Main features of modeling terrigenous deposits in East-Siberia using the example of the Hamakinsky horizon

Background. The article considers the results of updating the geological model of the khamakinskii horizon reservoirs of the Chayandinskoe oid and gas field. The main aim is project the production of the oil rims and form a positive business case of the project. Materials and methods. Conceptual sedimentary model bases on the core of the 14 wells. Updating of the petrophysical model is the key to identify post-sedimentary transformations (like anhydritization and halitization) and the opportunity to correct the permeability trend. The tectonic pattern of the horizon based on the interpretation of 3D seismic data. There are two groups of faults were identified: certain and possible. Neural networks algorithm uses for a creating the predictive maps of anhydritization, which are used in the geological model. Results. Estuary sands influenced by fluvial and tidal processes dominate the khamakinskii horizon. The reservoir is irregular vertically: at the base of the horizon, there are sandstones of the delta front and there are alluvial valley with fluvial channels in the middle and upper parts. Eustary sands eroded by incised valleys (alluvial channels). According to the core and thin section analysis, the main uncertainty is sedimentary transformations of reservoir. It affects the net thickness and then the volume of oil in productive wells. 3D geological model includes the trends of anhydritization and halitization over the area, which makes it possible to obtain a more accurate production forecast. Conclusion. As part of the probability estimate of oil reserves, the main geological parameters that affect the volume of reserves were identified. Pilot project is planning to remove geological and technical uncertainties.

A Cognitive Data-Driven Single-Well Modeling Workflow for Reservoir Deliverability Predictions – Expanding the Wireline Formation Tester Application Envelope

In today's dynamically challenging E&P industry, exploration activities demand for out-of-the-box measures to make the most out of the data available at hand. Instead of relying on time consuming and cost-intensive deliverability testing, there is a strong push to extract maximum possible information from time- and cost-efficient wireline formation testers in combination with other openhole logs to get critical reservoir insight. Consequently, driving efficiency in the appraisal process by reducing redundant expenditures linked with reservoir evaluation. Employing a data-driven approach, this paper addresses the need to build single-well analytical models that combines knowledge of core data, petrophysical evaluation and reservoir fluid properties. Resultantly, predictive analysis using cognitive processes to determine multilayer productivity for an exploratory well is achieved. Single Well Predictive Modeling (SWPM) workflow is developed for this case which utilizes plethora of formation evaluation information which traditionally resides across siloed disciplines. A tailor-made workflow has been implemented which goes beyond the conventional formation tester deliverables while incorporating PVT and numerical simulation methodologies. Stage one involved reservoir characterization utilizing Interval Pressure Transient Testing (IPTT) done through the mini-DST operation on wireline formation tester. Stage two concerns the use of analytical modeling to yield exact solution to an approximate problem whose end-product is an estimate of the Absolute Open Flow Potential (AOFP). Stage three involves utilizing fluid properties from downhole fluid samples and integrating with core, OH logs, and IPTT answer products to yield a calibrated SWPM model, which includes development of a 1D petrophysical model. Additionally, this stage produces a 3D simulation model to yield a reservoir production performance deliverable which considers variable rock typing through neural network analysis. Ultimately, stage four combines the preceding analysis to develop a wellbore production model which aids in optimizing completion strategies. The application of this data-driven and cognitive technique has helped the operator in evaluating the potential of the reservoir early-on to aid in the decision-making process for further investments. An exhaustive workflow is in place that can be adopted for informed reservoir deliverability modeling in case of early well-life evaluations.

3D Integrated Structural, Facies and Petrophysical Static Modeling Approach for Complex Sandstone Reservoirs: A Case Study from the Coniacian–Santonian Matulla Formation, July Oilfield, Gulf of Suez, Egypt

The Coniacian–Santonian Matulla Formation is one of the important reservoirs in the July oilfield, Gulf of Suez Basin. However, this formation is characterized by uncertainty due to the complexity of reservoir architecture, various lithologies, lateral facies variations and heterogeneous reservoir quality. These reservoir challenges, in turn, affect the effectiveness of further exploitation of this reservoir along the Gulf of Suez Basin. In this work, we conduct an integrated study using multidisciplinary datasets and techniques to determine the precise structural, petrophysical, and facies characteristics of the Matulla Formation and predict their complex geometry in 3D space. To complete this study, 30 2D seismic sections, five digital well logs, and core samples of 75 ft (ft = 0.3048 m) length were used to build 3D models for the Matulla reservoir. The 3D structural model shows strong lateral variation in thickness of the Matulla Formation with NW–SE, NE–SW and N–S fault directions. According to the 3D facies model, shale beds dominate the Matulla Formation, followed by sandstone, carbonate, and siltstone beds. The petrophysical model demonstrates the Matulla reservoir's ability to store and produce oil; its upper and lower zones have good quality reservoir, whereas its middle zone is a poor quality reservoir. The most promising areas for hydrocarbon accumulation and production via the Matulla reservoir are located in the central, southeast, and southwest sectors of the oilfield. In this approach, we combined multiple datasets and used the most likely parameters calibrated by core measurements to improve the reservoir modeling of the complex Matulla reservoir. In addition, we reduced many of the common uncertainties associated with the static modeling process, which can be applied elsewhere to gain better understanding of a complex reservoir.

