CA2932670A1

CA2932670A1 - Assessment of reservoir heterogeneity by using produced water chemistry

Info

Publication number: CA2932670A1
Application number: CA2932670A
Authority: CA
Inventors: Ian D. Gates; Zeinab Khansari
Original assignee: UTI LP
Current assignee: UTI LP
Priority date: 2016-06-06
Filing date: 2016-06-06
Publication date: 2017-12-06

Abstract

The invention disclosed herein generally relates to the field of oil and gas subsurface earth formation evaluation techniques. In a particular aspect, the present invention is directed to methods of using water geochemical data to identify and index shale layers in an oil sands reservoir.

Description

-, ASSESSMENT OF RESERVOIR HETEROGENEITY BY USING PRODUCED
WATER CHEMISTRY
FIELD OF THE INVENTION
[0001] The present invention is generally related to the field of oil and gas subsurface earth formation evaluation techniques. In particular, the present invention is directed to methods of estimating properties of a subterranean formation.
BACKGROUND OF THE INVENTION

[0002] A key consideration in the extraction of oil from oil sands reservoirs is the viscosity of the oil, which can be typically between 100,000 and several million cP.
Thermal recovery methods, such as the Steam Assisted Gravity Drainage (SAGD) process, is presently a method of choice for the Athabasca oil sands reservoirs, located in northeastern Alberta, Canada. In SAGD, in order to reduce the viscosity of the oil, high pressure (typically between about 1 to 5 MPa) and high temperature (typically between about 185 C and 250 C) steam is injected into the reservoir. At original conditions, the viscosity of bitumen can be in the hundreds of thousands to millions of cP, whereas at elevated temperature, it can drop to less than 10 cP and then drain within the reservoir under the action of gravity.
The SAGD process can incorporate, for example, two horizontal wells, one atop the other. Steam can be injected into the reservoir through the top well, whereas fluids, including steam condensate and mobilized bitumen, may then be produced through the lower well to the surface.

[0003] An important concern with regard to SAGD is the amount of carbon dioxide created in the process when fuel, most often natural gas, is combusted to generate steam. A high carbon dioxide-to-oil intensity can be the result of poor steam conformance in the reservoir. It has been shown that poor steam conformance may be caused by geological heterogeneities of the reservoir. This can especially be the case in systems where there may be extensive shale layers which can block steam ascension and oil drainage. In real time, with current WSLEGAL\045074\00165\13492436v3 technology, the only means may be to estimate the extent of the steam chamber around a SAGD wellpair from thermocouple and distributed temperature sensor data or 4D seismic data interpretation. Larter et al. (2008) analysed the spatial arrangement of bitumen composition within the reservoir, from core samples prior to steam injection and used the spatial mapping of the compositions to allocate the origins of produced oil samples with the reservoir to estimate steam chamber conformance. Although they found they could use the data to roughly estimate steam conformance, these methods can be complex and may be subject to uncertainty, especially in reservoirs where the composition of bitumen is essentially the same at different locations within the reservoir.

[0004] The existence and influence of chemical reactions in oil-steam systems have been extensively studied. Hyne (1986) showed that in temperature range of around 170 C to 300 C, aquathermolysis (hydrous pyrolysis) is the dominant reaction class. Thermal cracking (pyrolysis) typically occurs at temperatures greater than about 300 C. Clark and Hyne (1984) devised a reaction scheme to represent aquathermolysis that produced mainly methane, light hydrocarbons, hydrogen sulfide, hydrogen and carbon oxides. Ng (1997) investigated the kinetics of water gas shift reaction in a temperature range of 320 C to 380 C
and proposed reaction rate constant and reaction profile depicting the generation of hydrogen, hydrogen sulfide and carbon oxides. Kapadia et al. (2012, 2013) constructed a new reaction model for aquathermolysis and applied it to understand the generation of hydrogen sulphide in the SAGD process. The results demonstrated that SAGD may not only be a physical process but also a chemically reactive one in which the reaction zones of the process may predominantly be found at the edges of the depletion chamber where there is a combination of elevated temperature, hot mobile bitumen, and steam condensate.

[0005] Beyond the water gas shift reaction and aquathermolysis reactions occurring during steam-based processes such as SAGD, another class of reactions occur between reservoir rock minerals and steam. The products of steam-rock reactions may significantly affect reservoir properties such as WSLEGAL\ 045074 \00165\13492436v3 mineralogy, porosity, and permeability, thus the recovery efficiency. For example, there is potential for deposition of scale in the reservoir and at the injection and production wells due to steam-rock reactions. Scale buildup within the system, especially at the wells, may lower the efficiency and productivity of the recovery processes significantly. At this point, reactive thermal reservoir simulation models of steam-based recovery processes may not take rock-steam reactions into account.

[0006] Sjoberg (1978) studied calcite dissolution mechanisms with associated kinetics and found that the dissolution reaction depends on the form of the calcite present (powder or crystal) due to the difference in their available surface area and pH. He also described that magnesium and phosphate ions act as inhibitors for calcite dissolution. Boon et al. (1983), in a series of experiments, determined the effect of different parameters on calcite dissolution rate and found that steam-rock reactions were controlled by pH, salinity and temperature and slightly affected by bitumen interaction. They concluded that high temperature and high pH were in favor of calcite dissolution. Abercrombie and Hutcheon (1986), by studying carbon isotopes, showed that CO2 released after steam flooding may not solely be sourced from aquathermolysis reactions between steam and oil but also from inorganic rock-steam reactions.

[0007] Gunter and Bird (1988) described that during thermal enhanced oil recovery, the presence of steam and steam condensate at elevated temperature enhances reactions that involve rock minerals and that the products may significantly affect reservoir permeability. They investigated the calcite dissolution reaction at 265 C and presented a three stage reaction model where condensate and calcite react relatively quickly to generate a calcium-saturated smectite, which in turn can react to produce CO2.

[0008] Gunter and Perkins (1993) studied CO2 disposal in a carbonate aquifer in central Alberta. They concluded the brine water may have less capacity to absorb CO2 due to its salt content. They also divided the CO2, water and carbonate WSLEGAL\045074\00165\13492436v3 reactions into two stages. The first stage consisted of calcite dissolution whereas the second one was adsorption of dissolved calcium and other ions onto the solid matrix (clay) of the aquifer. Using numerical modeling, they demonstrated that the amount of CO2 adsorption strongly depended on the mineral type and that the higher the amounts of calcium and magnesium, the higher the CO2 storage in the aquifer.

[0009] Previous research has shown that steam injection can promote calcite decomposition. Maclntire and Stansel (1953) reported that the temperature at which steam catalyzed dissolution occurs is equal to 973K (-700 C). Wang and Thomson (1994) studied the effect of steam on calcite decomposition and developed a reaction rate kinetic model based on their experimental results and showed that the presence of steam can significantly promote CO2 generation.
They concluded that steam weakened the bond between CaO and CO2 in calcite molecules that can lead to calcite dissolution.

[00010] Dreybrodt et al. (1997), in a series of experiments, demonstrated three processes in the calcite, water, and CO2 reaction system: 1. precipitation or dissolution of the reacting species at the surface of the calcite, 2. mass transport of reactants through the aqueous phase, and 3. slow reaction rate of CO2 and water ¨ this reaction being the rate limiting step. They found that when the solution is sufficiently far from equilibrium, for instance in the presence of inhibitors such as phosphate, the kinetics may strongly depend on the ratio of the solution volume to reactive surface area. They also devised a kinetic model that matched the experimental data. Liu and Dreybrodt (1997) presented two elementary reversible reactions that described changes in carbon dioxide concentration when steam is reacted with calcite. They concluded that when the aqueous solution with dissolved CO2 is supersaturated, the mechanism of precipitation may be the same as that of dissolution of calcite. Emberley et al.
(2005) investigated 002-steam-rock reactions in a carbonate reservoir in Saskatchewan, Canada and found that the dissolution of carbonate minerals, especially calcite, can change the mineral concentration (such as calcium ions) WSLEGAL \ 045074 \ 00165 \ 13492436v3 and the total dissolved solid. The CO2 reacts with calcium to form a calcite precipitate. The changes in CO2 content alter pH, which in turn can affect the dissolution reaction.

