Integrating Petrophysical and Geomechanical Rock Properties for Determination of Fracability of the Iraqi Tight Oil Reservoir

Abstract


Introduction
The oil and gas sector is continuously assessing and developing new reservoirs to meet the world's growing energy needs.Unconventional reservoirs, including tight oil reservoirs, which extend across a wide region and produce economically relatively large amounts of hydrocarbons with the support of unique technologies like fracturing treatment, have become the most leading destinations for resources (Holditch, 2006).Petrophysical and geomechanical properties of rocks are critical in developing strategies of oil reservoirs, including fracturing operations (Meehan, 1994).Numerous studies have examined the petrophysical and geomechanical characteristics of the formations in a number of Iraqi oil fields.Abdul Aziz and Abdul Hussein, 2021 developed correlations for estimating mechanical rock properties in Fauqi oil field that consists of reservoirs with various lithology including dolomite and limestone.Al-Majid, 2021 studied the petrophysical properties of a highly permeable reservoir.Tali and Farman, 2021 calculated the porosity of a carbonate reservoir in the south of Iraq using standard and statistical approaches.Abdulrahman et al. (2020) evaluated the Jeribe Formation in Jaria pika gas field in northeast Iraq.These researches as well as other published articles, did not address the petrophysical and geomechanical characteristics of rocks in the area under study with relation to the fracability of the formation using data from vertical wells.Therefore, to clearly implement the petrophysical and geomechanical properties to determination of the ability and easiness to fracture the formation under study, this research has been conducted.To measure these properties, well logs and a diagnostic fracture injection test (DFIT) data have been used.Afterward, two fracturing models were designed to investigate the capability of fracturing of the formation under study.
The Saadi Formation in Halfaya Oil Field, which is nominated for this study, is the Late Turonian-Early Campanian Sequence's youngest, thickest, and most distributed formation.It is 124 meters thick and is composed of the non-reservoir Saadi A and the reservoir Saadi B units.It is a carbonate oil reservoir with a medium-pore size, and a narrow-pore throat with poor petrophysical characteristics.The Saadi Formation is anticline composed mainly of limestone (Jassim and Goff, 2006).The permeability (k) of Saadi B reservoir is very low, while the porosity is poor to very good.Also, Saadi Formation, was deposited over the Tanuma Formation and underneath the Hartha Formation (Jassim and Goff, 2006).The Saadi B tight oil reservoir of the Halfaya Oil field, is 77 m in thickness and has been designated as the field's primary tight oil reservoir.Al-Fandi et al. (2020) illustrate the stratigraphy and lithology description of study area as shown in Fig. 1.

Rock Petrophysical Properties
Prior to log processing, every data had been thoroughly preprocessed and corrected for effects on wellbore conditions.Gamma Ray (GR) logs serve as a reference for all subsequent logs for depth matching as GR log is the only recorded log with each other log and shows clear indication of formation tops, and the total depth is verified and rectified using the depth of the casing shoes.Each logs depth is perfectly matched each measurement point.All data have been adjusted to account for environmental effects.Density logs have been adjusted to account for hole size and mud weight.Corrections for hole size, temperature, pressure, mud weight, and borehole salinity were made to the neutron logs.Resistivity logs were adjusted for borehole effects and mud filtrate invasion using a typical sonic-neutron scatter cross plot.The lithology was deduced from log responses.Saadi and Tanuma formations tops are found based on GR log reading.
The porosity from neutron logs (PHIN) and the porosity from density logs (PHID) which is estimated by equation (1) (Kilgore et al., 1972), are used to compute the average porosity using arithmetic average (PHIavg), and root mean square method (PHIRMS) by equations ( 2) and (3), respectively.However, the average porosity (PHIA) that was used in the model is the arithmetic average of (PHIavg) and (PHIRMS) as per equation ( 4).Gamma-ray index (IGR) and shale volume (Vsh) are estimated using equations ( 5) and ( 6), respectively (Thomas and Stieber, 1975).Afterward, the effective porosity (PHIE) is computed using equation ( 7) (Bateman, 1986). (2) (3) Where ρmatrix, ρbulk and ρfluid are matrix, bulk and fluid densities in gm/cm 3 .The estimated reservoir permeability (PERMest), relates to how much oil is produced and the magnitude of leak-off it may anticipate, was estimated using the correlation in equation (8).For tight oil reservoirs where the permeability is as low as 1 md, the permeability multiplier (kmultiplier) and the permeability exponent (kexponent) were set to 20 and 3, respectively (Barree, 2017).This is neither a core permeability nor an absolute permeability but rather an effective permeability.DFIT permeability should be used to validate it.The fracture geometry or leak-off is seldom affected by permeability values in tight reservoirs.Therefore, leak-off is neglected.Archie equation is used to estimate water saturation (Sw) as shown in equation ( 9) (Archie, 1952).Analysis of sample shows that formation water salinity is 70000 ppm at temperature of 190 °F and by using Schlumberger chart for adjusting resistivity, formation water resistivity (Rw) in Saadi reservoir is found to be 0.04 ohm.m.The tortuosity factor (a) is 1, and cementation exponent (m) is 1.8-2.5 for carbonate reservoir (Asquith and Krygowski, 2004).In this research, m equal to 1.8 is used since water saturation will not affect the fracturing model.The net pay of the reservoir is calculated by applying three cutoff conditions.Porosity, resistivity and Vsh cutoffs were fixed to 0.04, 10 ohm.m, 0.5, respectively.
Where Rt is the true deep resistivity.

