Th E Petrophysical Evaluation of Unconventional Najmah Formation of Kuwait - A Case Study

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1 Th E Petrophysical Evaluation of Unconventional Najmah Formation of Kuwait - A Case Study B. Khan* (Kuwait Oil Company), O. Nohut (Schlumberger), M. Van Steene (Schlumberger), A. Abu Ghneej (Kuwait Oil Company) & A. Al Ajmi (Kuwait Oil Company) SUMMARY Najmah Formation is an unconventional reservoir consisting of kerogen rich mudstone. It serves as an excellent source as well as reservoir and seal rock. It has low porosity and matrix permeability with sustained commercial production only in regions of high natural fracturing. Petrophysical evaluation of Najmah Formation poses many challenges and there is always a degree of uncertainty. The objective of this paper is to deliberate the methodology adopted in order to minimize the uncertainty. In the wells under study, a complete suite of logs were recorded including elemental log and nuclear magnetic resonance. Petrophysical evaluation was conducted using a mineral solver. Calcite, quartz, pyrite, illite, chlorite and kerogen were the minerals solved. The fluid volumes were obtained using Simandoux equation. Porosity was computed from sum of the fluid volumes, hence, intrinsically corrected for the presence of kerogen. TOC was computed based on the conversion of kerogen volume to TOC as proposed by Tissot and Welte (1978). The Langmuir isotherm methodology was used to determine the amount of adsorbed gas. The mineral volumes, porosity and TOC show good correlation with the core data. The computed adsorbed and total gas volumes confirm the economic potential of this unconventional reservoir.

2 Introduction The Najmah formation was deposited in an intra-shelf basin within the Arabian plate during Callovian to Oxfordian ages. It is divisible into three main units. The lower unit comprises of thinly laminated mudstone and wackestone, deposited in inner to middle ramp. The middle unit consists of calcareous mudstone rich in kerogen deposited in outer ramp to starved basinal setting (Yousif and Nouman 1977). The upper unit is composed of oncoidal bioclastic packstone deposited in inner ramp with moderate to high energy condition. The middle unit is considered as an excellent source rock with type II kerogen and is responsible for charging various reservoirs in Kuwait. In addition, the Najmah formation also serves as reservoir and seal rock with established commercial production of light oil and gas. The middle unit has an average thickness of 70 ft. The matrix porosity is in the range of 2-6 p.u. and permeability is less than 0.01 to 1.5 millidarcy. Commercial production from the reservoir has been found to be sustained only in regions of high natural fracturing; presence of natural open fractures is believed to have enhanced the permeability substantially. These characteristics place the Najmah formation in the category of unconventional reservoirs. Its effective exploration and exploitation has become increasingly critical to meet the steadily rising demand for natural gas in the country. There are multi-facet challenges and a degree of uncertainty in the petrophysical evaluation of this unconventional reservoir. The objective of this paper is to present the challenges that face the petrophysical evaluation and deliberate the methodology adopted in order to minimize the uncertainty. Geochemistry Evaluation Results The organic rich sediments contain organic matter as insoluble kerogen and/or soluble bitumen. The organic richness is expressed in terms of total organic carbon (TOC). A large number of core samples from the Najmah formation from different wells spread over Kuwait have been analyzed for TOC by Rock Eval pyrolysis. In general, the middle unit has excellent TOC, ranging from 2.13 wt. % to 30.5 wt. % (with an average of 8.3 wt. %). The TOC values are higher in North West Kuwait with an average value of 9.0 wt. %. However, the Najmah formation has an excellent source potential all across Kuwait. Thermal maturity can be assessed by the measurement of reflectance light using microscopy analysis of vitrinite particles (Ro), spore color index and Rock Eval analysis Tmax. The reflectivity measurements were carried out on bitumen and the values of bitumen reflectivity obtained were converted to the equivalent vitrinite reflectivity using the bitumen/vitrinite reflectance correlation method proposed by Jacob (1989). The equivalent vitrinite reflectivity values range from 6.6% to 1.28% suggesting that the source rock interval within the Najmah formation is late mature for oil generation and mature for condensate and/or wet gas generation. This is in good agreement with the spore coloration of preserved amorphous material indicating a type II kerogen. Pyrolysis Tmax values range from 441degC to 498 degc indicating that the Najmah rocks are late mature for oil generation, confirming the results of the optical maturity analyses. It can be concluded that the Najmah formation lies in the late maturity oil-condensate window based on the vitrinite reflectance data and is adequate for oil, condensate, and wet/dry gas production. The transformation ratio (TSR) is about 80%. The hydrogen indices (HI) in most of the wells show low values, ranging from 16.8 to 286 mg/g TOC. The low HI is due to late maturity of the interval. The kerogen has already exhausted most of its original potential; this is typical for late mature type II marine organic matter. Petrophysical Evaluation Challenges Petrophysical evaluation of the Najmah formation, as any other shale oil/gas reservoir, poses many challenges in terms of data requirements, mineralogical characterization, estimation of porosity, total organic content, initial gas pore volume, net pay, and producibility.