[00011] Kaufmann and Dreybrodt (2007) described the calcite-water-0O2 reaction system. They divided the kinetics into three different regimes with respect to the concentration of calcium ions: a low reaction rate regime, the fast reaction rate regime, and the high order kinetic regime. The results can demonstrate that the higher the calcium ion concentration, the lower the pH
and the higher the CO2 generated in CaCO3-H20-0O2 system. Brantley (2008) found that for pH lower than 3.5, calcite dissolution can be mass transport-controlled whereas it can be reaction rate limited (at the interface) at higher pH. They mentioned, from a rate-limiting step perspective, that since the activation energies of interface reactions are generally high leading to surface reactions being the rate-limiting step over than of mass transport, increasing the temperature might change the process from being reaction rate limited to transport limited.
Pokrovsky et al. (2009) investigated the effect of pH and partial pressure of on kinetics of calcite dissolution in the temperature range from 25 C to 150 C.
They found that the higher the pH, the lower the activation energy of calcite dissolution. They also concluded that an increase of CO2 partial pressure can decrease the dissolution rate. They also found that changes of temperature may not significantly affect the dissolution rate of calcium carbonate.

[00012] During the SAGD process, the steam and produced CO2 from aquathermolysis and rock-steam reactions within the formation can lead to a steam-condensate-rock system that can affect heat transfer (partial pressure effects due to generated gases), oil mobility (002 dissolution in oil phase leading to reduction of oil viscosity), oil swelling (002 dissolution in oil phase), and formation porosity and permeability (due to precipitate formation in the pore space), which consequently can affect the growth of the steam chamber and oil recovery. It would therefore be advantageous for a method to consider such WSLEGAL\045074\00165\13492436v3 , , interactions occurring in the steam chamber for establishing the possible relationships between steam chamber growth and the intensity of the reactions.

[00013] Steam-rock reactions, water geochemistry, and how the produced water composition varies as the thermal recovery process evolves are issues which may not have gained significant attention. As the steam interacts with oil and the multiple rock types within the reservoir, reaction products formed within the reservoir accumulate within the steam chamber and are produced with the produced oil and steam condensate. While the shale layers can contain concentrations of calcium carbonate, the oil sand typically does not. It would therefore be advantageous for there to be a method that considered such produced water compositions so as to provide information about the evolution of the steam chamber within the reservoir and to help characterize the shale layer heterogeneity of the reservoir.
SUMMARY OF THE INVENTION

[00014] The present invention generally relates to the field of oil and gas subsurface earth formation evaluation techniques and methods for estimating properties of a subterranean formation.

[00015] In one aspect, the present invention comprises a method for using produced water analysis during a thermal heavy oil and bitumen recovery technique to provide information about the evolution of the steam chamber within the reservoir and to help characterize the reservoir.

[00016] In a particular aspect, the present invention comprises methods for using the produced water compositions for detecting shale barriers and contact of the steam chamber with the overburden in the reservoir.

[00017] In a further aspect, the present invention provides a method for analysing produced water compositions so as to provide information about one or more of the size and extent of any shale layer in the reservoir, the proximity of the shale WSLEGAL \045074 \ 00 I 65 \13492436v3 , layer to the production well, the thickness of the shale layer, the number of shale layers in the reservoir and/or contact of the steam chamber with the overburden.

[00018] Additional aspects and advantages of the present invention will be apparent in view of the description, which follows. It should be understood, however, that the detailed description and the specific examples, while indicating preferred embodiments of the invention, are given by way of illustration only, since various changes and modifications within the spirit and scope of the invention will become apparent to those skilled in the art from this detailed description.
BRIEF DESCRIPTION OF THE DRAWINGS

[00019] The subject matter which is regarded as the invention is particularly pointed out and distinctly claimed in the concluding portion of the specification.
The invention, however, may best be understood by reference to the following detailed description of various embodiments and accompanying drawings in which:

[00020] FIG. 1 depicts a reservoir simulation model for eight reservoir cases including SAGD well pair position and shale layer location and geometry;

[00021] FIG. 2 is a chart of cumulative oil production and steam to oil ratios over time for each of the eight cases of FIG. 1;

[00022] FIG. 3 is a chart of the calcium production rate for cases 1, 2 and 3;

[00023] FIG. 4a depicts a steam chamber (water phase mole density) at the beginning of calcium production time for case 2;

[00024] FIG. 4b depicts a steam chamber (water phase mole density) at the beginning of calcium production time for case 3;

[00025] FIG. 5 is chart of the calcium production rate for cases 3, 4 and 5;

WSLEGAL\045074\00165\13492436v3

[00026] FIG. 6 is a chart of the first peak response versus shale layer volume for cases 3, 4 and 5;

[00027] FIG. 7 is a chart of the calcium production rate for cases 4 and 6;

[00028] FIG. 8 is a chart of the calcium production rate for cases 5 and 7;

[00029] FIG. 9 is a chart of the calcium production rate for cases 4 and 8;

[00030] FIG. 10 is a chart of the cumulative produced amount of calcium versus shale volume at day 900;

[00031] FIG. 11 is a chart of the cumulative methane production for each of cases 1 to 8;

[00032] FIG. 12 is a chart of the cumulative carbon monoxide production for each of cases 1 to 8;

[00033] FIG. 13 is a chart of the cumulative carbon dioxide production for each of cases 1 to 8;

[00034]FIG. 14 is a chart of the cumulative hydrogen production for each of cases 1 to 8;

[00035] FIG. 15 is a chart of the cumulative hydrogen sulphide production for each of cases 1 to 8;

[00036] FIG. 16 depicts the steam chamber development for a system having three shale layers;

[00037]FIG. 17 is a chart of the calcium production rate for a case with three shale layers; and

[00038] FIG. 18 is a flow chart illustrating one embodiment of a method for determining a property of subterranean formation.
DESCRIPTION OF PREFERRED EMBODIMENTS

WSLEGAL\045074\00165\13492436v3

[00039] The present invention generally relates to the field of oil and gas subsurface earth formation evaluation techniques and particular methods for estimating properties of a subterranean formation during a thermal heavy oil and bitumen recovery technique. Suitable recovery techniques for use in conjunction with the present invention can generally include a thermal process in which steam is injected into a reservoir so as to heat the hydrocarbon product within, such as bitumen, and lower its viscosity sufficiently to enable oil flow to a production well.
Examples of such thermal recovery methods can include SAGD, Cyclic Steam Stimulation (CSS), steam flood, etc. The thermal recovery technique can also include steam-solvent processes in which solvent is used in the presence of steam.

[00040] Before the present invention is described in further detail, it is to be understood that the invention is not limited to the particular embodiments or examples described, and as such may, of course, vary. It is also to be understood that the terminology used herein is for the purpose of describing particular embodiments only, and is not intended to be limiting, since the scope of the present invention will be limited only by the appended claims.

[00041] Unless defined otherwise, all technical and scientific terms used herein have the same meaning as commonly understood by one of ordinary skill in the art to which this invention belongs. Although any methods and materials similar or equivalent to those described herein can also be used in the practice or testing of the present invention, a limited number of the exemplary methods and materials are described herein.

[00042] It must be noted that as used herein and in the appended claims, the singular forms "a", "an", and "the" include plural referents unless the context clearly dictates otherwise.

