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Shale characteristics impact on Nuclear Magnetic Resonance (NMR) fluid typing methods and correlations

Mohamed Mehanaa, Ilham El-monierb

 

 

 

aUniversity of Oklahoma, Suez  University, USA

bUniversity of Oklahoma, USA

Abstract

 

The development of shale reservoirs has brought a paradigm shift in the worldwide energy equation. This  entails developing robust techniques to properly evaluate and unlock the potential of those reservoirs. The  application of  Nuclear Magnetic Resonance techniques in  fluid typing and properties estimation is  well-developed in   conventional  reservoirs. However,  Shale reservoirs characteristics like  pore size,  organic matter, clay  content, wettability, adsorption, and mineralogy would limit the applicability of  the used interpretation methods and correlation. Some of  these limitations include the inapplicability of the controlling equations that were derived assuming fast relaxation regime, the overlap of different fluids peaks and the lack  of robust correlation to estimate fluid properties in  shale. This  study presents a  state-of-the-art review of  the main contributions presented on  fluid typing methods and correlations in both experimental and theoretical side. The study involves Dual   Tw, Dual   Te, and  doping  agent's  application,  T1-T2, D-T2 and  T2sec vs. T1/T2 methods. In addition, fluid properties estimation such as  density, viscosity and the gas-oil ratio is discussed. This  study investigates the applicability of  these methods along with a  study of  the current fluid properties correlations and their limitations. Moreover, it recommends the appropriate method and correlation which are capable of tackling shale heterogeneity.

1. Introduction

 

 

Since  the introduction of Nuclear Magnetic resonance technology in petroleum industry, its applications answered a lot of questions in  reservoir engineering and provided unambiguous techniques to evaluate rock, rock-fluid  and fluid properties. NMR  applications started with a  tool to calculate the total porosity independently  from rock matrix effects by calculating the  intensity of  hydrogen protons  in  formation. Then,  the differentiation between the bound and free  fraction of  fluid in  porous  medium  became obtainable. Further  improvements  were  performed  to   extend  its  applicability to determine  capillary pressure [1],  wettability [2],  and relative permeability  [3]   from  NMR   measurements.   Consequently, NMR  became a  reliable instrument  to  diagnose fluid types, properties, and rock  properties as  well for both conventional and unconventional reservoirs [4-8].

 

Counting  on  NMR methods used in  conventional reservoir to  determine rock  and fluid properties as  a  guide to  analyze shale reservoirs response is  misleading and will  yield unreliable  data [9]. In terms of composition, shale is a heterogeneous rock   with  various clay   contents  [10].   The   clay   distribution affects both NMR response and interpretation [11].  Apart from clay  content, the presence of the organic matter will  add more complexity to the system. Considering the pore size, shale has  a wide spectrum of  pore sizes ranging from nanometer  pores, conventional pores to natural fractures along with the dependence  of   the  organic pores  on   the  maturity  of   the  rock. Moreover,  shale has  different wettabilities and most of  them are  mixed [10].  Due  to  the complexity of the shale system, an extensive  study  of  rock   and  fluid  characteristics  impact is required to successfully interpret the NMR response.

 

 

2.  Theory

 

 

NMR measurements procedure starts with exciting the sample by a magnetic field,  which will polarize the hydrogen protons in  one direction. Then,   measuring the longitudinal relaxation time (T1) or use  Carr Purcell Meiboom Gill (CPMG) sequence and measure the transverse relaxation time (T2) or use  pulsed-field gradient  sequence  and  measure  the  diffusion coefficient (D) [12].  After that, an  inversion method will  be  adopted to  obtain the decay exponents distribution [13].  This  distribution will  be the base of all succeeding interpretation methods.

