Geostatic modeling of the clastic reservoir: a case study the Late Cenomanian Abu Roash G Member, Hamra Field, Abu Gharadig Basin, Western Desert, Egypt

Recent advances in computer sciences have resulted in a significant improvement in reservoir modeling, which is an important stage in studying and comprehending reservoir geometry and properties. It enables the collection of various types of activities such as seismic, geological, and geophysical aspects in a single container to facilitate the characterization of reservoir continuity and homogeneity. The main goal of this work is to build a three-dimensional reservoir model of the Abu Roash G reservoir in the Hamra oil field with enough detail to represent both vertical and lateral reservoir heterogeneity at the well, multi-well, and field scales. The Late Cenomanian Abu Roash G Member is the main reservoir in the Hamra oil field. It is composed mainly of shale, carbonate and some streaks of sandstone, these streaks are shaly in some parts. Conducting the 3D geostatic model begins with the interpretation of seismic data to detect reflectors and horizons, as well as fault picking to explain the structural framework and frequently delineate the container style with proposed limitations to construct the structural model. The lithology and physical properties of Abu Roash G reservoir rock, including total and effective porosity and fluid saturation, were determined using well log data from four wells in the Hamra field. The constructed 3D geological model of the Abu Roash G has showed that the petrophysical parameters are controlled by the facies distribution and structure elements, whereas properties are the central part to the northern side of the deltaic environment than the other sides of the same environment. The model will be useful in displaying the reservoir community and indicating prospective zones for enhancing the dynamic model to improve the behavior of the flow unit productivity, as well as, section of the best sites for the future drilling.

The Impact of Extended-Time Proppant Conductivity Impairment on the Ultimate Recovery from Unconventional Horizontal Well Completions

The stimulation design of hydraulically fractured wells has always pitted the engineer's capability to maximize the fracture extent (or fracture half-length within the formation) versus the conductivity of the fracture pack generated by the deposited proppant material. In essence, the area of productive reservoir rock contacted by the hydraulic fracture treatment needs to be appropriately engineered to remain connected to the wellbore over the life of the well to maximize reservoir recovery. The completion design of multi-stage hydraulically fractured horizontal wells has been driven by their application to unconventional oil and gas reservoirs. This has primarily occurred in North America where most of the wells drilled and completed were operated by small, private, or upstream-only independent public companies. Metrics used to evaluate performance and completion design changes were short-term in nature and typically focused on parameters such as peak-month production, 90- or 180-day cumulative production; or at longest, the first year or two of cumulative production. Capital efficiency, and capital return or well payout were drivers of value creation in an environment where the well inventory was viewed as extensive if not unlimited and the quick recycling of invested capital created the illusion of value creation. Short-term performance metrics give credence to fracture designs that value most the early-time production that is dominated by rate acceleration. The work presented in this paper shows a comparison of fracture designs in deep unconventional formations looking to minimize cost by pumping all sand proppants versus a focus on ultimate recovery from the reservoir with designs that are more applicable to the stress regime. The work shows the importance of maintaining the wellbore connectivity to the reservoir by designing fracture treatments using proppant conductivity decline data measured over an extended-time period of months or years to maximize ultimate recovery from the reservoir. This approach will be critical to those E&P companies who view their well inventory or resource base as finite and consequently place a priority on maximizing recovery from the reservoir.

Petrophysical core-based zonation of OW oilfield in the Bredasdorp Basin South Africa

This study aims to generate rock units based on core permeability and porosity of OW oilfield in the Bredasdorp Basin offshore South Africa. In this study, we identified and classified lithofacies based on sedimentology reports in conjunction with well logs. Lucia's petrophysical classification method is used to classify rocks into three classes. Results revealed three lithofacies as A (sandstone, coarse to medium-grained), B (fine to medium-grained sandstone), and C (carbonaceous claystone, finely laminated with siltstone). Lithofacies A is the best reservoir quality and corresponds to class 1, while lithofacies B and C correspond to class 2 and 3, which are good and poor reservoir quality rock, respectively. An integrated reservoir zonation for the rocks is based on four different zonation methods (Flow Zone indicator (FZI), Winland r35, Hydraulic conductivity (HC), and Stratigraphy modified Lorenz plot (SMLP)). Four flow zones Reservoir rock types (RRTs) were identified as RRT1, RRT3, RRT4, and RRT5, respectively. The RRT5 is the best reservoir quality composed of a megaporous rock unit, with an average FZI value between 5 and 10 µm, and HC from 40 to 120 mD/v3, ranked as very good. The most prolific flow units (RRT5 and RRT4 zones) form more than 75% of each well's flow capacities are supplied by two flow units (FU1 and FU3). The RRT1 is the most reduced rock quality composed of impervious and nanoporous rock. Quartz is the dominant framework grain, and siderite is the dominant cement that affects flow zones. This study has demonstrated a robust approach to delineate flow units in the OW oilfield. We have developed a useful regional petrophysical reservoir rock flow zonation model for clastic reservoir sediments. This study has produced, for the first time, insights into the petrophysical properties of the OW oilfield from the Bredasdorp Basin South Africa, based on integration of core and mineralogy data. A novel sandstone reservoir zonation classification criteria developed from this study can be applied to other datasets of sandstone reservoirs with confidence.

