (e.g., due to the oxidizer). The connected porosity after oxidative hydraulic fracturing is a treatment effect and may be equal to the sum of the connected porosity before oxidative hydraulic fracturing plus the mathematical product of the fractured kerogen porosity multiplied by kerogen vol %. Thus, the increase in connected porosity may be the fractured kerogen porosity multiplied by the kerogen vol % (in the formation).

FIG. 14 is a computing system 1400 having a processor 1402 and memory 1404 storing code 1406 (e.g., logic, instructions, etc.) executed by the processor 1402. The code 1406 may include the executable components or logic to implement the aforementioned techniques including actions described with respect to (and associated with) the preceding figures. The computing system 1400 may be single computing device, a server, a desktop, a laptop, multiple computing devices or nodes, a distributed computing system, or a control system or component of a control system, or a computer associated with an analytical device or instrument (e.g., SEM). The processor 1402 may be one or more processors and may have one or more cores. The hardware processor(s) 1402 may include a microprocessor, a central processing unit (CPU), a graphics processing unit (GPU), or other circuitry. The memory 1404 may include volatile memory, nonvolatile memory, and firmware. The volatile memory can include, for example, cache or random access memory (RAM). The nonvolatile memory can include, for example, hard drive, solid-state drive, read only memory (ROM), etc. As indicated, the computing system 1400 may be programmed via the code 1406 stored in memory 1404 and executed by the processor 1402 to perform actions discussed throughout the present disclosure including with respect to the figures.

The computing system 1400 improves, for example, the technologies of subterranean formation evaluation, hydraulic fracturing, and the production of hydrocarbons from a subterranean formation. In addition, the computing system 1400 is an improved computing system via the code 1406 in providing for timely evaluations or predictions of oxidative treatment effects on subterranean formations, an in facilitating planning and implementing oxidative hydraulic-fracturing treatments. Such is plainly unconventional, including with respect to the present techniques described herein.

An embodiment a method of estimating enhancement of porosity and permeability of a subterranean formation due to presence of an oxidizer in a fracturing fluid. The fracturing fluid may be utilized in hydraulic fracturing of the subterranean formation. The method includes determining kerogen vol % in the subterranean formation and estimating fractured kerogen porosity, wherein the fractured kerogen porosity is associated with presence of the oxidizer. The method includes determining an increase in connected porosity in the subterranean formation correlative with the kerogen vol % and the fractured kerogen porosity. In implementations, the determining of the kerogen vol % involves determining kerogen wt % in the subterranean formation and determining kerogen density of kerogen in the subterranean formation, wherein the kerogen vol % is correlative with the kerogen wt % and the kerogen density. The method may include estimating kerogen density based on maturity of the kerogen. The method may include estimating the kerogen wt % and the maturity via pyrolysis testing of a sample of the subterranean formation. The estimating of the fractured kerogen porosity may include imaging, after oxidative treatment via the oxidizer, a sample of the subterranean formation. The imaging may be via a scanning electron microscope. In implementations, the oxidative treatment is performed on the sample, wherein the sample is collected from the subterranean formation before hydraulic fracturing of the subterranean formation with the fracturing fluid having the oxidizer, and the oxidative treatment is performed in the laboratory on the sample. In other implementations, the sample is collected from the subterranean formation after hydraulic fracturing the subterranean formation with the fracturing fluid having the oxidizer. In some implementations, samples are generally not collected from the subterranean formation after the oxidative hydraulic fracturing. Instead, samples are obtained from the formation (e.g., from a core sample) collected before the well is completed. In those cases, samples imaged before and after treatment are from laboratory treatment and may be utilized as a proxy for the actual hydraulic fracturing treatment.