The relaxation of fluids in a bulk state is bulk relaxation and tends to be longer as the relaxation will  be due the interactions among fluid protons only.  On the other hand, fluids relaxation in porous media will  be  promoted by  the interactions among the fluids and the confining surface protons. Besides, the transverse relaxation time will be more affected by the molecules diffusion. The  diffusion relaxation will  not affect T1  measurement, but it influences T2  where there are  spin dephasing and refocusing [14]. The  relaxation  governing equations  in  porous  media  is developed in  fast  diffusion regime as  a  weighted average between bulk and surface relaxation rate. Therefore, they will  be

The validity of fast  diffusion regime assumption in shale will determine the applicability of those equations. In addition, the impact of the diffusion coupling, homonuclear dipole coupling, heteronuclear dipole coupling, residual dipole coupling and magnetization transfer as relaxation mechanisms should be considered [15].

 

 

3.  Shale characteristics impact on the NMR signals

 

 

Shale is a clay-rich rock which contains variable content  of clay  minerals and organic matter. This  rock contains different pore sizes which have fractional wettability and host different kinds of fluids. In addition, the Nano-scale pores and adsorption will add more ambiguity to the nature of these rocks. This section will discuss the main characteristics of Shale and their impact on NMR response.

 

 

3.1.  Pore  size

 

 

The behavior of fluids in confined porous media diverges from their behavior in  bulk state [16].  These deviances will  be  more significant in  Nano-scale pores (Fig. 1). Therefore, this entails a study of these deviances effects on  relaxation mechanisms.

Fig. 1. Sizes  of molecules and pore throats in  siliciclastic rocks on  a logarithmic scale. Measurement techniques are shown at the top of the graph [15].

In most conventional pores studies, it is assumed that the main relaxation mechanism is the surface relaxation. Therefore, the position of the fluid peak will  be directly proportional to the size  of the pore-containing that fluid. With this in  mind, many studies managed to  estimate pore size  distribution  from NMR. Moving into shale domain, the main relaxation mechanism will be  also  the surface relaxation. But  knowing that the relaxation interactions scale  is comparable to the scale  of pores investigated [6], will  render any  study of pore size  based on  NMR relaxation time useless. Since,  it is evident that Equation (2) is not valid  to calculate the relaxation time of water in Smectite interlayers [17]. Therefore, conventional surface relaxivity concept is not applicable in nano-scale pores anymore.

 

Furthermore,  the  heterogeneous distribution of  pore  size observed in shale would puzzle the interpretation scheme. Shale contains micro-pores in  the organic matter and nano-pores in the clay minerals and natural fractures [5]. The presence of these different pore size  scales in  one rock  complicates the interpretation process. As it  will  be  more challenging to  decide if the peaks  in   relaxation  time  distributions  are    resulting  from different pore sizes or from different fluids in these pores.

 

 

3.2.  Organic  matter and  clay  content

 

 

The organic matter and clay content are  considered as matrix constituents and hydrogen protons populations that affect NMR signal [6]. Therefore, the NMR response is not independent of the rock  matrix in  this case  [18].  The  organic matter  affects NMR signals in two ways directly as it is one of the proton population investigated and indirectly by controlling the relaxation time of the fluid contained in  the organic pores where it  acts   as  the relaxation surface. In  both cases, the effect of  organic matter depends on its maturity. Considering the direct effect, the degree of maturation is directly proportional to the mobility of protons [6]. Therefore, the organic matter signature of samples from gas, oil  or  immature windows will  not be  the same. Unfortunately, the organic matter response may be  masked if high hydrogen index fluid is present. On the other hand, the organic matter as a matrix contains organic porosity up  to  20.2% and average pore size approximately 100nm  [19]. Therefore, the surface relaxivity of organic matter and the interactions between the fluid and the surface need further investigation. As, Washburn [18]  suggested that the surface relaxation in organic pores depends on  the homonuclear dipole coupling among hydrogen protons in the fluid and the surface. In contrast to the surface relaxation in conventional  pores  where it is dominated by interactions  among fluid protons and paramagnetic impurities in the surface. Consequently, the  sample  organic content  and  maturation should be  investigated to  properly evaluate their effect. Fig. 2 shows the  morphology of  conventional and  unconventional pores through SEM images along with a schematic representation of shale structure.