Diagenetic stages of oil-saturated sandstones of the pashyisky horizon at the Romashkinskoye oil field

It was identified three stages of reservoir rock formation of the Pashyisky horizon of the Frasnian stage of the Upper Devonian at the Romashkinskoye field, based on optical microscopic studies. The first stage, associated with clastic deposits sedimentation and marked by clastic grains dense structural packing formation, close to cubic. The second diagenetic stage of quartz sandstones is associated with the subsidence stage of sediments into the burial zone. During this period were actively proceeding the processes of grains mechanical deformation, blastesis of quartz clasts, the formation of siderite fragments, and fibrous chalcedony, partially metasomatic replacing clay layers in sandstones. The third diagenetic stage in quartz sandstones is associated with the migration of underground gas-water solutions. Analysis of the transformation degree of the Pashyisky horizon quartz sandstones at different areas of the Romashkinskoye field revealed the relationship between the intensity of secondary diagenetic processes and the degree of rocks oil saturation. Keywords: pashyisky horizon; oil; sandstone; reservoir; diagenesis.

Minimizing Formation Damage in Drilling Operations: A Critical Point for Optimizing Productivity in Sandstone Reservoirs Intercalated with Clay

The recovery of oil and gas from underground reservoirs has a pervasive impact on petroleum-producing companies’ financial strength. A significant cause of the low recovery is the plugging of reservoir rocks’ interconnected pores and associated permeability impairment, known as formation damage. Formation damage can effectively reduce productivity in oil- and gas-bearing formations—especially in sandstone reservoirs endowed with clay. Therefore, knowledge of reservoir rock properties—especially the occurrence of clay—is crucial to predicting fluid flow in porous media, minimizing formation damage, and optimizing productivity. This paper aims to provide an overview of recent laboratory and field studies to serve as a reference for future extensive examination of formation damage mitigation/formation damage control technology measures in sandstone reservoirs containing clay. Knowledge gaps and research opportunities have been identified based on the review of the recent works. In addition, we put forward factors necessary to improve the outcomes relating to future studies.

Carbonate reservoir rock typing algorithm based on integrated approach (IRT)

The goal of carbonate rock typing is a realistic distribution of well data in a 3D model and the distribution of the corresponding rock types, on which the volume of hydrocarbon reserves and the dynamic characteristics of the flow will depend. Common rock typing approaches for carbonate rocks are based on texture, pore classification, electrofacies, or flow unit localization (FZI) and are often misleading because they based on sedimentation processes or mathematical justification. As a result, the identified rock types may poorly reflect the real distribution of reservoir rock characteristics. Materials and methods. The approach described in the work allows to eliminate such effects by identifying integrated rock types that control the static properties and dynamic behavior of the reservoir, while optimally linking with geological characteristics (diagenetic transformations, sedimentation features, as well as their union effect) and petrophysical characteristics (reservoir properties, relationship between the porosity and permeability, water saturation, radius of pore channels and others). The integrated algorithm consists of 8 steps, allowing the output to obtain rock-types in the maximum possible way connecting together all the characteristics of the rock, available initial information. The first test in the Middle East field confirmed the applicability of this technique. Results. The result of the work was the creation of a software product (certificate of state registration of the computer program “Lucia”, registration number 2021612075 dated 02/11/2021), which allows automating the process of identifying rock types in order to quickly select the most optimal method, as well as the possibility of their integration. As part of the product, machine learning technologies were introduced to predict rock types based on well logs in intervals not covered by coring studies, as well as in wells in which there is no coring.

Wettability of Carbonate Reservoir Rocks: A Comparative Analysis

Various methods have been proposed for the evaluation of reservoir rock wettability. Among them, Amott–Harvey and USBM are the most commonly used approaches in industry. Some other methods, such as the Lak and modified Lak indices, the normalized water fractional flow curve, Craig’s triple rules of thumb, and the modified Craig’s second rule are based on relative permeability data. In this study, a set of capillary pressure curves and relative permeability experiments was conducted on 19 core plug samples from a carbonate reservoir to evaluate and compare different quantitative and qualitative wettability indicators. We found that the results of relative permeability-based approaches were consistent with those of Amott–Harvey and USBM methods. We also investigated the relationship between wettability indices and rock quality indicators RQI, FZI, and Winland R35. Results showed that as the rock quality indicators increased, the samples became more oil-wet.