Rock Geomechanical Properties
The Closure pressure is highly dependent on the geomechanical characteristics of the reservoir.Therefore, they regulate and control the propagation of the created fractures.Poisson's ratio (v), Young's modulus (YME), vertical poroelastic coefficient (αv), brittleness factor (BRF), critical fissure opening pressure (CFOP), pore pressure (Pp), process zone stress (PZS), and total closure stress (Pc) were all included into the model as geomechanical characteristics.
The Poisson's ratio and the Young's modulus that are estimated dynamically from log records are two critical elastic constants utilized in the design of fracturing models.The Poisson's ratio (v) expresses the amount of strain in the direction perpendicular to the applied stress, transverse strain (εT), and the strain parallel to it, longitudinal strain (εL) as shown in equation ( 10) (Fjaer et al., 2008).Applying elevated stress using simulation, the strain components are estimated by estimating the ratio of change in the dimension to the original dimension and directly used to calculate Poisson's ratio.Young's Modulus (YME) is a measure of a rock's stiffness and indicates the stress needed to deform a rock.Young's Modulus is determined by dividing stress (σ) by strain (ε) as in equation ( 11).High Young's Modulus value indicates a stiffer material, since it requires more stress to produce a given strain (Economides and Martin, 2007).The pressure response is expected to be 100% since the reservoir fluid communicates directly with the fracturing fluid.Therefore, the horizontal Biot's poro-elastic constant (αh) is fixed to 1.In contrast, the vertical Biot's poro-elastic constant (αv), which dictates how much pore pressure affects the effective stress, is computed utilizing effective porosity values as per equation ( 12).Brittleness factor (BRF) is computed using equation ( 13) (Rickman et al., 2008).
BRF = 0.071 YME − 1.43 v + 0.5 (13) The Extra pressure above closure stress (CFOP) that is required to open natural fractures as well as pore pressure gradient were estimated from DFIT results.Then, equation ( 14) was used to estimate the pore pressure.The total closure stress (PC) is computed using equation ( 15) after all petrophysical and geomechanical characteristics were recognized.Surface ISIP was found from DFIT analysis and converted to bottom hole conditions, then process zone stress (PZS) was estimated as per equation ( 16) (Barree, 2017).Pp = Depth × Pore Fluid Gradient + CFOP ( 14) Where εx is regional horizontal strain and σt is horizontal tectonic stress.

Breakdown Pressure and Fracture Orientation
Hussain and Al Mahdawi, 2019 observed in their study about estimation of breakdown pressure gradient in Halfaya Oil field, that the breakdown pressure gradient (Pbd / h) is directly related to the pore pressure gradient.They showed that Cesaroni I method that takes into consideration the low permeability reservoirs as per equation ( 17), gave the best results of the breakdown pressure gradient in Halfaya oilfield.
Where Pbd is the breakdown pressure and h is the depth.In fracturing stimulation, it is essential to distinguish the in-situ stress orientations all over the reservoir since this will determine the direction of the created fractures.The orientation of the stresses of any formation is critical for fracture propagation.Fractures propagate in a path perpendicular to the direction of the minimal horizontal stress or parallel to the direction of the maximum stress (Zhang et al., 2018).