[00043] The recovery of heavy oil and bitumen can be a complex process, requiring the use of particular products and services built for specific conditions, as these hydrocarbon products can be extremely viscous at reservoir conditions.

WSLEGAL\045074\00165\13492436v3 Heavy oil and bitumen viscosity decreases significantly with increases in temperature, and as such, thermal recovery methods such as SAGD, are commonly employed.

[00044] In order to reduce the viscosity of the oil using the SAGD process, steam at high pressure, typically between about 1 to about 5 MPa, and at high temperature, typically between about 185 C and about 250 C, is injected into the reservoir. Steam can be injected into the reservoir through a top well whereas fluids, including steam condensate and mobilized bitumen, may then be produced through a lower well to the surface.

[00045] During the SAGD process evolution, geochemical reactions between rock and steam can arise with variations to the geochemistry and the produced water composition occurring. The changes in the mineral content of the produced water can be due, for example, to the different sets of chemical reactions between the steam chamber and formation layers, which represent the reservoir heterogeneity.

[00046] In accordance with an embodiment of the present invention, methods are provided for the retrieval and analysis of the produced water during a thermal heavy oil and bitumen recovery process, such as SAGD. Such methods can generally provide information about the evolution of the steam chamber within the reservoir and assist in characterizing the reservoir. Given that many oil sands reservoirs are strongly heterogeneous with shale layers within, the use of water geochemical data to provide information about the heterogeneity of the reservoir aids in understanding steam conformance within the reservoir. In a particular aspect, the present invention can comprise methods of using water geochemical data to identify and index shale layers in an oil sands reservoir.

[00047] In a particular embodiment, the present invention can include methods for providing information about the size and extent of a shale layer in the reservoir. In another embodiment, methods of the present invention can be used to provide an index as to the proximity of the shale layer to the production well. In WSLEGAL\045074\00165\13492436v3 another embodiment, the present invention can include methods for providing an index as to the thickness of a shale layer in the reservoir.
In a further embodiment, the present invention can include methods for determining the number of shale layers in a reservoir. In other aspects, the methods of the present invention may be used to relate the time point at which the steam chamber reaches the caprock.

[00048] In a SAGD steam chamber, geochemical reactions between rock and steam in the presence of CO2 (due to aquathermolysis reactions) can take place which can affect the growth and shape of the steam chamber and alter the porosity and permeability and oil and water saturations within the chamber.
Two sets of reactions that can occur are thermal cracking of the oil and aquathermolysis. However, as thermal cracking becomes significant above 300 C, it is thus not a major contributor to SAGD at typical steam injection conditions (usually <250 C). On the other hand, aquathermolysis typically occurs between about 180 C and 300 C and thus it should be included in the set of reactions. The aquathermolysis reactions as used herein are as disclosed by Kapadia et al. (2012, 2013).

[00049] As the steam chamber interacts with the reservoir, the mineralogical difference between shale layer baffles or barriers and the bitumen bearing sand can yield different water compositions, which can drain as condensed water vapor with different mineral contents to the production well. A common component of shale is quartz and calcite. Thus, a key differentiator between the sand intervals and shale in an oil sands deposit can be the presence of calcite in the shale layers.

[00050] The major reactions between 002, calcium carbonate, and hot water (formation water and steam condensate) can be described as follows:
002+ H2O 4-7) H2003 t H + HCO3-(1) CO2 + Oft t; HCO3- (2) WSLEGAL\045074\00165\13492436v3 CO2 + H20 + CaCO3 Ca2+ + 2HCO3-(3)

[00051] Reactions (1) may be more pronounced when the pH value of the water is less than 7. Reaction (2) may be dominant for systems when the pH value is greater than 7. H2CO3 in reaction (1) may be dealt with as an intermediate product and was not considered for the kinetic model. The reaction rate constants for reactions (1) and (2) can be described as follows:
ki = 10-3 exp(934.69 ¨ 9252 T1) (4) 7H+ 7HCO3- (Ko/K5) (5) log k2 = 14.072 ¨ 3025 T-1 (6) k-2 = k2 (21-1, I 7Hc03) Kw (Ko/K5) (7) Ko = K5/K6 (8) K5 = 1.707x10-4 (9) log 1<6 = -356.3094 + 21834.37T-1¨ 0.060919964 T+ 126.8339 log T¨ 1684915 T-2 (10) log Kw = 22.801 ¨4787.3 T1¨ 0.010365 T-7.1321 log T (11) WSLEGAL\045074\00165\13492436v3

[00052] Ko, 1<5, and ic are empirical mass balance constants (based on activities rather than concentration) which depend on temperature, described by Buhmann and Dreybrodt (1985). y is the ionic activity coefficient given by Kiel land (1937).

[00053] Reaction (3) presents the dissolution and precipitation reactions associated with Ca2+ conversion from CaCO3. Under the assumption that the CO2 partial pressure is higher than 0.05 atmospheres and there are no mass transfer limitations (sufficient diffusion due to relatively high porosity and permeability in the reservoir sand), the reaction rate constants for reaction (3) can be described as follows:
log k3 = 0.198 - 444 T-1 (12) log k'3 = 2.84 - 2177 T1 (13) log k"3 = -5.86-317 T1 (14) log k_3 = -2.375 + 0.025 7-, (15)

[00054] k, is the reaction rate constant for the forward reaction of reaction (1) and k1 is the reaction rate constant for the reverse reaction of reaction (1), T
is temperature in Kelvin and 7-, is temperature in degrees Celsius. For reaction (3), k3, k'3 and k"3 shows the reaction rate constants at slightly acidic, basic and neutral medium of forward reaction respectively and k-3 represents the general reaction rate constant for reverse reaction. According to Buhmann and Dreybrodt (1985), the left side of Reaction (1) may be slow, whereas the right side may be fast. Reactions (1), (2) and (3) can be written in expanded form as listed in Table 1.

Major reactions in CO2-rock-steam media Reaction Reaction Reaction rate number constant 1 CO2 + H20 H+ + HCO3-k1 2 H+ + HCO3- -o CO2 + H20 k-3 CO2 + OH- -0 HCO3-k2 4 HCO3- --o CO2 + OH- k-5 CO2 + H20 + CaCO3 Ca2+ + 2HCO3-k3 WSLEGAL \ 045074 \ 00165 \ 13492436v3 6 CO2 + H20 + Ca003 Ca' + 2H003- k'3 7 CO2 + H20 + Ca003 Ca2+ + 2HCO3- k"3 8 Ca2+ + 2HCO3 CO2 + H20 + CaCO3 k_3

[00055] The rate constants can be given by the Arrhenius equation as follows:
k= A e-EIRT
(16)

[00056] Table 2 lists the kinetic parameters which were estimated from the literature mentioned above.

Kinetic parameters for Equations (4) to (11) Reaction Activation energy (J/.mol) Pre-exponential factor number (1/day) 1 76921.1 7.43x10-8 2 75082.9 8.96x10-14 3 57909.5 7.32x10-10 4 108464.4 4.57x10-11 5 8499.4 5.48x104 6 41669.8 1.25x102 7 6068.6 6.26x1010 8 48955.3 1.36x10-2 WSLEGAL\045074\00165\13492436v3

[00057] The activation energy for the precipitation reaction listed in Table 2 estimated here is comparable with the apparent activation energy for the calcite precipitation reaction equal to 46 4 kJ/mol reported by Nancollas and Reddy (1971).
EXAMPLES

[00058] A two-dimensional reactive-thermal SAGD model was constructed to evaluate the effect of rock-0O2-wet steam reactions on water composition and steam chamber evolution. The reaction scheme, as provided in Table 1 and their calculated kinetic parameters, as provided in Table 2, were encoded within a commercial thermal reservoir simulator (CMG, 2013) to construct the two-dimensional reactive-thermal SAGD model.

