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The Barik, Miqrat and Amin formations are deep, tight reservoirs of the Haima Supergroup that provide the majority of gas production in the Sultanate of Oman. The Miqrat formation is a feldspathic sand/shale sequence with complex pore structure and occasional bitumen presence. In the area of interest, it occurs at a depth of approximately 5000 m. Average porosity varies from 5 to 9%, average permeability for Lower Miqrat does not exceed 0.1 mD. In general, Archie equation derived saturation in low porosity rocks is subject to medium to high uncertainty. Therefore the most common challenge in the petrophysical evaluation of tight reservoirs is the determination of gas saturation and fluid type identification.
In an effort to improve the reliability of saturation calculation and fluid typing, several different methods were tested including cased-hole Pulsed Neutron Logs (PNL). The classical sigma interpretation was found to be too sensitive to input parameters and did not provide significant improvement to saturation determination in the complex Haima lithologies. An important breakthrough was made when the dynamics of the mud filtrate invasion process in these reservoirs was understood. During open-hole logging usually very little or no gas effect is observed on logs with negligible or no density-neutron separation. The reason is considered to be deep mud filtrate invasion pushing moveable gas beyond the depth of investigation of radioactive logs. One or two months later, the filtrate in the invasion zone dissipates with gas returning to the near wellbore formation.
The best match between log calculated moveable gas saturation and production test data was obtained using a reverse time-lapse technique, with PNL cased-hole logs compared to baseline open-hole neutron measurements. The changes in neutron porosity with time can be attributed to moveable gas saturation. Careful neutron log quality control and normalization across non-reservoir and known water-bearing sections is required. Knowing the hydrogen index of gas, we can calculate the moveable gas saturation from the difference in neutron log response. In contrast to the sigma approach, an accurate rock matrix model is not required.
This paper describes the Reverse Time-Lapse technique: a novel application of the classic time-lapse technique between open-hole neutron and cased-hole PNL. The case studies demonstrate that this technique is applicable for completion decision making and field-scale development planning.
Al-Yaarubi, Azzan (Schlumberger) | Al-Hadidi, Khalsa (Petroleum Development Oman) | Lukmanov, Rinat (Petroleum Development Oman) | Al-Mahrouqi, Ali (Petroleum Development Oman) | Elie, Marcel (Petroleum Development Oman)
The identification, quantification, and implications of bitumen are concerns for a deep (>5000-m) tight gas reservoir in the Amin and Miqrat Formations in the Sultanate of Oman. Hydraulic fracturing is required to yield economical production rates in these reservoirs. The bitumen, which is believed to result from oil to gas cracking process, poses an additional challenge because it directly degrades storage capacity, destroys the permeability, and results in erroneous computed saturations. It is, thus, imperative that these factors are taken into consideration in reserves and productivity predictions that could ultimately impact overall development planning.
An evaluation workflow was devised to directly quantify bitumen and provide accurate volumetric analysis. The methodology is based on the integration of the triplecombo, nuclear magnetic resonance (NMR), and pulsed neutron spectroscopy logs in an openhole environment. The NMR effectively identifies bitumen through its reduced porosity against density log. This difference arises because NMR is incapable of measuring fast relaxation of the hydrogen contained in bitumen. However, the NMR porosity is also reduced due to the reduced hydrogen index of gas. Spectroscopy analysis quantifies the concentrations of various elements contained in the reservoir rocks. This includes carbon concentration contained in the rock, gas, and bitumen. The total organic carbon (TOC) is derived by subtracting inorganic carbon contained in the rock. The measured TOC is essentially due to the bitumen as it is negligible in gas. The integration of these different measurements is an effective means to differentiate and quantify different pore constituents contained in our subject reservoirs.
In cased and completed wells, we have developed an evaluation workflow that uses the slim pulsed neutron tool outputs. This includes sigma that is sensitive to saline water, hydrogen index (HI) and fast neutron cross section that are sensitive to gas, and TOC that is predominately due to bitumen.