Diagnostic Fracture Injection Test (DFIT)
The deliverability of unconventional reservoirs is determined not by matrix characteristics, but by secondary fractures and, potentially, an enhanced-permeability zone produced by stimulation.As a result, it is incorrect to utilize permeability values obtained from cores in designing completion and stimulations.DFIT or fall off tests, which detect the reservoir permeability, is more suitable technique in unconventional reservoirs wherein they used in place of prolonged transient tests (Barree et al., 2015).The fluid type used in the test, well configuration, reservoir and the mini-frac pressure vs. time data were the primary input for analyzing the test.DFIT test events, the blowdown and the G-function analyses were performed.Pre-falloff test event of the DFIT was analyzed to set the instantaneous shutin pressure (ISIP) and fracture gradient.Meanwhile, blowdown analysis was performed to eliminate the effect of the instantaneous pressure decrease caused by pipe friction, perforations, near-wellbore friction and decompression of wellbore fluids on the value of ISIP.Moreover, G-function plot of pressures falloff, pressures first and log of superposition derivatives vs. G-time, i.e., dimensionless closure time, was used to determine closure pressure, PZS, closure gradient, CFOP and permeability.The G-function time was estimated using (Nolte, 1979) equations ( 18) through (20).The effective permeability (k) is computed using empirical correlation equation ( 21) (Barree et al., 2009).Where G is G-function time, ΔtD is dimensionless pumping time, g is dimensionless time function, g0 is dimensionless time-function at shut-in, tp is pumping time, μ is viscosity of injected fluid and subscript c is closure time.

Fracturing Models
Standard hydraulic fracture treatment provides optimal length and conductivity for well stimulation.Performing hydraulic fracturing treatment requires careful consideration of fracture design parameters such as fracturing fluid kind and size, proppant kind and concentration and rate of pumping, etc., (Shaoul et al., 2007).Hydraulic fracturing design should prioritize contacting reservoir capacity above generated fracture half-length or conductivity and fracture height.Increases in the length of the produced fracture have a progressively decreasing influence on effective fracture length (Barree et al., 2015).

Selection of fracturing fluids and proppants
The utilized fracturing fluid depends on the permeability and brittleness.High-permeability formations are typically stimulated with viscous fracturing fluid to generate wide fractures.In contrast, unfractured rocks in low-permeability formations hindered fluid flow.Likewise, when rock brittleness reduces (or ductility rises), larger fracture openings are required to preserve permeability of the fractures once the pressure is removed.Brittle reservoirs with poor permeability need more aggressive fracturing.To compensate, more fluid volume is injected with reduced viscosity (slick-water or Guar fluid) (Cipolla et al., 2008).Also, increasing the amount of fracturing fluid causes the fracture lengths to rise (Rickman et al., 2008).
Proppant (typically sand) is injected with fluid to maintain the fracture open and provide a route for reservoir fluids to reach the wellbore.The size of the proppants has a significant effect on the fracture's permeability.Higher permeability is achieved with homogeneous and greater proppant sizes (Zoback and Kohli, 2019).The fracture permeability is influenced by the proppant's transportability and strength.Higher transportability enables deeper proppant distribution into the fractures.Smaller, lighter proppants are easier to carry (Economides, 2013).Proppant strength is equally essential.If the fracture closure stress exceeds the proppant's compressive strength, the particles will be smashed.This decreases proppants size and therefore fracture permeability.Ceramic proppants have varying densities, compressive strengths, and their size and shape can be precisely controlled to create extremely homogeneous grains (Lyle, 2011).
As shown in Fig. 2 which depicts typical trends in fracture fluid kinds, volumes, and complexity based on rock characteristics.Where the rock's brittleness rises, permeability decreases, and is highly fractured, the hydraulic fracturing treatment should utilize low viscosity, large volume, and high pumping rate of fracturing fluid, but with lower proppant volume and concentration.Meanwhile, the fractures tend to be asymmetrical, more complex, with smaller openings, and vice versa (Rickman et al., 2008).Therefore, based on these properties, the Guar_200 F° and Slickwater_180 F° fracturing fluids suits the viscosity and the temperature of Saadi B reservoir.The low-density ceramic and high-density ceramic proppants were chosen since they give highest conductivity for stresses higher than 6000 psi.