Fig. 2.  (a)  represents a  comparison between  the  conventional sandstone and the  unconventional organic pores [20].  (b) Represents  schematic illustration of  shale morphology [21].

Clay   content   and   distribution   add  another   degree  of complexity for fluid identification in these heterogeneous reservoirs.  Similarly, clay  minerals are  one  of the proton population, which have NMR response and influence the responses of the attached fluid in  many different ways. Firstly,  the NMR response  of   clay    will    depend  on    their  distribution  and compaction  in   shale  [11].   If  the  clay   particles  present  in structural or laminar distribution, Their NMR response will  be below 0.1  ms  and will  require high resolution equipment to detect their signal [6]. However, if the clay  is dispersed, it will not produce a  separate signal,  but will  affect other fluids responses by  providing extra surface area for fluids to  relax on. Secondly,  the  type  of  clay   minerals present  will   affect  the wettability of the pores. Saada et al. [22]  explained that Illite  is water-wet while Kaolinite is hydrocarbon-wet. In addition, clay inter-layers  fluids will  also  exhibit restricted relaxation as  it will  be  bonded within the internal structure of  the molecule. Interestingly,  Zhang et al.  [23]'s experimental results suggest that Smectite may absorb hydrocarbons in  certain conditions. So, according to clay type, clay will  absorb and adsorb different fluids.

 

 

3.3.  Wettability and  adsorption

 

 

Wettability determines which fluid will adhere to the surface and subsequently will   be  affected more by  the surface-fluid interactions. In  contrast to  conventional reservoirs where hydrocarbons accumulations migrate from the source rock  to the reservoirs,  Shale is  considered self-sourced reservoir.  Besides, the heterogeneity reported in shale mineralogy. Fig. 3 highlights the main constituents of shale matrix and pores. Therefore, Shale pores have different wettabilities and most of them are  mixed. Subsequently, the determination of fluid location within the pore is indefinite and will  depend on  the pore type under investigation [20].

Fig. 3. Schematic representations of different shale system constitutions [24].

The   electrical  charge  imbalance  on   the  surfaces of  both organic matter and clay  particles leads to fluid adsorption on these surfaces. There are  two kinds of adsorption experienced in Shale: gas  adsorption in organic pores and water adsorption on clay  particles. Gas  adsorption will   be  more  tangible in  high pressures as  indicated from Langmuir isotherm. The  adsorbed fluid signal will  be  mainly controlled by  the interactions with surface molecules and will  exhibit relatively faster relaxation compared to  the remaining fluid in the pore. The  exchange between molecules between the adsorbed phase and the free phase and its impact on  the fluid response needs more investigation.

 

 

3.4.  Mineralogy

 

 

NMR response is assumed to be  independent from the rock matrix, however rock mineralogy will  control the surface chemistry of  the  grains and, in  turn, the  surface relaxation mechanism.  Shale is  a  fine-grained  clastic sedimentary  rock composed of different portions of clay  minerals, quartz, calcite and organic matter. Interestingly, the resin present in the organic pores also  affects the surface chemistry of these pores as it coats the grains. Therefore, the heterogeneity in  the composition reflects on  the surface chemistry of the pores which will  exhibit different relaxitivity characteristics. Therefore, assigning a single value  for   surface  relaxivity  for   the  whole  rock  would  be misleading.

 

Paramagnetic impurities are  another aspect that should be considered during shale mineralogy discussions. The  most common paramagnetic ions  present in shale are  iron and manganese. The high paramagnetic content may be misinterpreted to high surface relaxivity. But, in reality, most of the iron content in shale is related to the pyrite and small amount is dispersed as an impurity in  pore  surfaces and  very little  in  organic  matter. Therefore, the paramagnetic ions  will not be the reason for faster relaxation [18].  Fig. 4 displays the mineralogy of the main shale gas  plays in the United States.