[00059] The reservoir simulator can calculate the material balance equation for each component within each phase (oil, water, and gas):
- - = =
a x xoipoSo y jpgSg 111j¨ Mir ¨at 0 mwo mwg mw, _ ( kõ 'ow V ____________________ c ( VP y V z)l- DV ___ (17) koPo + c (VPõ x)Vz)+ Def/V P0x0J
14õ mw \. 0 kgpg eff PgY
gi + _______________________________ c \21'g ygVz)+Dg,V
MW, \ 0 and energy balance accounting for all phases:
a rt ¨ 0)Mr ¨Tref 0(S.põUõ +SopoUo+SgpgU A-EQ.
at -v.[ ¨km,VT + põuõCõfr pou0C0(T ¨Tjej)+ pgu gC gfr ¨Tõf)]
(18) WSLEGAL\045074\00165\13492436v3

[00060] Flow of oil, gas and water phases can be governed by multiphase version of Darcy's law and the governing equations were calculated by using the finite volume method (CMG, 2013).

[00061] The reservoir domain was modeled into fifty-eight 0.8 m grid blocks in the cross-well direction and by sixty 0.5 m grid blocks in the vertical direction (Cartesian grid configuration) with the top of the formation at 200 m depth below the surface. The length of the SAGD wellpair was equal to 750 m. The oil column thickness was set equal to 30 m. Initially, the reservoir water had a pH
around 7 (neutral).

[00062] Tables 3 and 4 list the bulk reservoir properties and properties of shale layers within the formation, respectively.

Input data for bulk reservoir in SAGD reactive reservoir simulation model Parameters (Reservoir) Value Two-dimensional grid and dimensions 58 x 0.8 m by 60 x 0.5 m SAGD wellpair length, m 750 Horizontal permeability, mD 4000 Vertical permeability, mD 2000 Average porosity 0.3 Initial oil saturation 0.75 Initial water saturation 0.25 Irreducible water saturation 0.15 Residual oil saturation with respect to 0.20 water Relative permeability to oil at irreducible 1.0 water Relative permeability to water at residual 0.992 oil Critical gas saturation 0.005 Residual oil saturation with respect to 0.005 gas Relative permeability to gas at residual 1.0 oil Relative permeability to oil at critical gas 0.992 Critical gas saturation 0.005 Initial temperature, C 20 Initial pressure, kPa 2000 Rock heat capacity, J/m5 C 2.600x106 Rock thermal conductivity, J/m day C 6.600x105 Water phase thermal conductivity, J/m 5.350x104 day C

WSLEGAL\045074\00165\13492436v3 Oil phase thermal conductivity, Jim day 1.150x104 C
Gas phase thermal conductivity, Jim day 5.000x103 C
Bitumen Molecular weight, kg/kmol 465 Critical temperature, C 903.85 Critical pressure, kPa 792 Viscosity, cP versus Temperature, C 10 1,587,285 100 203.91 200 9.71 Input data for shale layer in SAGD reactive reservoir simulation model Parameters (Shale) Value Horizontal permeability, mD 20 Vertical permeability, mD 10 Average porosity 0.04 Initial oil saturation 0 Initial water saturation 1 Irreducible water saturation 0.35 Initial temperature, C 20 Initial pressure, kPa 2000 Rock heat capacity, J/m3 C 3.328x106 Rock thermal conductivity, Jim day C 1.900x106 Shale water composition, mole fraction Water 0.3 HCO3- 0.3 H+ 0.1 OH- 0.1 Ca2+ 0.2

[00063] The definitions of the symbols used herein are found below in Table 7.

[00064] Referring now to FIG. 1, in accordance with the present invention, a cross-sectional view of a reservoir grid for a symmetrical two-dimensional reservoir simulation model is shown that depicts the positioning of a SAGD
injector and producer well pair and the location and geometry of the shale layers within the reservoir. Eight separate reservoir examples are shown to demonstrate the effect of shale geometry and its chemical composition on the steam chamber.

[00065] Beyond the modeled part of the caprock, heat losses were permitted and were approximated by using Vinesome and Westerveld's (1980) heat loss model.
At the bottom boundary, heat losses were permitted and were also approximated WSLEGAL\045074\00165\13492436v3 by using Vinsome and Westerveld's (1980) model. At the sides of the model, symmetry conditions were applied (no flow and zero heat transfer). The physical properties of the caprock and shale layers were the same.

[00066] To initialize the SAGD wellpair, as is done in field operations with steam circulation, a pre-heating period, such as for example 90 days, is typically conducted so as to heat the oil between the injection and production wells. In the model, this was done by using temporary line heaters that were located in the trajectories of the wells. After the temperature is sufficiently high in the oil sand between the wells, the viscosity of the oil between the wells is low enough to be mobilized when steam is injected into the upper well and fluids are produced through the lower well. In the reservoir simulation model, during SAGD
operation, steam was injected into the upper well at 400 m3/day (expressed as cold water equivalent, OWE) with steam quality equal to 95%. At the production well, it was operated with a maximum steam rate constraint (OWE) equal to 1 m3/day to mimic steam-trap control.

[00067] Referring again to FIG. 1, of the eight reservoir examples shown, case represents a base case comprising a homogeneous reservoir without a shale layer. Each of the eight cases represent reservoirs sealed with shale layer caprock at the top of the reservoir, with the modeled portion of the caprock having a thickness equal to about 2.5 m.

[00068] The shale layers have the same thickness, same horizontal extent, and same horizontal distance from the injection and production well pair with respect to cases 2 and 3, while in case 1 there is no shale layer is present. With regard to cases 4 and 5, the thickness of the shale layers have been increased by a factor of four and eight, respectively, from that of cases 2 and 3. The horizontal extent of shale layer, thickness and vertical distance between shale layer or the well pair have been changed in cases 6, 7 and 8 versus the previous cases.

[00069] Referring now to FIG. 2, a chart of cumulative oil production and steam to oil ratios (SOR) for the eight cases are depicted. The cumulative oil production WSLEGAL\045074\00165\13492436v3 is depicted by a solid line, whereas a dashed line represents the SOR. It can generally be seen that the greater the volume of shale in the reservoir, the greater the SOR and the lower the cumulative oil produced from the reservoir. This result can arise because the steam will heat the volume of shale and yet no oil may be produced from it. Doubling of the grid in both vertical and cross-well directions can result in changes to the liquid and gas production rates and cumulative steam-to-oil ratios of less than about 0.001%. Thus the grid was considered to be sufficiently converged with respect to the dimensions of the grid blocks.

[00070] The SOR, as shown by FIG. 2, can range from about 3 to about 4.8 m3/m3 for most of the cases during mature production, such as after the chamber has become firmly established in the reservoir. The SOR for each of the cases are generally quite consistent with SAGD operations in the field. This may imply that the carbon intensity of these processes can range from about 600 to about 1,000 kgCO2eq/m3 oil produced, respectively. This may also imply that the energy return from these processes may vary from about 3.8 to 2.4 GJ out, in the form of chemical energy, per GJ invested in the process in the form of steam, respectively.

[00071] FIG. 3 is a chart of the calcium ion production rate for cases 1, 2 and 3.
Substantial changes to the rate of calcium production can be seen in each of the cases. As the initial 90 days represents the preheating period, changes in the calcium ion production rate during this period were not expected. With regard to case 1 in which no shale layer was present, calcium ion production started at about day 500, corresponding with the time that the steam chamber reaches the caprock. For case 2, in which the shale layer was located close to the depth of the injection well, calcium production began after about 215 days, or about days after the commencement of the SAGD mode. With respect to case 3, in which the shale layer was located about 7.25 m above the injection well, the changes in the calcium production rate began at about day 280, which corresponds to about 190 days after commencement of SAGD mode.