Lithology Identification
As shown in Fig. 3, which illustrates the lithology identification scatter cross-plot for well HF-55, The sonic-neutron scatter-plot shows that DTC of Saadi reservoir is 47.6 μsec/ft.This value indicates that Saadi B reservoir comprises of relatively clean limestone.However, the Saadi B reservoir show some shale regions.The results of DFIT are summarized in Table 1.

Breakdown Pressure and Fracture Orientation
The breakdown pressure varies at each point within the formation.For well HF-55, it is found that the minimum and maximum breakdown pressures at the top of the pay zone in Saadi B reservoir at 2704.65 mTVD are 5815 psi and 8597 psi, respectively.Also, the minimum and maximum breakdown pressures at the bottom of the pay zone in Saadi B reservoir at 2774.25 mTVD are 6247 psi and 7768 psi, respectively.The minimum breakdown pressure at each point is considered in fracturing models.
The breakdown gradient diagram (in psi/ft), which is shown in Fig. 9a, is affected by CFOP and stress anisotropy of 695.578 psi and confirms that the azimuth of maximum horizontal stress is at 205.074 degrees.The figure shows that the fracture occurs more easily in the northeast/ southwest direction.
The breakdown angle diagram, shown in Fig. 9b, indicates the position of the fracture creation point in the vicinity of the well.The red and purple spots indicate sites where fracture creation results in danger of mainly developing horizontal fractures as well as shear failure along with the layers or preexisting planes of low strengths.

Fracturing Models
Based on the measured geomechanical properties and breakdown pressures required to create the fracture, the simulation of the fracturing models shows different cumulative fracturing elements volumes and fracturing size.Design A treatment required cumulative clean volume of 53475.9gal, cumulative slurry volume of 55870.5 gal, and cumulative proppant of 72013 lb to be pumped through the perforations.The half-length and the height of the fracture are 220 m and 178 m, respectively, with an average and maximum widths of 0.054 inches and 0.129 inches, respectively.Design B treatment required cumulative clean volume of 53354.4gal, cumulative slurry volume of 56404.5 gal and cumulative proppant of 72013 lb to be pumped through the perforations.The half-length and the height of the fracture are 208.8m and 98 m, respectively, with an average and maximum widths of 0.047 inches and 0.113 inches, respectively.Fig. 10 and Fig. 11 show the fracture width for designs A and B for well HF-55, respectively.