Research on the Construction of a Petrophysical Model of a Heterogeneous Reservoir in the Hydrate Test Area in the Shenhu Area of the South China Sea (SCS)

The occurrence characteristics of hydrates in the Shenhu area reflect a typical inhomogeneity in terms of spatial distribution. It is difficult to accurately describe the petrophysical properties of a reservoir using a petrophysical model considering a single cementation factor parameter. According to the analysis of a mathematical model and the estimation results of V p and V s , the unique structure of foraminiferal sediment particles provides opportunities for forming a diversified hydrate occurrence in the foraminiferal area. In areas where hydrates are thin and interbedded, hydrate reservoirs are generally three-phase media, with obvious thermoelastic properties. Therefore, the parameters of the three characteristic models of the pore-filling model, particle cementation model, and thermodynamic elastic model are all included in the correction model. The weights of the influence factors are then changed to realize an accurate description of the petrophysical characteristics of the correction model in different drilling areas and at different formation depths, reducing the limitations of using a single petrophysical model to describe the petrophysical characteristics of heterogeneous regions under the influence of multiple factors.

3D Numerical Simulations of Non-Volcanic CO2 Degassing in Active Fault Zones Based on Geophysical Surveys

An integrated approach that combines geophysical surveys and numerical simulations is proposed to study the processes that govern the fluid flow along active fault zones. It is based on the reconstruction of the architecture of the investigated fault system, as well as the identification of possible paths for fluid migration, according to the distribution of geophysical parameters retrieved by multi-methodological geophysical prospecting. The aim is to establish, thanks to constraints deriving from different types of data (e.g., geological, geochemical and/or hydrogeological data), an accurate 3D petrophysical model of the survey area to be used for simulating, by numerical modelling, the physical processes likely taking place in the imaged system and its temporal evolution. The effectiveness of the proposed approach is tested in an active fault zone in the Matese Mts (southern Italy), where recent, accurate geochemical measurements have registered very high anomalous values of non-volcanic natural emissions of CO2. In particular, a multi-methodological geophysical survey, consisting of electrical resistivity tomography, self-potential and passive seismic measurements, integrated with geological data, was chosen to define the 3D petrophysical model of the investigated system and to identify possible source geometries. Three different scenarios were assumed corresponding to three different CO2 source models. The one that hypothesizes a source located along the fault plane at the depth of the carbonate basement was found to be the best candidate to represent the test site. Indeed, the performed numerical simulations provide CO2 flow estimates comparable with the values observed in the investigated area. These findings are promising for gas hazards, as they suggest that numerical simulations of different CO2 degassing scenarios could forecast possible critical variations in the amount of CO2 emitted near the fault.

An Example of Building a Petrophysical Model of Unconsolidated Gas-Saturated Laminated Sediments Using Advanced Wireline and Logging While Drilling Services

Productive deposits of the Turonian age as part of the Kuznetsovskaya Formation are cover the eastern part of Western Siberia (Figure 1), but until recently they were not of wide industrial interest. Today, most of the gas reserves in Western Siberia are produced in the Cenomanian deposits, which are in the stage of declining production. The productivity of the deposits above Cenomanian layer has been established in many fields where the Cenomanian formations are productive. In general, in Western Siberia in the Turonian deposits, there are more than 3 trillion cubic meters of gas, which allows us to consider them as high-potential sources of gas reserves. The main difficulties in the industrial development of Turonian deposits are reduced permeability, high dissection, high content of clay fraction, high macro- and microheterogeneity of the reservoir, inconsistency of effective thicknesses in plan and section. In turn, the relatively low temperature of the reservoir predetermines the operation of the field in a mode close to hydration (Avramenko et all., 2019). Under these conditions, a good petrophysical baseline is essential to assess the exploration potential of the assets and design the development of the reservoir. Shaly gas-saturated formations are not a simple object for petrophysical modeling. Adding to this the low quality of the core material caused by the weak cementation of shallow deposits, we get a very nontrivial problem. On the other hand, modern horizontal well development scenarios dictate their requirements for petrophysical models. In other words, the petrophysical model must maintain its stability for any well logging regardless of the well trajectory (vertical or horizontal) and the logging method conveyance (wireline or while drilling). The authors of the paper carried out work on the development of a universal petrophysical model of the Turonian reservoir, for one of the fields in the region of the north of Western Siberia, based on a modern extended GIS complex.