Another embodiment is a method of evaluating effect of hydraulic fracturing fluid having an oxidizer on a subterranean formation. The method includes determining porosity of the subterranean formation before hydraulic fracturing the subterranean formation with the hydraulic fracturing fluid comprising the oxidizer, determining percent of the porosity that is connected porosity, and determining an increase in the connected porosity correlative with kerogen vol % in the subterranean formation and fractured kerogen porosity due to the oxidizer. The method may include estimating the fractured kerogen porosity via imaging a sample of the subterranean formation, wherein the sample is treated with the oxidizer or wherein the subterranean formation is treated with the oxidizer. The imaging may include image processing to estimate the fractured kerogen porosity. The estimating of the fractured kerogen porosity via the imaging may include identifying items of the sample in an image of the sample, wherein the items are caused by the oxidizer, and wherein the imaging gives the image. In implementations, the items may include pores associated with organic matter caused by attack of the organic matter by the oxidizer.

Yet another embodiment is a method of determining effect of oxidative hydraulic fracturing on a subterranean formation. The method includes determining porosity of the subterranean formation before the oxidative hydraulic fracturing, determining percent of the porosity that is connected porosity, determining kerogen vol % in the subterranean formation, and estimating, via imaging of a sample of the subterranean formation, fractured kerogen porosity caused by an oxidizer of a fracturing fluid. The imaging may include SEM imaging. The method may include estimating an increase in connected porosity in the subterranean formation based on the kerogen vol % and the fractured kerogen porosity. In implementations, the method includes estimating kerogen wt % in the subterranean formation, and estimating kerogen density of kerogen in the subterranean formation based on maturity of the kerogen, wherein the kerogen vol % is determined based on the kerogen wt % and the kerogen density. The estimating of the kerogen density based on the maturity may involve employing an empirical relationship. The estimating of the fractured kerogen porosity via the imaging may involve identifying items on the sample in an image of the sample caused by the oxidizer, wherein the items include pores or fractures, or both, in or adjacent organic matter of the sample. In implementations, the items include items in or adjacent organic matter at an external surface of the sample, wherein the items contribute connected porosity.

A number of implementations have been described. Nevertheless, it will be understood that various modifications may be made without departing from the spirit and scope of the disclosure.

Claims

1. A method, comprising: determining porosity of a subterranean formation before hydraulic fracturing the subterranean formation with a fracturing fluid that is a hydraulic fracturing fluid comprising an oxidizer;determining percent of the porosity that is connected porosity before the hydraulic fracturing;determining kerogen volume percent (vol %) in the subterranean formation;collecting a sample of the subterranean formation comprising kerogen before the hydraulic fracturing;performing oxidative treatment via the oxidizer on the sample;estimating, via imaging of the sample, fractured kerogen porosity caused by the oxidizer in the oxidative treatment;predicting an increase in the connected porosity in the subterranean formation that would be caused by the hydraulic fracturing of the subterranean formation with the fracturing fluid based on the kerogen vol % of the subterranean formation and the fractured kerogen porosity of the sample caused by the oxidizer in the oxidative treatment of the sample; andwherein the fracturing fluid is utilized in hydraulic fracturing of the subterranean formation.

2. The method of claim 1, wherein determining the kerogen vol % comprises determining kerogen weight percent (wt %) in the subterranean formation and determining kerogen density in the subterranean formation, and wherein the kerogen vol % is correlative with the kerogen wt % and the kerogen density.

3. The method of claim 2, wherein determining the kerogen density comprises estimating the kerogen density based on maturity of the kerogen.

4. The method of claim 3, comprising estimating the maturity via pyrolysis testing.

5. The method of claim 1, comprising hydraulic fracturing the subterranean formation with the fracturing fluid.

6. The method of claim 1, wherein determining the kerogen wt % comprises estimating the kerogen wt % via pyrolysis testing.

7. The method of claim 1, wherein estimating, via the imaging of the sample, the fractured kerogen porosity caused by the oxidative treatment performed on the sample comprises identifying pores of the sample in an image of the sample, and wherein the pores are caused by the oxidizer.

8. The method of claim 1, wherein the sample is from a core sample of the subterranean formation collected via a well comprising the wellbore.

9. The method of claim 1, wherein the imaging comprises imaging via a scanning electron microscope.