Fig. 4.  Mineralogy of the gas  shale plays in  the United States [25].

4.  Fluids NMR responses in shale

 

 

The relaxation time of the fluids in bulk volume will  depend mainly on the interactions between the protons within the fluid. But, the relaxation of the fluid in shale pores will  be affected by several competing factors as  indicated in  the previous section. The  resulting signal will  signify massive information about the fluid and the pore size.  This section discusses the NMR response of the fluids in shale. Table  1 shows the qualitative response of different fluid in porous media. Table  2 display the fluids signatures reported in literature.

Table 1 Qualitative T1, T2, and D values for different fluids in porous media [modified after 12].

Table 2 Comparison between the response of the brine, oil  and gas in sandstone and shale [6,14,26-29].

4.1.  Brine response

 

 

The   relaxation of  the  bulk liquids is  controlled  by  dipole-dipole  interactions. Consequently,  the response is  directly proportional to  liquid viscosity and inversely to absolute temperature. In addition, the response of brine depends on the type of  salts  dissolved. As,  the  presence of  small  concentrations paramagnetic ions  (mn+2) or ferromagnetic ions  reduces water response substantially. The  combination of the long  bulk relaxation time and the tendency of water to fill the small pores are the main reasons for  the domination of  the surface relaxation mechanism on  the brine relaxation in porous media.

 

 

4.2.  Oil response

 

 

Oil is a mixture of different liquid hydrocarbons components and series. Therefore, oil is expected to  have board distribution without unique peak characterizing the fluid type as  in  pure fluids. The  more heterogeneous  oil  composition is  the more broad the oil response would be.  The  fractions of the light and heavy component in oil determine whether the oil will relax fast due to the heavy components or  relax slowly due to  light components. Moving to  the nanoscale pores,  the wettability of the surface determines  which fluid will  be  affected by  surface interactions. However, Minh et al. [5] suggested that the relaxation of  heavy oil  will  be  dominated by  bulk relaxation mechanism regardless of the wettability of the pore due to  the short bulk relaxation of heavy oil. Based  on their simulation results, they set 100cps   as   the  dividing value. Higher than this value, the wettability effect is considered negligible. Based on experimental study results, Tinni  et al. [26]  agreed that the heavy oil response will not be affected by the surface relaxation. On the other hand, the bulk decay exponent is  comparable to  the surface decay exponent in light oil. So wettability will determine the essence of the relaxation mechanisms involved.

 

 

4.3.  Gas response

 

 

Dunn et al. [14]  showed that the relaxation behavior of gas will  not follow the same behavior of liquids. As the bulk relaxation of  gas  will   be  dominated by  spin-rotation interactions. Therefore, the  response  is  directly  proportional  to   absolute temperature and inversely to fluid viscosity. Moreover, the T1 relaxation dependence on temperature and pressure is opposite to  the situation in  liquids. T1   is  directly proportional  to  the pressure and inversely to the temperature. Moving to relaxation in shale, the situation is more complicated with the introduction of adsorbed gas  to  the system. As, gas  diffusion coefficient will depend on  the diffusion of adsorbed phase, free  phase and the exchange between them. Ref. [29]  studied the gas  dynamics in Shale.   Their  study proposes a  new restricted diffusion model. However the experimental results do  not present the diffusion in confined nanopores due to the limited resolution of the used machines. They  claims that T1  and T2  are  controlled by  dipole interactions between gas  protons and paramagnetic impurities in   the  surface. However,  Washburn  [18]   suggested that the relaxation might be  due to  homonuclear coupling between gas protons and protons on  the surface.