3 For petrophysical evaluation of shale oil/gas, it is necessary to establish the volume of kerogen in order to estimate adsorbed gas content and porosity with fair accuracy. In unconventional reservoirs, porosity is highly dependent on the kerogen volume since kerogen has a low density compared to the non-organic matrix components. Matrix density determination is also necessary in order to compute accurate porosity and fluid volumes. Since organic shales usually have complex mineralogies, a basic set of conventional logs is not sufficient to accurately resolve mineralogy. Another challenge particular to drilling of the Najmah formation is the high barite content in the mud, which renders the photoelectric factor difficult to use. This reinforces the need for complementary mineralogical information sourced from additional logs. Although fracture characterization is important, as it affects completion and producibility, it is not within the scope of this case study. Petrophysical Model In this case study, a comprehensive set of logs was acquired. In addition to the standard triple combination of resistivity, gamma ray, neutron porosity, bulk density and photoelectric factor, neutron spectroscopy data was acquired in order to refine the mineral volume fractions evaluation. From the neutron spectroscopy measurement, the elemental dry weights of silicon, calcium, iron, sulfur, aluminum, and titanium were input into the evaluation. Full spectrum natural gamma ray data, providing the concentrations of potassium, thorium and uranium, was used to define clay types, but also to separate the large uranium contribution in the organic shale interval from the other radioactive minerals. Nuclear magnetic resonance (NMR) measurement was also acquired. Due to the kerogen very fast relaxation time, NMR is not sensitive to the kerogen volume (Kleinberg et al. 2010); hence, by combination with bulk density and spectroscopy logs, it provides a robust input into kerogen volume estimation. Other measurements, such as acoustic and imaging tools are instrumental in determining the completion quality, but have not been used in the petrophysical evaluation. Formation evaluation was conducted using a mineral solver, as it allows full integration of the large amount of data (conventional logs, NMR, and spectroscopy data). The following mineral volumes were solved for: quartz, calcite, pyrite, illite, smectite, chlorite. The oil and water volumes, in addition to water saturation were obtained using the Simandoux saturation equation. The kerogen volume was also part of the outputs. Finally, porosity was computed from the sum of the fluid volumes. Hence, the porosity was intrinsically corrected for the presence of kerogen. TOC Evaluation TOC is the amount of carbon bound in the organic compounds of the rock. It is an important parameter of shale evaluation, because it allows determination of the amount of gas adsorbed on the kerogen. The conversion between kerogen and TOC depends on the kerogen type and its thermal maturity, which has been determined by core analysis and discussed in the geochemistry section above. In this case study, the TOC was computed based on the conversion of kerogen volume to TOC proposed by Tissot and Welte (1978), which requires the knowledge of kerogen volume, kerogen density, and formation matrix density. The kerogen volume and matrix density were outputs of the the mineral solver analysis (as described in the previous paragraph). Kerogen density was estimated based on the kerogen maturity. Several other methods using only conventional logs are available to compute the TOC. Most common algorithms use either density or sonic logs, but also a combination of neutron-resistivity, densityresistivity and uranium content. In this paper, additional TOC estimations were performed using the Schmoker equation (Schmoker and Hester 1983) and the Passey equation (Passey et al. 1990). The results of the three TOC computation methods are shown in the results section (see Figure 1).

