porosity

The F field in the Middle East currently has more than 40 producing wells in the center of the structure. The uneven well distribution limits the understanding of 3D reservoir characterization, particularly in the flank areas. A new technique that analyzes scanning electron microscope (SEM) images of formation samples has been used to measure porosity and total organic carbon (TOC) in the Wolfcamp Shale of the Delaware Basin in west Texas.

Houston-based Surge Energy drilled the Medusa Unit C 28-09 3AH well in the Midland Basin to a TMD of 24,592 ft, with a total horizontal displacement of 17,935 ft, or 3.4 miles. This paper discusses a project with the objective of leveraging prestack and poststack seismic data in order to reconstruct 3D images of thin, discontinuous, oil-filled packstone pay facies of the Upper and Lower Wolfcamp formation. A new technique that analyzes scanning electron microscope (SEM) images of formation samples has been used to measure porosity and total organic carbon (TOC) in the Wolfcamp Shale of the Delaware Basin in west Texas. The integration of microseismic data with 3D seismic attributes, and well log and completions data is used to understand geomechanical rock properties. Data mining for production optimization in unconventional reservoirs brings together data from multiple sources with varying levels of aggregation, detail, and quality.

This paper examines the prospect of Gas Assisted Gravity Drainage (GAGD) process in improving recovery from a sandstone reservoir by injecting produced gas back into the crestal part of the reservoir. Besides recovery improvement, immiscible gas injection ensures near Zero Flaring strategy. The process has been found to be ideal in reservoirs with high permeability and reasonable dip to maximize oil production wherever a sufficient gas source exists. Based on the study, gas injection is recommended at the crestal part of the reservoir under study at the rate equivalent to the produced gas to maintain pressure, arrest gas cap shrinkage and improve recovery.

Digital core generated from micro CT images of rock sample cutting and results obtained from digital core analysis are presented in this work as a substitute of conventional core study for Petrophysical evaluation. Conventional core extraction during drilling, core preservation and analysis are expensive, time consuming processes and often unavailable for small size fields. Moreover, routine and special core analysis results are a critical input for petrophysical characterization. In this situation, digital core study appears to be a cost effective substitute to ensure and validate petrophysical evaluation results.

High resolution 3D micro CT imaging and analysis was done on rock samples cut during drilling or on sidewall core plugs cut by wireline logging tool. Segmented micro CT image slices when combined in 3D space in three orthogonal directions, can be termed as digital core. Solid rock matrix, clay filled and porous rock portions are distinctly separable using micro CT images and their volume fractions can be estimated. Detail textural analysis in terms of Grain and pore throat size distribution of the rock is possible from digital core which controls storage capacity and flow behavior. Two critical petrophysical input parameters for fluid saturation (Sw) estimation are cementation exponent (m) and saturation exponent (n). These parameters are commonly computed from special core analysis (SCAL) on conventional core plugs. But digital core study can provide the estimates of ‘m’ and ‘n’ which replace the need of SCAL.

Digital core study has been carried out in three different reservoirs in west and east coast of India and the results were analyzed. Porosity and permeability data obtained from digital core was first compared with log analysis results and then used to identify different petro physical rock types (PRT). Fluid saturation (Sw) was estimated from resistivity log by using ‘m’ and ‘n’ exponent obtained from digital core seems to be more realistic and corroborates with well test results. Porosity, permeability, water saturation and rock types (PRT) were helped to build geo-cellular model (GCM) for small and marginal reservoir.

Enhanced reservoir characterization by using digital core study result has helped in better understanding and decision making for small and marginal fields where limited well data is available. Finally this leads to the preparation of field development plan (FDP). Digital core technique is less expensive, having quick turnaround time than conventional coring which has translated into high value business impact for any development project.

Cement is a key element for successful drilling and completing of a well. From oil and gas wells to geothermal applications, cement is a major material ensuring zonal isolation. With an increase in global energy needs and an expected uptick in drilling and plugging and abandonment activities, evaluating and understanding cement properties is crucial, since these properties are used in various engineering designs and calculations. The objective of this paper is to present how Nuclear Magnetic Resonance (NMR) can be used to understand the cement hydration process and the development of key properties such as strength and porosity. NMR applications for cement include determination of porosity, water interactions, identification of hydration stages and C-S-H gel development with curing time. Since water is present in all cement slurries, NMR can potentially help to understand microstructural changes in cement during curing. Data from more than 600 cement specimens cured for more than a year are compiled. Standard cement properties such as UCS (unconfined compressive strength) are compared with NMR responses. In this paper, we document cement hydration and porosity changes through NMR measurements in samples with five different recipes. Our study also confirms a strong correlation between NMR response and cement strength.

S field has unique geological condition, the depth of maturity based on geochemistry analysis start from 800 m and classified as shallow depth rather than in the core of Kutai basin at 4000 m. It was caused by gravity tectonic from north which lifting the middle miocene formation from below. This situation gives the benefit to find source rock in shallower depth for unconventional exploration.

To characterize and predict the source rock especially for Total organic content value is using a well-known method called ΔLog R. This technique has been applied in many field with success stories. Beyond it is success, this method is less recognizing to predict in coal, because of the huge separation between Porosity log and Resistivity log. This study aims to applied this method in delta plain environment with abundant of coal source rock using between Density log, Sonic log, and Neutron log combine with Resistivity log. Besides that, TOC accumulation will be compared with Cyclostratigraphy trend, which trends contain much TOC content and by this vertical distribution to generate lateral correlation.

Basic principle for ΔLog R method is to seek the overlay between porosity log and Resistivity Log. Assuming when TOC is high the sediment rocks has good porosity and higher Resistivity reading. Those are the effect from kerogen in shale and generation of hydrocaron. In immature organic rocks it has good porosity but Resistivity log shows lowest value. Most of organic accumulation is in non reservoir. To eliminate the reservoir zone by using the Gamma ray log. This TOC value will be validate using several geochemistry analyses from cores.