WSLEGAL\045074\00165\13492436v3

[00072] FIGS. 4a and 4b depict the steam chamber (water mole density) at the beginning of calcium ion production time for cases 2 and 3, respectively. The onset of calcium ion production corresponds to the time at which the steam chamber is in contact with the shale layer. FIG. 4a shows case 2 at about day 215, or after about 125 days of SAGD operation. FIG. 4b shows the extent of the steam chamber (water mole density) for case 3 at day 280, or after 190 days of SAGD operation.

[00073] The surge in calcium ion production can be directly associated with chemical reactions (1), (2) and (3), as disclosed above, which generate calcium ions when the steam contacts the shale layers. The ions can then be washed from the shale layer and drained with steam condensate to the bottom of the steam chamber to be produced to the surface by the lower well. After the steam chamber has reached the caprock, the production of calcium ions continues to grow. Referring back to FIG. 3, it can be seen that calcium ion production begins at about day 500 for case 1, which is the day that the steam chamber contacts the caprock. With regard to case 2, the shale layer is closer to the injector well, and the period of time over which calcium ion extraction occurred was at about day 215 to about day 745. After about day 745, the steam chamber passed the shale layer and started extracting calcium ions from the caprock until about day 860.
Beyond about day 860, the steam chamber has extracted the calcium ions from the caprock layer directly exposed to the chamber, and thus the generation rate drops. With respect to case 3, the onset of calcium ion production coincides with the steam chamber reaching the shale layer. As the shale layer in case 3 is closer to the caprock and farther from the well pair than case 2, the calcium production begins later, at about day 280, and the chamber reaches the caprock before the shale layer is exhausted of freely available calcium ions.

[00074] FIG. 5 depicts the calcium ion production rate for each of cases 3, 4 and 5. Cases 4 and 5 comprise shale layers having a thickness increased by a factor of four (case 4) and eight (case 5) from that of case 3. The top location of the shale layer is the same for each of cases 3, 4 and 5. However, the bottom shale WSLEGAL\045074\00165\13492436v3 , layer locations each differ, resulting in different distances to the well pair. The results demonstrate that the greater the thickness of the shale layer, the larger the calcium ion generation response. As well, the closer the shale layer is to the production well, the sooner is the response.

[00075] FIG. 6 depicts the first peak response against the volume of the shale layer for each of cases 3, 4, and 5. As shown, the peak correlates with the volume of the shale layer. Accordingly, this may have important implications on the use of produced water geochemical information, in that the peak may be used to index the relative sizes of shale layers.

[00076] Referring now to FIG. 7, depicted therein is a chart of the calcium production rate for each of cases 4 and 6. The main difference between each case is in regard to the horizontal extent of the shale layers. The nearest distance of the shale layer to the production well in each case is the same, and thus, the onset of calcium ions is about the same at about Day 200. However, as the layer extents differ horizontally, the response profile for case 6 is slightly elevated over that of case 4, until the time the steam chamber starts producing calcium ions from the caprock. At that point, the calcium ion production rate for case 4 is shown to be slightly higher than that of case 6, as it is easier for the steam chamber to pass the shorter shale layer in case 4. Accordingly, the gap between the curves can provide an index on the horizontal extent of the shale layers.
However, by comparing FIGS. 5 and 7, it can be seen that changes in shale layer thickness can affect the calcium production response more significantly than variations in horizontal extent.

[00077] FIG. 8 depicts a chart for the calcium ion production rate for each of cases 5 and 7. The main difference between cases 5 and 7 is in the thickness of the shale layers. The shale layer is thicker for case 5 than in case 7, while the bottom of each shale layer are the same location and distance from the well pair.
As shown, the commencement day for calcium ion production and the time period over which the calcium ions are extracted from the shale layers are almost the WSLEGAL\045074\00165\13492436v3 same in each case. However, the peak height for case 5 is about 3 times that of the peak height for case 7. Accordingly, this provides additional support that the peak height can be directly related to the thickness of the shale layer.

[00078] Referring now to FIG. 9, depicted therein is a chart of the calcium ion production rate for each of cases 4 and 8. The main difference between each case is in the thickness of the shale layers. The thickness of the shale layer for case 8 is about two times as thick as that of case 4. As the proximity of the bottom of the shale layer to the production well is the same for each case, the increase in calcium production rate began at about the same time. The peak in case 8, however, is almost 5.2 times as high than that of case 4, which can indicate the greater thickness of the shale layer in case 8. By about day 630 in case 8, the generated calcium ions are mainly sourced from reactions occurring at the caprock.

[00079] FIG. 10 depicts the cumulative calcium ion production for each of cases 2 to 8 against the shale volume at day 900. The cumulative produced amount of calcium ions, can be calculated by integrating the area under the plot of calcium production rate versus time. Case 2 has the same shale volume as Case 3, whereas case 4 and case 7 also have the same shale volume. As shown, in cases with the same shale volume, the closer the shale layer is to the well pair, the greater the cumulative amount of calcium ions produced. In case 6, a greater horizontal extent of shale layer can act as a baffle for the steam chamber to reach the caprock, as well as obstructing the complement of reactions within the shale layer. Accordingly, such results can be used in conjunction with core, log, and seismic data to understand heterogeneity of the reservoir along with its impact on steam conformance around the well pair. Also it can be used as a tool to indicate the presence of shale layers that the steam chamber is encountering as it grows within the reservoir.

[00080] Figures 11 to 15 depict the cumulative production of CH4, CO, 002, H2 and H2S respectively, for each of cases 1 to 8. These gases can be produced as WSLEGAL\045074\00165\13492436v3 a result of aquathermolysis reactions and geochemical reactions as disclosed in Table 1. As shown, the lowest cumulative gas productions belong to case 8 followed by case 5. This result can indicate that the larger the thickness of the shale layer, the lower the amount of gas production. This result can be due to the capability of gas sequestration within shale volume. As shown, case 2 has the greatest amount of gas production, as it has the closest shale layer to the well pair, and there is lesser room for holding gaseous product due to the smaller thickness of the shale layer. The sequence of cumulative gas production for each of the gases shown in FIGS. 11 to 15 are generally the same, with the exception of case 1, where there is no shale layer in the reservoir.

[00081] In three-dimensional systems, with discrete shale layers distributed within the reservoir, as the steam chamber intersects with each shale layer, the calcium ion response from the production well will be the superposition of all of the responses of each of the steam chamber interactions with the shale layers.
Thus, the signal from the reservoir can become more complex to interpret.
However, the first onset and subsequent step changes of calcium ions production can indicate when the first shale layer and then subsequent ones are reached by the steam chamber. Thus, providing an index of heterogeneity of the reservoir.

[00082] FIGS. 16 and 17 depict instances in which the reservoir comprises three shale layers. FIG. 16 shows the evolution of the steam chambers, as indicated by the water mole density. FIG. 17 depicts the calcium ion production profile for this case. There are three peaks shown with regard to the calcium ion production rates. A comparison of the results shown in FIGS. 16 and 17 demonstrate that the first peak, at about day 150, can be associated with the chamber reaching the second shale layer from the bottom. By about day 370, the steam chamber has not enveloped but has touched the bottommost shale layer, as depicted by the second peak in FIG. 17. The third peak represents the beginning of the envelopment of the topmost shale layer at about day 680.
The results demonstrate that as the number of shale layers increases, the calcium ion profile can become more complex.