4 Adsorbed Gas Estimation The goal of the evaluation is to determine the gas in place in the unconventional reservoir. The total gas present in the formation comes from the contributions of two different components: adsorbed gas, which is gas sorbed at the surface of kerogen; and free gas, which is found in the rock pore space. The Langmuir isotherm methodology is used to determine the amount of adsorbed gas. It is a function of the TOC, pore pressure and the formation temperature. For many known basins like the Barnett and Marcellus, isotherm values are well known. For new shale plays, it is best if they are measured on core in the laboratory. Results The results of the petrophysical evaluation, TOC and gas in place computation are displayed in Fig.1, where they are compared to core data (routine core analysis results and TOC evaluation). Figure 1 Petrophysical interpretation results, the tracks description is as follows: track 1: depth;, track 2: gamma ray and caliper; track 3: resistivity; track 4: neutron porosity and acoustic slowness; track 5: bulk density, matrix density computation and core grain density; track 6: mineral solver volumetric analysis, including clay volumes, matrix volume, kerogen volume and fluids volumes; track 7: reservoir and net pay flags; track 8: porosity and fluids volumes with core porosity and water saturation; track 9: gas, oil and water saturations, gas-oil ratio, oil API gravity; track 10: TOC computed from the mineral solver compared to core TOC data; track 11: adsorbed gas and total gas in place (based on TOC in track 10); track 12: TOC computed from the Passey method compared to core data; track 13: TOC computed from the Schmoker method compared to core data: track 14:

5 mineral dry weight fractions from neutron spectroscopy, compared with total gamma ray (red curve) and core clay dry weight fraction. Track 6 shows the results of the volumetric evaluation, and the kerogen volume is shown with purple shading. There is a strong correlation between the zones having the highest kerogen volume and the high uranium response, as seen from the difference between total and corrected gamma ray curves (track 2). The mineralogy is mostly composed of clay (dominated by illite) and calcite, with fractions of quartz and pyrite. The clay volume follows the core data trend and the pyrite volume matches well with core data. Such complex mineralogy would have been very difficult to resolve from conventional logs alone, in particular in the absence of photoelectric factor. Porosity (see track 8) correlates well with core data. It is not uniformly distributed across the unconventional interval, and sweet spots exist in the upper part of the Najmah formation (interval XX238 ft - XX262 ft) and at the base of the section (interval XX280 ft XX290 ft). These zones also correspond to lower water saturation, while the interval located in between (XX262 ft XX280 ft) has low porosity and high water saturation. The TOC obtained from the different computation methods is shown in track 10 (obtained from the conversion of kerogen volume), track 12 (obtained from Passey equation) and track 13 (obtained from Schmoker equation). The TOC from the kerogen volume conversion method shows a good match with the TOC obtained from core analysis. The TOC results obtained from the Passey and Schmoker methods also show a decent match; however, adjustment of the correlation parameters was required, and hence, these two methods could not have been predictive if no core calibration had been available. Total gas and adsorbed gas volumes are shown in track 11. This analysis shows that free gas is available in the sweet spots described above. Conclusions The Najmah formation lies in the late maturity oil-condensate window. Thanks to the use of advanced logs (neutron spectroscopy, full spectrum gamma ray and NMR), in addition to conventional logs, a detailed volumetric formation evaluation could be carried out. The mineral volumes, porosity, and TOC data were validated with core data. Adsorbed and total gas volumes could be computed and confirmed the economic potential of this unconventional reservoir. References Jacob, H. [1989] Classification, structure, genesis and practical importance of natural solid oil bitumen, International Journal of Coal Geology, Volume 11, Issue 1, February 1989, Pages Kleinberg, R. et al. [2010] Oil Shale Formation Evaluation by Well Logs and Core Measurements, 30 th Oil Shale Symposium, Golden CO, October Passey Q.R., Creaney S., Kulla J.B., Moretti F.J., Stroud J.D. [1990] A Practical Model for Organic Richness from Porosity and Resistivity Logs, AAPG Bulletin, V64, No12, p Schmoker, J.W. and Hester, T.C. [1983] Organic Carbon in Bakken Formation, United States Portion of Williston Basin, AAPG Bulletin, V67, No 12, p Tissot, B.P., and Welte, D.H. [1978] Petroleum Formation and Occurrence, Springer-Verlag, Berlin, 538 p. Yousif, S., and Nouman, G. [1977] Jurassic Geology of Kuwait, GeoArabia, Volume 2, No.1 1, p