Cyclostratigraphy-INPEFA log, is cyclic deposition that refer to orbital change that effect insolation on earth. This situation cause fluctuates of Eustachy and change the sea level. When sea level drop or N-Trend and coarse sediment will deposit and the other hand P-Trend or warming phase. Predicted TOC accumulation is much higher when warming phase. This trend will help to know TOC distribution around the field.

Considering the modern oil price environment, oil companies are more pressured than ever to reduce costs. This need affects tools used for reservoir characterization. Coring is important but expensive and is usually not available for the entire length of the well. A novel methodology is presented to perform reservoir characterization from wireline nuclear magnetic resonance (NMR) data, in the absence of any core, in offshore gas-bearing wells. This includes computing T₂ cutoff, hydrocarbon saturation, permeability, and poro-fluid sand facies determination.

NMR is a shallow measurement and using wireline NMR measurements is even more challenging due to higher time after bit and increased mud filtrate invasion. Consequently, its use is restricted to quantifying porosity, and even the basic assessment of bound/free fluid require correct T₂ cutoff to be determined from cores. Traditional formation evaluation methods use various equations like Archie’s, dual water, Waxman Smits, etc. to determine hydrocarbon saturation, all of which have many variables which, again, must be determined from cores. This makes it imperative to have core measurements to get precise results.

In this paper, we present the results of successful implementation of the proposed methodology, which functions without core data. It employs NMR data along with modern processing techniques like factor analysis and fluid substitution, and integrates density data to evaluate reservoir by 1) minimizing the mud signal, 2) using the virgin zone data to extract dominant peaks and repeated patterns on T₂ distribution to divide the entire reservoir section into different poro-fluid types, 3) obtaining the T₂ cutoffs for various poro-fluids facies, 4) calculating density magnetic resonance porosity (DMRP) and adopting it to drive fluid substitution, 5) obtaining original water equivalent porosity which is divided by DMRP to get water saturation, 6) employing the fluid substituted (water-only equivalent) T₂ distribution along with the T₂ cutoff determined by factor analysis to calculate permeability using the Timur-Coates equation.

Until recently, reservoir characterization methods in the industry were limited to use of seismic technologies in exploration of oil and gas and had a very constrained role in production and development. In the past, using characterization for development fields was considered a very perilous task. Technological advancements and the risk-averse mindset have significantly expanded the application of reservoir characterization. Today, reservoir characterization is the basis of any development plans made for a commercial field.

Development of 3D reservoir modeling techniques to generate field development plans (FDPs) marked a step-change in reservoir characterization methods. Introduction of geostatistics and numerical simulation made it possible to build precise models to generate realistic field development scenarios. This is the state-of-the-art seismic-to-simulation method of reservoir characterization used in FDPs today. However, the struggle to estimate reservoir properties spatially away from the well continues.

Surface seismic data provide excellent areal coverage but do not provide the vertical resolution required for a fine-scale reservoir model. Geostatistical methods reduce the uncertainty in spatial distribution of petrophysical properties from pseudo-point supports (wells) but are not calibrated spatially between the wells. Correspondingly, the fluid saturation distribution and the parameters used in dynamically calculating the same during numerical simulation are not calibrated in the interwell space.

This paper details necessary data acquisitions and methods of calibration of 3D reservoir model to reduce uncertainty in the interwell space. The data acquisition methods have been available for some time, but have rarely been electronically incorporated in the 3D reservoir model and have been largely used to analytically guide the modeling and its inferences. A logical way of interpreting the results of acquisitions and calibrating the 3D reservoir model cell-by-cell is detailed in this paper.

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. This methodology was used in deep tight fields in Oman for more than 3 years in both vertical and highly deviated wells greatly reducing the risk, logging cost and complexity of operations.

The identification of fluid saturations in depleted reservoir sands is critical to understand the reservoir potential and field life. However, in case of water flooding, the formation water salinity of the reservoirs sands might be altered and fluid saturations from conventional petrophysical analysis can be misleading. This will have direct impact on the field economics. A salinity independent saturation computation from Carbon/Oxygen (C/O) log becomes a necessity in such development wells– a first of such application in a field under secondary recovery for this basin.

C/O well logging has been extensively used in cased hole environments to determine saturation behind casing. They are used essentially to determine oil saturation in cased hole conditions for depleted reservoirs. While their cased hole applications have been well established; for the study well, a pulsed neutron tool was used in an open hole environment to determine the fluid saturations to compare against the saturations computed from conventional resistivity logs. This study helped in the determination of fluid saturations in mixed salinity reservoir sands, which were to be explored from subsequent wells in the field.

The hydrocarbon-bearing sands in the field were water injected in nearby wells to enhance recovery. Development wells drilled in the field relied on petrophysical evaluation from conventional open hole data and pressure testing and fluid sampling depths were determined accordingly. A pulsed neutron tool was deployed in an open hole well after operational constraints were encountered with the formation testing tool. As an alternative, the pulsed neutron data were acquired in the well to compute salinity independent water saturation based on C/O log response as against the fluid saturation computation from resistivity logs. The determination of fluid saturations from C/O helped in determination of altered salinity for the sand intervals in the field. For the study well, C/O-derived water saturation was found to be higher than that from resistivity log computation. This was significant in identification of water breakthrough in the bottom interval of the reservoir sands.

This paper details the method and findings of C/O logging in open hole environment from Western Onland Basin in India. The critical solutions provided for the reservoir sands in the field and enabled the operator to save significant well cost and rig time by making informed decision of not lowering the casing in this well section.