 

 

5.  Interpretation methods

 

 

The complex structure and heterogeneous composition of shale require the  manipulation of  more than one dimension (1-D) distribution to identify the different fluids present in the pores. In addition, the overlap between the fluid relaxation peaks would confound fluid typing methods, for example, the overlap between heavy oil peak and water peak considering 1-D interpretation. Also, Kausik et al. [27] reported an overlap between oil signal (6e20 ms) and methane signal (10e20 ms). However, the implementation of two-dimension (2-D) methods provide better differentiation between the fluid peaks and in some cases may capture clay particles and organic matter response. Unfortunately, there are  two expected weaknesses in these methods: I) the wide range of oil viscosities leads to indefinite signature. ii) All these methods do not distinguish between free  and adsorbed gas  fractions. In this section, different interpretation methods will be discussed.

 

 

5.1.  1-D method

 

 

There are two methods counting on  only  1-D  measurement. The  first method is simply based on  the T1  contrast among the fluids (dual TW  method). This  method  involves polarizing the sample with short and long  wait times. Water protons are polarized  in the two times, but the hydrocarbons will be polarized only during the long  time. So the differential response will  define the hydrocarbon response (light oil or gas).  The  second method depends on  the contrast among the diffusion coefficients of fluids (dual TE method). Based  on the Equation (2) if the T2 measurement was performed with different TE the responses will  be  different. The  differential response can  be  used to identify the fluids. This method  identifies the  gas   response and measures its  volume accurately. Xie and Xiao  [30]  proved from numerical simulation that water response in  large pores will  not be  identified by  TW method and there will be an overlap between the responses of gas in small pores and irreducible water using TE method. These results suggest the use  of 2-D methods for better resolution.

 

 

5.2.  2-D methods

 

 

2-D methods will overcome most drawbacks encountered in  1-D methods. These methods  include  plotting  diffusion distributions versus T1 or T2, T1 versus T2 and T2SEC versus T1/T2. These methods  yield better  fluid  typing  by  providing more contrasts between the fluids peaks reveal the overlaps between the fluids signatures.

The T1-T2 method provides better differentiation between the different fluids responses. A number of  experimental studies have been conducted in  this area, including the work of Fleury [6] with low field NMR to quantify fluids through T1-T2 maps. The experiments were performed on  both the organic matter (immature, oil  window and gas  window) and shale samples. According to the experimental results, T1-T2  method successfully capture water and methane signature (T1/T2  ~ 2 and 10  respectively) along with a diagnostic map (T1  vs. T2) showing the expected  region of  the  response from the  organic matter  and hydroxyls groups in  the clays  as  indicated in  Fig. 5. Washburn [31]  has  studied the T1-T2  response of four  shale samples, three from Piceance basin (outcrop, oil  shale and well cuttings) and outcrop sample from unita basin. This study confirms the ability of the T1-T2  maps to identify different organic maturities present in  shale, mainly solid  and liquid-like phases. Xie and Xiao  [30] studied the T1-T2   maps with numerical simulation. Their   results  are   consistent  with  the  previous experimental  work. Therefore T1-T2  method is the applicable tool  for fluid typing in most situations except differentiating between  heavy oil  and bound water response.

Fig. 5. T1-T2  diagnostic  map [Modified after 6].

The  overlap between the gas  and irreducible water signals resulting from the use of Dual TE method can be resolved by the D- T2 method. Experimental investigation conducted by Zielinski et al. [32] on carbonates introduced the concept of restricted diffusion of fluids in  porous  media, followed by  the  application of  these restricted diffusion maps to interpret the dynamics of restricted gas  in  shale [29],  completed by  a  revised model based on  the restricted diffusion to interpret the response from gas and oil shale as shown in Fig. 6. However, it worth noting that all the diffusion-based methods lack real measurements of restricted diffusion coefficients in shale due to the limited resolution of the machines.

Fig.  6. D-T2  method in  conventional and unconventional reservoirs [5].