WSLEGAL\045074\00165\13492436v3 ,

[00083] Goodman et al. (2010) investigated the produced water hardness in SAGD facilities and reported the average value of 140 to1400 mg/I as alkalinity as CaCO3. Table 5 represents the values reported for alkalinity of produced water as CaCO3 from field data of SAGD projects. The alkalinity of the produced water in Cases 1 to 8 was calculated and compared with the published data by ConocoPhillips to confirm the reliability of the generated data as produced ions by simulation. In the report presented by ConocoPhillips to the Alberta Energy Regulator, the alkalinity of produced water as CaCO3 was stated to be equal to 228.5 mg/I for the Surmont SAGD project. This alkalinity is close to the alkalinities listed in Table 6 obtained from the reactive thermal reservoir simulation model.
This can demonstrate that the produced amount of calcium ions which strongly depends on other produced ions, as obtained from the model, can be reliable as well.

Alkalinity of produced water as CaCO3 from field data Reference Alkalinity as CaCO3, mg/I
Goodman et al. 140-1400 ConocoPhillips ¨ Surmont 228.5 SAGD project Alkalinity of produced water based on the produced amount of basic ions after about 2.5 years of production Cases Produced amount Produced Produced Alkalinity as of HCO3, m3 amount of OH-, water, m3 CaCO3, mg/I
m3 Case 1 1107.1 271.6 150158 227.2 Case 2 1144.0 271.5 152070 228.3 Case 3 945.5 240.3 152335 194.5 Case 4 1024.0 248.3 153793 204.1 Case 5 1193.7 262.9 154749 226.3 Case 6 989.2 240.6 153675 197.6 Case 7 1135.9 263.0 153608 221.9 Case 8 1080.7 239.2 155826 203.9 WSLEGAL \ 045074 \ 00165 \ I 3492436v3

[00084] Referring now to FIG. 18, depicted therein is an example of the implementation of a method of the present invention.

[00085] Method 100 generally commences at step 102. A hydrocarbon recovery method for the recovery of a viscous hydrocarbon product, such as for example bitumen, from a subterranean formation can be initiated at step 104. In a particular embodiment of the present invention, the recovery method employed comprises a thermal recovery process, such as a SAGD process. The SAGD
process employed can include, for example, two horizontal wells in the subterranean formation, located one atop of the other. Steam can be injected into the reservoir through the top well, whereas fluids, including steam condensate and mobilized bitumen, may then be produced through the lower well to the surface. At step 104, steam at high pressure, for example, between about 1 MPa to about 5 MPa, and at high temperature, for example between about 185 C to about 250 C can be injected into the reservoir through the top well. A pre-heating step for a period of, for example 90 days, may be initially conducted so as to heat the hydrocarbon product between the upper (injection) and lower (production) well pair. Once the temperature is sufficiently high, the viscosity of the hydrocarbon product between the wells may be low enough so as to be mobilized when the steam is injected into the upper well and the fluids are produced through the lower well.

[00086] As the steam interacts with the viscous hydrocarbon product and the multiple rock types within the reservoir, reaction products are formed within the reservoir and accumulate within the steam chamber and are produced with the produced oil and steam condensate from the production well.
After commencement of the hydrocarbon recovery process of step 104, production from the reservoir may be initiated and formation fluid samples may be retrieved at step 106. The formation fluid sample can comprise produced water that further comprises one or more components of interest. Suitable components in accordance with an embodiment of the present invention can include calcium, WSLEGAL\ 045074 \ 00165 \13492436v3 methane, carbon monoxide, carbon dioxide, hydrogen, hydrogen sulphide, or any combination thereof. The formation fluid samples may be collected over a period of time. In some embodiments, the samples may be collected weekly, or monthly, for example. In an embodiment, the collection of the samples may occur throughout the course of the hydrocarbon recovery process, such as in certain instances, fifteen years or more.

[00087] The formation fluid sample may be analyzed and data derived, at step 108. In an embodiment, the derivation of the fluid sample data may comprise determining the presence or absence and/or concentration of one or more components of interest. Any suitable technique recognized by a person skilled in the art for determining the presence, absence or concentration of a desired component may be used. In some embodiments, the technique used may involve one or more of mass spectrometry (MS), high pressure liquid chromatography-mass spectrometry (HPLC-MS), titration, ion titration, plasma emission spectroscopy, ion chromatography, or atomic absorption spectroscopy.
After the analysis and data derivation of step 108, the data may be input into a model to determine one or more characteristics of the subterranean formation, in accordance with step 110. Additional base line data, can also be input into the model. The base line data can include previously determined data regarding the subterranean formation which may also be used as input for the reservoir model.
Previously determined data may include any data that provides physical information regarding a property of the subterranean formation, such as, for example, SAGD well pair length, initial formation water composition of the reservoir, initial reservoir pressure, initial reservoir temperature, horizontal and vertical permeability, average porosity, initial oil saturation, initial water saturation, residual oil saturation with respect to water, bitumen characteristics, etc.
and may include data related to shale layer.

[00088] In one aspect, the mineralogy of the formation and shale layers can be determined for making a benchmark of a component assumed to be available only WSLEGAL 045074 \ 00165 \ 13492436v3 in the shale layer and not along the reservoir. For example, the initial formation water composition may be used in determining the concentration and/or presence of a particular component of interest, such as calcium, for example.
Accordingly, base line data can include calcium ion concentration from the initial reservoir water, for example.

[00089] The produced water can be retrieved and analyzed, with changes to mineral or component content being monitored. The monitoring frequency can vary. For example, in various embodiments, monitoring may take place weekly, monthly, quarterly, or other frequency. Techniques for monitoring on-line may be used, for example. In accordance with the present invention, examples of water analysis methods can include, for example, laboratory testing of subterranean fluids and/or core samples, logging techniques, seismic techniques, reservoir modeling, etc.

[00090] Shale layers may be mapped to some extent from log and core data and thus, given the position and extent of shale layers and the placement of the SAGD
well pair, the evolution of the steam chamber may be estimated.
In an embodiment, the baseline data may be plotted against data for the produced water samples over a given period of time.

[00091] The usage of water geochemical data, prepared in step 108, may then be applied at step 110, to provide information about the heterogeneity of the formation. This can include for example, identifying and indexing shale layers in an oil sands reservoir.

[00092] Non-oil sands layers, such as shale layers, can be identified by a change of the produced water chemistry by more than about 25% from the base line value. For example, a change of the concentration of calcium ions in the produced water by more than 25% from the base line value would demonstrate that the steam chamber is interacting with a shale layer. If the change grows, this can indicate that the shale layer is more extensive since as the steam chamber is growing, it is interacting with more of the volume of the shale layer.

WSLEGAL\045074\00165\13492436v3

[00093] The severity of the response can be directly related to the size and extent of the shale layer. In general, the larger the calcium ion generation response peak the greater the thickness of the shale layer. As well, the calcium ion generation response width can provide an index as to the horizontal extent of the shale layer. In general, the greater the calcium ion generation response width the larger the horizontal extent of the shale layer. The changes in shale layer thickness, however, can affect the calcium production response peak. The beginning of the first peak response of calcium ions can also provide an index about the distance between shale layer and SAGD well pair. In general, the larger the peak the greater the thickness of the shale layer. As well, a wider first peak can demonstrate a greater horizontal distance of the shale layer.
In instances in which the horizontal extent of a shale layer can act as a barrier in a particular time window, the production of determined ion production can constantly increase, while when the shale layer acts as a baffle, the ion production increases and then decreases. The start of the ion production rate decrease can mean that the steam chamber passes the shale layer.

[00094] The onset of calcium production can correspond with the time at which the steam chamber is in contact with the shale layer. As well, the relative timing of the onset of calcium ion production can provide an index as to the proximity of the shale well to the production well. Generally, the sooner the calcium ion response, the closer the shale layer would be to the production well.

[00095] The cumulative production of CH4, CO, CO2, H2 and/or H2S can also be used to determine the heterogeneity of the reservoir. In general, a lower amount of gas production would indicate a greater thickness of the shale layer. This result can be due to the capability of gas sequestration within shale volume.