Discussion
The sonic-neutron scatter-plot clearly indicates that Saadi B reservoir comprises of relatively clean limestone with some shale regions.The tops of Saadi B and Tanuma as obtained from GR log of well HF-55 are 2697.2mTVD and 2774.6 mTVD, respectively.Also, the petrophysical analysis show that net pay zone of Saadi B reservoir is found at 2704.65 mTVD and 2774.25 mTVD.The well logs serve as inputs to get more information regarding the study area, including Sw, permeability, net pay zone, and geomechanical properties, as presented in Fig. 4 and Fig. 5. Numerous property grids have been created using well HF-55 as a reference well which is located between the toe and the toe edge of the project area.Pre-Fall-off analysis begins with analyzing of the DFIT events as illustrated in Fig. 6.With an avg.perforation depth at 2738 m, a surface ISIP of 2560.09psi was recorded after 9.69395 minutes of pumping.This results in a bottom-hole ISIP of 6450.65 psi, which indicates a fracture-extension gradient of 0.7181 psi/ft.Blowdown analysis in Fig. 7 shows a compression in the injected fluid of 23.498 psi/bbl.The pressure, which is 1945.06psi at the beginning of compression (time = 70.670min) increases to 5416.22 psi at the end of compression (time = 76.620)due to compression.The analysis also shows a blowdown pressure of 413.626 psi which is observed after injection has been stopped meaning that the exact surface ISIP is 2973.71psi (bottomhole ISIP is 6,864.276psi) which is seen at the final pump rate (t = 86.313min).The ISIP value observed in the test events was calibrated to the new value.The G-function analysis as given in Fig. 8 shows that fissure opening happens after 11.2622 min, at G time equal to 0.317775 with a bottomhole pressure of 6407.18 psi.The closure occurs after 27.6836 min, at G time equal to 2.20342 with a bottomhole pressure (total closure stress) of 6251.22 psi.This results in a closure-stress gradient of 0.695899 (psi/ft) and PZS of 199.428 psi.Moreover, the analysis shows that 155.96 psi extra pressure above closure stress, CFOP, is required to open natural fractures which lead to pore pressure gradient of 0.684855 psi/ft.Permeability from the closure time is estimated to be 0.0562293 md.The results from DFIT are quite consistent with well logs results.
The petrophysical properties (Fig. 4) show that Saadi Formation has relatively poor quality reservoir with relatively high porosity and extra low permeability which infer that the reservoir is a tight oil reservoir.However, promising water saturation values are recognized and ranges from 18.22% to 47.42%, designating a favorable oil zone, and these values indicate that Saadi B reservoir has to be fractured to enhance the permeability and increase the conductivity of the pores.Also, the findings show lower PR and higher YME values in Saadi B reservoir than the layers above it, indicating that Saadi B reservoir is brittle.However, the formations above and below these layers are more brittle than Saadi B reservoir since they have lower PR and higher YME values.Moreover, BRF results indicates the presence of brittle rock immediately around the wellbore in Saadi B reservoir, which assists in fracture propagation, yet there are ductile rock strata above and below Saadi B reservoir.Also, an extremely brittle rocks exist above and below the ductile rocks.These findings from the simulation demonstrate that the fracture height development may extend uphill and/or downhill the Saadi B reservoir.Therefore, a close monitoring of fracturing components design particularly the fracturing fluid type has been taken into account to control the fracture propagation above or below the Saadi B reservoir.
The results of CFOP, Pc, PZS and pp are essential in estimating the breakdown pressure.The minimum breakdown pressure at each point is considered in fracturing models.According to the results of the breakdown pressures, the minimum breakdown pressure at the top and the bottom of the pay zone in Saadi B reservoir are 5815 psi and 6247 psi.This shows that the required pressure to fracture the Saadi B reservoir is around 6250 psi which can easily be applied due to availability of well head components that could handle these pressures.The design (A) for well HF-55 results show that fracture height propagates upward and downward to Hartha and Tanuma formations, respectively, Design (B) reveals that the fracture on either side of the well is asymmetric.The fracture is developed in Saadi Formation and propagate perfectly in the lateral direction.The fracture height is controlled and confined in Saadi Formation from the top.Controlling the fracture development downhill to Tanuma Formation is entirely unlimited due to the close distance between the pay zones of Saadi and Tanuma formations.Therefore, the use of petrophysical and geomechanical properties of the rocks aids in understanding the fracability of Saadi Formation, demonstrating the orientation and the fracture propagation direction.

Conclusions
Developing petrophysical and geomechanical properties of Saadi B tight oil reservoir in order to estimate the fracability of the reservoir rocks is the concern of this research.Therefore, a complete suite of petrophysical and geomechanical properties are estimated for the formations above and below Saadi B reservoir as well as Saadi B reservoir.These properties are the base for creating the fracturing models with the aid of DFIT analysis.The key conclusions that can be drawn from the study's findings include that Saadi B reservoir consists of clean limestone with some shale regions.The petrophysical analysis shows that Saadi reservoir has poor petrophysics wherein promising water saturation values observed.The geomechanical properties model refer to variations across the formations and that Saadi B reservoir is brittle with ductile rock strata above and below Saadi B reservoir while the formations above and below are more brittle than Saadi B reservoir.The results from DFIT are quite consistent with well logs results.The breakdown pressure of Saadi B reservoir reflects that this reservoir could easily be fractured by inserting pressure equal to 6250 psi.The design (A) fracturing treatment which employ Guar fracturing fluid and high-density ceramic proppants show that fracture height propagates upward and downward to Hartha and Tanuma formations, respectively.On the other hand, design (B) treatment which uses Slickwater fracturing fluid with low-density ceramic proppants reveals that the fracture is developed in Saadi Formation and propagate perfectly in the lateral direction and downhill to Tanuma Formation.This imply that the fracture height is controlled using Slickwater fracturing fluid with lowdensity ceramic proppants rather than tempting to use Guar fracturing fluid and high-density ceramic proppants.Therefore, the fracturing model design manipulate the fracture height confinement within Saadi Formation and its propagation to Hartha and/or Tanuma Formations.In summary, the employment of petrophysical and geomechanical properties of the rocks aids in understanding the fracability of the formation and demonstrating the orientation and the fracture propagation direction.

Table 1 .
DFIT results 6407.180 psi Pore or reservoir pressure gradient 0.684855 psi/ft CFOP 155.9600 psi Permeability from the closure time 0.056229 md