The integrated volumetric analysis is done using an iterative linear solver. The analysis provides the total porosity, bitumen volume, and true gas saturation. The log predictions were verified against pyrolysis and thin-section analyses on core samples from similar wells. The production logs directly demonstrated the influence of the bitumen presence on the well productivity. Repeating the analysis in different areas of the reservoir further established the uneven bitumen distribution and its consequences across the reservoir. Our analysis provided the basis for more representative static and dynamic modeling.
The paper discusses a petrophysical evaluation method for complex tight gas formations in a mature and partially depleted gas condensate field in Oman, allowing a full petrophyscial evaluation as well as geomechanical modeling from a source-less petrophysical dataset, thus reducing operational data acquisition risk in partially depleted reservoirs without compromising on hydraulic fracturing design. The developed methodology includes the volume of shale estimation from correlation with Poisson's ratio for the feldspathic rich tight formation.
The presence of bitumen is an obvious risk for reservoir development. Pore-filling bitumen degrades reservoir quality. Sweetspotting, discriminating between producible oil and gas and reservoir bitumen is critical for recoverable hydrocarbon volume calculations and the optimal development planning. However it is in most cases impossible to make such differentiation using conventional logs.
It is well known that the Nuclear Magnetic Resonance (NMR) log provides an opportunity to identify the presence of reservoir bitumen in oil bearing reservoirs. The zones containing bitumen within oil and water reservoirs are characterized by lower NMR porosity estimates when compared to porosity from the density and neutron tools. But in gas reservoirs, bitumen identification from NMR porosity deficit is not a common industry practice. The porosity deficit could be related not only to the presence of bitumen, but also to the presence of gas in the pore space.
The case studies include tight gas reservoirs in Miqrat and Middle Gharif formations, both located in the Sultanate of Oman. Well tests showed gas rates lower than expected, accompanied by low mobility and sometimes water production from intervals with relatively good porosity and saturation calculated from logs. Besides, bitumen was identified from core. A new methodology was developed which can differentiate between residual gas and bitumen presence based on Density, Neutron and NMR logs in conjunction with resistivity. One of the pre-requisites is that the reservoir lithology must be known. The remaining gas saturation is quantified from Density-Neutron separation. If we know the Hydrogen index (HI) of gas, the NMR porosity deficit can be compensated for residual gas effect. Bitumen saturation can be quantified from the difference of total porosity and NMR compensated porosity.
The methodology was tested on two tight gas reservoirs of the Sultanate of Oman. Core analysis, production data, and total organic carbon (TOC) derived from pulsed neutron logs were used to verify the results of the suggested methodology. The comparison shows that the methodology can be used for semi-qualitative identification of bitumen. It was also observed that the bitumen distribution varies across the field, and overall the majority of reservoir hydrocarbons are moveable. Recommendations on the workflow for static and dynamic modeling were provided.
The suggested novel approach of bitumen identification in gas bearing reservoirs is relatively simple. It provides fit for purpose results for gas bearing reservoirs including tight gas which in turn can be used for more accurate estimation of gas volumes and optimizing development planning.
Miqrat is a complex clastic deep tight gas reservoir in the North of the Sultanate of Oman. The Lower unit of the Miqrat formation is feldspatic sand characterized by low permeability not exceeding 0.1 mD and porosity up to 12 %. Based on results of the appraisal campaign of Field X, it contains significant volume of gas. However the production test data after fraccing showed mixed results. The objective of this study to explain the production behavior in relation to the frac geometry.
Understanding the reason of possible overestimation of log derived Hydrocarbon saturation is important. Thus the interpretation of conventional and special logs was revisited. In parallel, all the available core data including SCAL and thin sections were dissected. Besides, the analysis of hydraulic fracture propagation, well tests, cement quality, PLT including Spectral Noise Log was performed.
The wells were subdivided into categories according to their production. wells producing no water wells with water channeling from the water leg of Middle Miqrat wells with transition zone intervals with two-phase inflow of water and gas.
wells producing no water
wells with water channeling from the water leg of Middle Miqrat
wells with transition zone intervals with two-phase inflow of water and gas.