[00096] The number of peaks found in the calcium ion production rate can correlate with the number of shale layers. For instance, if there are multiple peaks within the evolution of the concentrations, this may indicate that the steam chamber is interacting with multiple shale layers and the number of peaks would WSLEGAL\045074\00165\13492436v3 be an indicator of the number of shale layers that are being interacted with.
After the concentrations return back to the base line value, then this can suggest that the steam chamber is no longer interacting with the shale layers, for example, that the steam chamber has fully surround the shale layer and that the reactions that can take place on the surface of the shale are done. The base line may change as the process evolves in the sense that the steam chamber at start will be small and the base line concentrations will have a particular initial set of values (for each species). If the chamber encounters a large shale layer, then the water concentrations can change and a new set of species concentrations will be achieved which may stay elevated over the initial base line for an extended period of time, thus forming a new base line. Thereafter, if the chamber encounters another shale layer, the concentrations may shift beyond that of the new base line indicating the new interaction.

[00097] In an aspect, the greater the peak response of the calcium ions in the produced water, the greater is the thickness and extent of the shale layer. If the response is, for example, over 100% greater than the baseline value, then the thickness of the shale layer can be estimated to be of order of about several meters thick. If it is of order of 25% greater than the baseline value, for example, the thickness of the shale layer can be an order of less than about 1 m thick.
In one aspect, if the response curve has a peak and then shifts to a plateau (with value greater than that of the baseline) over a period of about 50-100 days, the horizontal extent of the shale layer can be estimated to be of order of about m. If the decline from the peak value shifts back to the base line, then the shale layer may not be extensive and may be an order of about 10 m in extent. In an aspect, for each reservoir, the water chemistry response can be tuned to the specific reservoir by examining the log and core data to correlate the response to the specific thicknesses of the shale layers.

NOMENCLATURE
Symbol Definition, SI unit WSLEGAL\045074\00165\13492436v3 A Reaction frequency factor Cg Specific heat capacity of gas phase, J/(kg.K) Cgj Molal concentration of component j in gas phase, mol/kg Co Specific heat capacity of oil phase, J/(kg.K) coi Molal concentration of component j in oil phase, mol/kg Cw Specific heat capacity of water phase, J/(kg.K) cwi Molal concentration of component j in water phase, mol/kg Deff Effective diffusivity coefficient of component j in gas phase, m2/s Deff Effective diffusivity coefficient of component j in oil phase, m2/s De ff Effective diffusivity coeff. of component j in water phase, m2/s Activation energy, J/mol Reaction rate constant kg Gas permeability, m2 ko Oil permeability, m2 kTH Thermal conductivity of formation, W/(m.K) kw Water permeability, m2 rhi Removal rate of component], kg/(m3.$) Mir Generation rate of component/ due to reaction, kg/(m3.$) Empirical mass balance constant based on activity Mr Volumetric heat capacity, J/(m3.$) MWg Molecular weight of gas phase, kg/mol MVVi Molecular weight of component j, kg/mol MW0 Molecular weight of oil phase, kg/mol MW w Molecular weight of water phase, kg/mol Order of reaction Pg Pressure of gas phase, kg(m.s2) Po Pressure of oil phase, kg(m.s2) Pw Pressure of water phase, kg(m.s2) Input energy from a reaction per unit volume, J/(m3.$) Q, Input energy from a source per unit volume, J/(m3.$) Universal gas constant, J/(mol.K) WSLEGAL\045074\00165\13492436v3 Sg Gas saturation So Oil saturation Sw Water saturation Temperature at time t, K
To Temperature in degree Celcius, C
Time, s Tref Reference temperature, K
Ug Darcy velocity of gas phase, m/s Ug Internal energy of gas phase per unit mass, J/kg uo Darcy velocity of oil phase, m/s U0 Internal energy of oil phase per unit mass, J/kg uw Darcy velocity of water phase, m/s Uw Internal energy of water phase per unit mass, J/kg xoj Mole fraction of component j in oil phase xwj Mole fraction of component j in water phase Yl Mole fraction of component] in gas phase Length, m jig Viscosity of gas phase, kg/(m.$) po Viscosity of oil phase, kg/(m.$) pw Viscosity of water phase, kg/(m.$) Pg Gas phase density, kg/m3 po Oil phase density, kg/m3 Pw Water phase density, kg/m3 Ionic activity coefficient for ion i Specific gravity of gas phase 7o Specific gravity of oil phase Specific gravity of water phase Porosity v. Divergence operator V Gradient operator WSLEGAL\045074\00165\13492436v3

[00098] In the preceding description, for purposes of explanation, numerous details are set forth in order to provide a thorough understanding of the embodiments of the invention. However, it will be apparent to one skilled in the art that these specific details are not required in order to practice the invention.

[00099] The above-described embodiments of the invention are intended to be examples only. Alterations, modifications and variations can be effected to the particular embodiments by those of skill in the art without departing from the scope of the invention.
REFERENCES

[000100] All publications mentioned herein are incorporated herein by reference (where permitted) to disclose and describe the methods and/or materials in connection with which the publications are cited. The publications discussed herein are provided solely for their disclosure prior to the filing date of the present application. Nothing herein is to be construed as an admission that the present invention is not entitled to antedate such publication by virtue of prior invention.
Further, the dates of publication provided may be different from the actual publication dates, which may need to be independently confirmed.
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7575-9062-7. 2011.
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WSLEGAL\045074\00165\13492436v3 5. Nduagu El, Gates ID, Process analysis of a low emissions hydrogen and steam generation technology for oil sands operations. Applied Energy 2015; 146:184-195.
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HCO- -) CO2 + H20 as a rate limiting step. Geochimica et Cosmochimica Acta 1997; 61:3897-3904.
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30. Emberley S, Hutcheon I, Shevalier M, Durocher K, Mayer B, Gunter WD, Perkins EH, Monitoring of fluid-rock interaction and CO2 storage through produced fluid sampling at the Weyburn CO2 injection enhanced oil recovery site, Saskatchewan, Canada. Applied Geochemistry 2005; 20:1131-1157.
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WSLEGAL\045074\00165\13492436v3 32. Brantley SL, Kinetics of mineral dissolution. Kinetics of water-rock interaction, Chapter 5, Springer 2008;151-210.
33. Pokrovsky OS, Golubev SV, Schott J, Castillo A, Calcite, dolomite and magnesite dissolution kinetics in aqueous solutions at acid to circumneutral pH, 25 to 150 C and 1 to 55 atm pCO2: new constraints on CO2 sequestration in sedimentary basins. Chemical Geology 2009; 265:20-32.
34. Kapadia P, Wang J, Kallos MS, Gates ID, Practical process design for in situ gasification of bitumen. Applied Energy 2013; 107:281-296.
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Calcite growth mechanism. Journal of Colloid Interface Science 1971; 37:824-830.
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WSLEGAL\045074\00165\13492436v3 42. Alberta Energy Regulator Publications: ConocoPhillips Surmont Project.
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WSLEGAL\045074\00165\13492436v3

Claims

What is claimed is:

1. A method comprising:
introducing steam into at least a portion of a subterranean formation at a temperature and pressure sufficient to mobilize a hydrocarbon product therein;
recovering one or more initial fluid samples from the subterranean formation for determining base-line data for the subterranean formation;
recovering a plurality of formation fluid samples from the subterranean formation over time;
determining formation fluid data for one or more of the formation fluid samples and base line data for the one or more initial fluid samples; and determining the heterogeneity of the subterranean formation, at least in part, on the formation fluid data and the base line data.

2. The method of claim 1, wherein determining the formation fluid data for one or more of the formation fluid samples comprises analyzing the formation fluid sample to determine the presence, absence and/or concentration of a component.

3. The method of claim 2 wherein the component is selected from the group consisting of an ion, chemical, metal, soluble material, organic material, tracer, and a combination or derivative thereof.