Daigle  et al.  [7]  introduced a  method based on  the secular relaxation  (T2sec)   to  distinguish between  the  fluids through plotting (T2sec  vs. T1/T2). Secular relaxation rate is the difference between transverse and longitudinal relaxation rates. Their  experiments were performed in ambient conditions with low  field NMR on  samples from the Bakken, Woodford and shallow Marine mudstone from offshore Japan. This  method succeeded to separate signals of the fluids based on  viscosity and pore size. They provide a diagnostic map to interpret the NMR responses to seven different scenarios as  shown in  Fig. 7.  Followed by  the work of Gips et al. [8] to evaluate the hydrocarbon characteristics based on  the differential response. This  differential response is the absolute difference between the NMR response at  a higher temperature   and  at    ambient   conditions.  This    differential response may carry valuable information about the fluid molecular size and viscosity if it is correlated to the correlation time. But,  it  is  worth mentioning that the experimental procedures were performed on a grinded sample. Moreover, Washburn [18] claims that this differential response will  be  mainly due to  the dependence of the surface relaxivity on  temperature.

Fig.  7. T2sec-T1/T2  method [modified after 7].

5.3.  Artificial  contrast

 

 

Another approach based on  introducing an  artificial contrast between hydrocarbons and water to separate their signals in the T1-T2   maps which will   allow better  identification of  the fluids. Mitchell et al. [34]  have analyzed the effect of the paramagnetic  doping agent, especially chelated  manganese-EDTA and  unchelated  manganese on four   limestone   plugs.  This study recommends the use of  doping agents for  better clear separation among oil  and water signals and the mitigation of unchelated manganese with EDTA whenever clay is present. On the other hand, this study opposes the use  of any  paramagnetic doping agent in  any  system with PH<9,  As, it  will  result in precipitation of  insoluble products which will  affect the flow capacity.  Unfortunately it does not include experimental work in  shale. Using  the same concept, Gannaway [33]  succeeds in providing robust method to  separate water and oil  response. This separation enables to quantify different types of porosities encountered in shale as presented in Fig. 8. However, this study did  not consider the formation damage resulting from the interactions between mn+2  and clays   and PH  effect on  doping effect in  shale.

Fig.  8.  Gannaway results from using doping agent to quantify the different porosities [modified after 33].

6.  Fluid properties estimation from NMR measurement

 

 

The  estimation of  the fluid properties from NMR measurements was reported in literature in the experimental work performed by Freedman et al. [35]  in bulk fluid samples, Ref. [36]  in Berea rocks and [37]  in oil sands. Ref. [35]  proposed a mapping function to estimate fluid properties from NMR measurements based on  the database that they have established. Ref. [36]  proposed a set  of correlation to  estimate the fluid properties from NMR signal. On the other hand, in one of the earliest studies to calculate the in-situ viscosity of oil  sands based on  NMR measurement, Ref. [37]  assumed that the heavy oil  relaxation will depend only  on  internal interactions so  they derived a  set  of correlation to estimate in-situ viscosity of oil sands based on T2 and relative hydrogen index.

 

The  successful estimation  of  fluid properties is  tied to the accuracy  of fluid  identification by previous  interpretation methods. The fluid properties that could be estimated from NMR include density, Gas-oil ratio (GOR) and viscosity [38-40].

 

 

6.1.  Density

 

 

The  fluid density can  be  estimated after fluid identification using hydrogen index equation [14].  This equation has  two variables hydrogen index and total porosity. So if the total porosity is known, the fluid density can  be estimated.

6.2.  Viscosity

 

 

Dead  oil viscosity of pure alkanes exhibits a linear relationship with both T1, 2 and D [14]. Hirasaki and Zhang [40] proposed a correction for  live  oil  viscosity as  a function of Gas  Oil Ratio (GOR). However,  Chen  and Chen  [39]  recommended a  mixing rule to estimate the viscosity of hydrocarbon mixtures. But, this is not the case  in the shale reservoirs where the main relaxation mechanism is surface relaxation. Subsequently, the decay exponent is mainly a function of surface-fluid interactions and does not represent the internal reactions within fluid protons. However,  Minh et al.  [5]  suggested based on  simulation study that the heavy oil (viscosity more than100 cps) relaxation will be controlled by  the  internal reactions. Therefore, the  heavy oil viscosity could be correlated with their relaxation time following the procedure presented in  Bryan   et al.  [37]   to estimate the viscosity of oil sands.