Identification of Drilling Efficiency Using Log-Derived Cation Exchange Capacity in Shale Formation

Shale and shaly formations constitute about 70% to 80% of the total rock formations drilled worldwide, and the most of footage drilled in gas and oil wells is in shale and shaly rocks. Drilling in shale sections in many cases causes wellbore instability and slow drilling problems. In this study, cation exchange capacity of shale is estimated using a relatively simple petrophysical model. The validation of this model is achieved with experimental values of cation exchange capacity. The estimation of cation exchange capacity by this model and common logs data has exhibited potentiality for distinguishing effective/ineffective drilling in shale formations. Drilling and petrophysical data gathered at controlled condition is required in order to optimize the proposed technique. Have knowledge of properties and location of shales permits for remedial actions in future offset well or while drilling in case of logging while drilling (LWD) is used

Interval maximum likelihood inversion for well logging data and statistical properties of estimated parameters

During the conventional petrophysical interpretation fixed (predefined) zone parameters are applied for every interpretation zone (depth intervals). Their inclusion in the inversion process requires the extension of a likelihood function for the whole zone. This allows to define the extremum problem for fitting the parameter set to the full interval petrophysical model of the layers crossed by the well, both for the parameters associated with the depth points (e.g. porosity, saturations, rock matrix composition etc.) and for the zone parameters (e.g. formation water resistivity, cementation factor etc.). In this picture the parameters form a complex coupled and correlated system. Even the local parameters associated with different depths are coupled through the zone parameter change. In this paper, the statistical properties of the coupled parameter system are studied which fitted by the Interval Maximum Likelihood (ILM) method. The estimated values of the parameters are coupled through the likelihood function and this determines the correlation between them.

Rock Physics Diagnostics as a prerequisite for optimal Petrophysics

One of the key outputs from petrophysical evaluation is porosity. Sonic log is considered as one of the logs for deriving petrophysical volumes including porosity. However, the sonic data might not be always suitable to be included in the petrophysical model even if the quality of the log is quite good. One of the key reasons lies behind the variable porosity-velocity relationship for different types of formations attributed to post depositional processes. Without performing proper rock physics diagnostics before petrophysics model building can create inconsistencies in the petrophysical volumes as well as force the petrophysicist to use unreasonable endpoints for matrix or fluid. In this paper, an attempt is made to perform rock physics diagnostics using Wyllie-time-average and Raymer-Hunt-Gardner relations, drawing conclusion on the consolidation state of the rock, followed by computation of porosity from sonic using these relations. Later, rock physics diagnostic using theoretical rock physics models is carried out to confirm and complement this understanding of rock’s consolidation state. The results show that even though these empirical relations in their original form are useful and widely used but it is not quite suitable for unconsolidated and weakly cemented (poorly consolidated) formations or at least cannot justify the porosity-velocity trend in the data. Here computed sonic porosity is compared with field calibrated density porosity. It could be seen from this study that, in order to match sonic porosity with density porosity, an unreasonable matrix/fluid endpoints or non-theoretical empirical fitting coefficient is required. Since, this might not always be the case, a proper assessment using rock physics diagnostic should be carried out before incorporating sonic data into the petrophysical model.

Pre-Jurassic Formation Lithological Composition and Reservoir Characteristic Variation Analysis. Core and Field Tests Analysis in Frolovsky and Shaimsky Petroliferous Regions

Analysis of the lithology of rocks of the pre-Jurassic complex and changes in the reservoir properties of rocks is one of the most important and difficult tasks for the formation of a petrophysical model for the interpretation of well logging data. Despite the long history of geological and geophysical study of deposits of the pre-Jurassic complex, a number of issues related to the reflection in the geophysical parameters of rocks and characteristics of reservoir properties have been studied insufficiently. This is due to the high variability of the lithological composition, textural and structural heterogeneity of the volcanic-sedimentary strata of the Turin Group. At present, the sediments of the pre-Jurassic complex are being actively studied - a representative core is purposefully selected, which is studied using an SCAL, including special methods, modern precision electrical, radioactive and acoustic studies are included in the complex of geophysical studies. The results of new studies are a good information base for refining the petrophysical model of an extraordinary object of study. The aim of this work was to analyze the lithology and reservoir properties of rocks, as well as to identify and classify the main groups of rocks that are possible reservoirs in the sediments of the pre-Jurassic complex within the Frolovsky and Shaimsky petroliferous regions.