4. The method of claim 3, wherein the component is selected from the group consisting of calcium, methane, carbon monoxide, carbon dioxide, hydrogen, hydrogen sulphide, and a combination or derivative thereof.

5. The method of claim 4 wherein analyzing the formation fluid sample comprises using at least one of the following: high performance liquid chromatography mass spectrometry (HPLC-MS), titration, ion titration, atomic absorption spectroscopy, inductively coupled plasma emission spectroscopy, infrared spectroscopy, nuclear magnetic resonance, ultraviolet spectroscopy, x-ray spectroscopy, visible spectroscopy, ion chromatography, and gas chromatography.

6. The method of claim 4, wherein the formation fluid data comprises one or more of component production rate over time, cumulative component production over time, one or more component peak responses, and component production response time.

7. The method of claim 6 wherein determining the heterogeneity of the subterranean formation comprises:
inputting the formation fluid data, the base line data into the reservoir model, plotting the formation fluid data against the base-line data; and determining the heterogeneity of the subterranean formation on the basis of the formation fluid data and the base line data for the subterranean formation.

8. The method of claim 7, wherein determining the heterogeneity of the subterranean formation comprises one or more of identifying presence of absence of one or more shale layers, approximating thickness for one or more shale layers, approximating horizontal extent for one or more shale layers, approximating proximity of one or more shale layers to a production well or well pair, and approximating number of shale layers in the subterranean formation.

9. The method of claim 8, wherein identifying the presence or absence of one or more shale layers is based on one or more of calcium production rate over time and cumulative calcium production over time.

10. The method of claim 9, wherein the presence of one or more shale layers is determined by an increase in formation fluid calcium concentration over the base line value for the subterranean formation by about 25% or greater.

11. The method of claim 8, wherein approximating the thickness for one or more shale layers is determined by one or more of calcium production rate over time, cumulative calcium production over time, cumulative methane production over time, cumulative carbon monoxide production over time, cumulative carbon dioxide production over time, cumulative hydrogen production over time, and cumulative hydrogen sulphide production over time.

12. The method of claim 11, wherein a greater calcium production rate or a greater cumulative calcium production corresponds to a greater shale layer thickness.

13. The method of claim 11, wherein a greater shale layer thickness corresponds to one or more of lower cumulative methane production, lower cumulative carbon monoxide production, lower cumulative carbon dioxide production, lower cumulative hydrogen production, and lower cumulative hydrogen sulphide production.

14. The method of claim 8, wherein approximating the proximity of one or more shale layers to a production well or well pair is based on timing of calcium production response.

15. The method of claim 14, wherein an earlier calcium production response time corresponds with a closer proximity of the one or more shale layers to the production well or well pair.

16. The method of claim 8, wherein approximating horizontal extent for one or more shale layers is based on calcium production rate over time, wherein greater calcium response corresponds to a greater horizontal extent.

17. The method of claim 8, wherein the number of shale layers in the subterranean formation is approximated by number of peaks in the calcium production rate.

18. A method of determining one or more approximate properties of a subterranean formation comprising:
obtaining base line data for initial fluid samples from the subterranean formation;
obtaining production water data for a plurality of produced water samples;
and using the production water data and the base line to estimate one or more properties in a subterranean formation.

19. The method of claim 18, wherein obtaining the production water data comprises analyzing the production sample to determine the presence, absence and/or concentration of a component selected from the group consisting of calcium, methane, carbon monoxide, carbon dioxide, hydrogen, hydrogen sulphide, and a combination or derivative thereof.

20. The method of claim 19, wherein the production water data comprises one or more of production rate over time, one or more peak responses, cumulative production over time, and production response time.

21. The method of claim 19, wherein approximating one or more properties of a subterranean formation comprises one or more of identifying presence of absence of one or more shale layers, approximating thickness for one or more shale layers, approximating horizontal extent for one or more shale layers, approximating proximity of one or more shale layers to a production well or well pair, and approximating number of shale layers in the subterranean formation.

22. The method of claim 21, wherein identifying the presence or absence of one or more shale layers is based on one or more of calcium production rate over time and cumulative calcium production over time.

23. The method of claim 22, wherein the presence of one or more shale layers is determined by an increase in formation fluid calcium concentration over base line value for the subterranean formation by about 25% or greater.

24. The method of claim 21, wherein approximating the thickness for one or more shale layers is determined by one or more of calcium production rate over time, cumulative calcium production over time, cumulative methane production over time, cumulative carbon monoxide production over time, cumulative carbon dioxide production over time, cumulative hydrogen production over time, and cumulative hydrogen sulphide production over time.

25. The method of claim 24, wherein a greater calcium production rate or a greater cumulative calcium production over the base layer value of the subterranean formation corresponds with a greater shale layer thickness.

26. The method of claim 24, wherein a greater shale layer thickness corresponds with one or more of lower cumulative methane production, lower cumulative carbon monoxide production, lower cumulative carbon dioxide production, lower cumulative hydrogen production, and lower cumulative hydrogen sulphide production.

27. The method of claim 21, wherein approximating the proximity one or more shale layers to a production well or well pair is based on timing of calcium production response.

28. The method of claim 27, wherein an earlier calcium production response time corresponds with closer proximity of the one or more shale layers to the production well or well pair.

29. The method of claim 21, wherein approximating the horizontal extent for one or more shale layers is based on calcium production rate over time, wherein greater calcium response corresponds with a greater horizontal extent.

30. The method of claim 21, wherein the number of shale layers in the subterranean formation is approximated by number of peaks in the calcium production rate.

31. A method of identifying the presence or absence of one or more shale layers in a subterranean formation comprising:
obtaining base line data for initial fluid samples from the subterranean formation;
obtaining calcium production rate data or cumulative calcium production data from a plurality of produced water samples over time; and determining the presence or absence of one or more shale layers in the subterranean formation, wherein an increase in formation fluid calcium concentration over the base line value by about 25% or more demonstrates the presence of one or more share layers.

32. A method for estimating the thickness of one or more shale layers in a subterranean formation comprising:
obtaining base line data for initial fluid samples from the subterranean formation;
obtaining calcium production rate data or cumulative calcium production data from a plurality of produced water samples over time; and estimating the thickness of the one or more shale layers, wherein a greater calcium production rate or a greater cumulative calcium production corresponds with greater shale layer thickness.

33. A method for estimating the thickness of one or more shale layers in a subterranean formation comprising:
obtaining base line data for initial fluid samples from the subterranean formation;
obtaining component data from a plurality of produced water samples over time, the component data comprising one or more of cumulative methane production, cumulative carbon monoxide production, cumulative carbon dioxide production, cumulative hydrogen production data, and cumulative hydrogen sulphide production; and estimating the thickness of the one or more shale layers, wherein lower cumulative component production corresponds with greater shale layer thickness.

34. A method for estimating the proximity of one or more shale layers to a production well or well pair in a subterranean formation comprising:
recovering a plurality of produced water samples from the subterranean formation over time;
analyzing the produced water samples for determining calcium concentration over time; and estimating the proximity of one or more shale layers to a production well or a well pair, wherein an earlier calcium production response corresponds to closer proximity.

35. A method for estimating the horizontal extent for one or more shale layers in a subterranean formation comprising:
obtaining base line data for initial fluid samples from the subterranean formation;

obtaining calcium production rate data from a plurality of produced water samples over time; and estimating the horizontal extent for the one or more shale layers, wherein a greater calcium production rate corresponds with a greater horizontal extent.

36. A method for estimating the number of shale layers in a subterranean formation comprising:
recovering a plurality of produced water samples from the subterranean formation over time;
analyzing the produced water samples for determining calcium production rate over time; and estimating the number of shale layers in the subterranean formation, wherein number of peaks in the calcium production rate corresponds with the number of shale layers.