 

Tinni  et al. [26]  used the T1/T2  ratio to differentiate between moveable and non-moveable fluids in  both conventional and unconventional reservoirs. The experimental results of this study show that the non-moveable hydrocarbons will  not be  affected by  surface relaxation which was confirmed by  the simulation results of [5]. This study proves that NMR can  estimate the fluid viscosity at least qualitatively.

 

 

6.3.  Gas-Oil  Ratio  (GOR)

 

 

Winkler et al. [38]  proposed a model to estimate GOR as the ratio between the numbers of the gas  protons to the number of oil protons assuming that oil and gas  molecules maintain their identities microscopically and, in turn, oil and gas molecules will maintain their self-diffusivity. So,  after the differentiation between gas  and oil  molecules using their proposed mixing rule, GOR and viscosity could be  determined. Chen   and Chen   [39] extend this model to  mitigate the invasion of oil base mud and provide a  method to  calibrate NMR  log  to estimate GOR and viscosity of live oil signatures. But, this approach requires precise differentiation between gas  and oil.  There is another approach based on the observed deviation from the temperature-viscosity/ relaxation time correlation in the case  of live  oil. Consequently, this deviation can  be  correlated empirically to GOR [41].  But, Winkler et al.  [38]   disputed the latter approach. As  it  overestimates GOR and they attributed this to the complexity of the competing factors; spin rotation and intramolecular attraction.

 

The  extension of  the capability of  NMR in  shale to  include fluid properties identification will  make it a stand-alone formation evaluation method. However, the accuracy of the properties derived will  be  doubtful. As the correlations used were derived based on pure alkanes assuming single decay constant. Also, the used correlations will  have limited applicability to  the formations and the fluids used to derive them.

 

The fast  relaxation of protons in shale limits the resolution of low-frequency field measurements. Therefor, the fluid properties will  be  better estimated using high-frequency NMR. However, these high field measurement are  double edged weapons. While it  enables capturing the bulk relaxation response, it magnifies the heterogeneity in  the  system. So  capturing this response would be more challenging and inaccurate. Moreover, the small size  of the probe of the common NMR high-frequency machines will not allow sample measurements. Instead, the measurements will  be performed on  grinded samples.

 

There is another approach based on measuring the response from the sample at  high-temperatures, then subtract the high temperature response from the ambient temperature response. So the differential response could be correlated to the change of fluid viscosity with temperature  assuming that surface relaxation  component  will   remain  constant.  But   this  approach  is disputed by  Washburn [18].  As they proved the dependence of the surface relaxivity of the organic pores on  the temperature.

 

 

7.  Conclusion

 

 

The abundance of different typing methods should boost the identification process, however, unfortunately, shale heterogeneity limit the applicability of most of them. The  T1-T2  method seems to  be  the most appropriate method for  fluid typing in shale. As, the high internal gradients observed in  shale would limit the applicability of all diffusion based methods. Moreover, the accuracy of the fluid properties estimated will depend on the efficiency of extracting the bulk relaxation response. Although most current correlations were derived for pure alkane components, the mixing rules proposed in the literature could extend their applicability to the  multicomponent systems. The  fluid properties estimation from NMR measurements in shale is challenging and  needs  more  experimental  work  to   develop reliable correlations and properly calibrate the devices. The fluid typing in shale is a complicated process, but it would be  better performed by  well-understanding of  the shale system on  one side  and developing robust identification methods on  the other side.

 

 

Nomenclature

Appendix

References

 

 

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Article history:

 

 

Received 26 October 2015

Received in revised form

25 January 2016

Accepted 3 February 2016

 

 

Corresponding author. (Mohamed Mehana) Tel.: +1 4058873536.

E-mail address: M.Mehana@ou.edu (M.  Mehana).

Peer review under responsibility of  Southwest Petroleum University.

 

 

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