There are three main challenges that needed to be overcome. First challenge is to identify the high uncertainty in hydrocarbon saturation from the resistivity logs. Petrophysical evaluation shows that porosity profile derived from logs looks very similar in all wells with insignificant lateral variations. Hydrocarbon saturation estimated from logs looks also similar regardless of how deep or shallow the well is. However, production tests show different results, e.g. different flow rates and high water-cut are observed in some wells.
The second challenge to keep the frac height below the boundary between Lower Miqrat and Middle Miqrat, which consist of around 3 to 7 meters of shale and in most of the field it is bound with water. The third one is to cover the upper part of the zone below the shale since it is the best part of Lower Miqrat without breaking to the water leg of Middle Miqrat. A geomechanical model was created and several frac model iterations were run since in the early appraisal well that boundary was broken.
Investigation through multidisciplinary integrated team led to unlock the tight gas reserves in Lower Miqrat. Based on open hole log interpretation to create a geomechanical model. That model is being calibrated with DFIT, 3 different case hole logs and confirmed with production.
Field N is a complex oil and gas field in the north of the Sultanate of Oman producing from several reservoirs. In this paper, the focus will be on Shuaiba gas reservoir, which is characterized by large variations in rock properties. An additional challenge is limited core data available and big gas effect observed from the logs. The described work was undertaken as part of an FDP update.
Gas correction effect and permeability modeling in such complex carbonate reservoir with the limited availability of representative core data is challenging. The density and neutron logs are affected by the presence of gas, which required advanced correction methods. The 1st applied technique of porosity correction comprised an iterative method of density and micro resistivity with simultaneous solution for residual gas saturation and corrected porosity. In addition, a new modification of gas correction was tried from Density-Neutron gas separation along with known PVT parameters was used for porosity calculation and gas corrections.
The log response of the Shuaiba reservoir in Field N looks like a classical illustration of gradual change of saturation from water leg to the transition zone and gas leg. However, flank well has been perforated close to the anticipated contact and produced gas for more than 200 days without water. As a result of comprehensive data analysis, a significant vertical heterogeneity of the reservoir was established. It was found that Gas saturation is a good indicator of permeability. A good relationship between fluid mobility from Wireline Formation Test data and water saturation from logs for gas leg was established. In the gas leg, all water is considered as irreducible, thus this is in fact relationship between mobility and irreducible water saturation. The relationship was then calibrated to permeability using the available core. As a result of this work, significant heterogeneity of the Shuaiba reservoir was captured in case of limited core data available. The remaining gas quantified for optimizing future development.
As part of this Study, an advanced gas correction method was applied resulting in more reliable Porosity evaluation. Besides, a new modification of the method for gas corrections from Density-Neutron separation was tested and showed good results.
The petrophysical evaluation of tight gas formations has traditionally been centered on calculations of porosity and water saturation. These two parameters are used to quantify the original volumes in place but they do not provide information about phase mobility except at the saturation endpoints in high porosities. Low porosity affects the accuracy of water saturation calculations and can often make them ambiguous, leading to wrong decisions and unwanted water production.
We found dielectric dispersion logging to be a robust technique for determining gas pay zones independently from saturation equation input parameters. Dispersion analysis of the conductivity and permittivity measurements acquired by these tools is a function of the water tortuosity factor (mn). This factor is vitally important for accurate water saturation evaluation, but is often unknown or variable.
Nuclear magnetic resonance (NMR) measurement has the potential to enhance traditional formation evaluation techniques by providing estimation of the irreducible water saturation (Swirr) and permeability throughout the interval of interest. Accurate determination of these parameters benefits the selection of perforation intervals and improves the chances of producing maximum hydrocarbon with minimum water. NMR logging of deep tight gas formations poses unique challenges with regards to data acquisition due to low porosity, high temperature, and frequently saline muds. Pulse sequences and quality control procedures are used to validate the NMR measurements at high temperatures and high salinities.
An interpretation workflow was developed to integrate dielectric dispersion and NMR data and the results compared with more traditional formation evaluation techniques. There were significant improvements in the prediction of hydrocarbon- and water-producing intervals. The technique has been applied in several deep, high-temperature, low-porosity gas wells. These analyses are made in a timely fashion to provide operators with information for making better completion decisions.