Three-Dimensional Modelling of a Multi-Layer Sandstone Reservoir： the Sebei Gas Field, China

Multi-layer sandstone reservoirs occur globally and are currently in international production. The 3D characteristics of these reservoirs are too complicated to be accurately delineated by general structural-facies-reservoir modelling. In view of the special geological features, such as the vertical architecture of sandstone and mudstone interbeds, the lateral stable sedimentation and the strong heterogeneity of reservoir poroperm and fluid distribution, we developed a new three-stage and six-phase procedure for 3D characterization of multi-layer sandstone reservoirs. The procedure comprises two-phase structural modelling, two-phase facies modelling and modelling of two types of reservoir properties. Using this procedure, we established models of the formation structure, sand body structure and microfacies, reservoir facies and properties including porosity, permeability and gas saturation and provided a 3D fine-scale, systematic characterization of the Sebei multi-layer sandstone gas field, China. This new procedure, validated by the Sebei gas field, can be applied to characterize similar multi-layer sandstone reservoirs.

A 3D analysis of the occurrence of fractures in hot dry rock reservoirs based on the spatial distribution of natural fractures

Hot dry rock(HDR)geothermal energy is a kind of widely distributed clean energy with huge reserves.However,its commercial development has been constrained by reservoir stimulation.In the early stage of HDR geothermal energy development,properly determining spatial distribution patterns of natural fractures in HDR reservoirs can effectively guide reservoir stimulation.This study analyzes the spatial distribution of natural fractures by using FracMan software based on the actual geological data and log data of well M-2 in the Matouying Uplift area,Hebei Province.The fracture parameters are counted and Monte Carlo simulation technique is introduced to optimize the parameters,which makes the natural fracture model more accurate and reliable.Furthermore,this study simulates hydraulic fracturing using the model combined with the actual in-situ stress parameters and the construction scheme.As verified by fitting the changes in simulated wellhead pressure during hydraulic fracturing with the actual wellhead pressure data detected during construction,the methods for natural fracture modeling used in this study are scientific and reasonable.The preliminary prediction results show that the displacement design scheme with a pump displacement of 2.0-3.0 m^(3)/min,4.0-5.5 m^(3)/min and 6-7 m^(3)/min in the early,middle and late stages,respectively,has good fracturing effect.The results of this study can be utilized as a reference for preparing development schemes for HDR reservoirs.

Formation conditions and reservoir-forming models of the Ordovician buried hill reservoirs in the Jizhong depression

The buried hill in the Jizhong depression contains abundant petroleum reserves and are important production areas.The Ordovician buried hill has restricted the discovery of new oil and gas exploration targets because of its strong reservoir heterogeneity and complex reservoir-controlling factors.Based on a large volume of core,thin section,logging,seismic,and geochemical data and numerous geological analyses,the reservoir-forming conditions and modes were systematically analyzed to guide the exploration and achieve important breakthroughs in the Yangshuiwu and Wen an slope buried hills.The study revealed that three sets of source rocks of the third and fourth members of the Shahejie Formation from the Paleogene and Carboniferous-Permian were developed in the Jizhong depression,providing sufficient material basis for the formation of buried hill oil and gas reservoirs.The reservoir control mechanism involving the three major factors of“cloud-karst-fault”was clarified,and karst cave,fracture fissure-pore,and cloud pore type reservoir models were established,thereby expanding the exploration potential.Controlled by the superposition of multi-stage tectonic processes during the Indosinian,Yanshanian,and Himalayan,two genetic buried hill trap types of uplift-depression and depression-uplift were formed.Based on the analysis of reservoir-forming factors of the Ordovician buried hill,three buried hill oil and gas reservoir-forming models were identified:low-level tectonic-lithologic composite quasi-layered buried hill,medium-level paleo-storage paleo-block buried hill,and high-level paleo-storage new-block buried hill.Comprehensive evaluations indicate that the reservoir-forming conditions of the low-level tectonic-lithologic composite quasi-layered buried hill in the northern portion of the Jizhong depression are the most favorable and that the Sicundian and Xinzhen buried hills are favorable areas for future exploration.

The source and formation characteristics of the Zhujiadun gas reservoirs in the Yancheng Sag, Subei Basin

The Yancheng Sag is a favorable exploration area in the Subei Basin. However, the key geological understanding of the natural gas source and reservoir formation characteristics of the sag is still controversial. Based on a set of organic geochemical experiments conducted on natural gas and associated condensate oil of the first member of the Funing Formation (E1f1) in well YCh5 and well data analysis, the oil-gas resources and reservoir formation model in the Zhujiadun gas reservoir in the Yancheng Sag, Subei Basin, were investigated. The results of this study are as follows. (1) The natural gas in the Zhujiadun gas reservoir is dry gas with high methane content, low heavy hydrocarbon content, and high maturity. The characteristics of carbon and hydrogen isotopes in the natural gas indicate that the natural gas is oil-cracked gas, which mainly originates from the source rocks of the Permian Qixia Formation. (2) The condensate oil from well YCh5 with a high degree of maturity has a high pristane/phytane ratio, low gamma-paraffin abundance, and low tricyclic terpene abundance, indicating a mixture of the Upper Paleozoic condensate oil and Cenozoic crude oil. The saturated and aromatic hydrocarbons have similar δ13C values to the Cenozoic continental crude oil. These features suggest two sources of condensate oil. (3) Oils generated from the source rocks of the Qixia Formation were cracked into highly mature gas after deep burial, which migrated along large faults into the sandstones of the E1f1 and K1t1 members. This type of reservoir was effectively preserved beneath the overlying mudstone cap rocks. Therefore, it can be inferred that a play fairway might occur in the eastern zone of the faults connected to the Paleozoic source rocks in the Yancheng Sag since this zone has similar petroleum geological conditions to well YCh5. Therefore, this zone is a favorable area for further exploration.

The Classification and Model of Coalbed Methane Reservoirs

Coalbed methane has been explored in many basins worldwide for 30 years, and has been developed commercially in some of the basins. Many researchers have described the characteristics of coalbed methane geology and technology systematically. According to these investigations, a coalbed methane reservoir can be defined: 'a coal seam that contains some coalbed methane and is isolated from other fluid units is called a coalbed methane reservoir'. On the basis of anatomization, analysis, and comparison of the typical coalbed methane reservoirs, coalbed methane reservoirs can be divided into two classes: the hydrodynamic sealing coalbed methane reservoirs and the self-sealing coalbed methane reservoirs. The former can be further divided into two sub-classes: the hydrodynamic capping coalbed methane reservoirs, which can be divided into five types and the hydrodynamic driving coalbed methane reservoirs, which can be divided into three types. The latter can be divided into three types. Currently, hydrodynamic sealing reservoirs are the main target for coalbed methane exploration and development; self-sealing reservoirs are unsuitable for coalbed methane exploration and development, but they are closely related with coal mine gas hazards. Finally, a model for hydrodynamic sealing coalbed methane reservoirs is established.

Full field reservoir modeling of shale assets using advanced data-driven analytics

Hydrocarbon production from shale has attracted much attention in the recent years. When applied to this prolific and hydrocarbon rich resource plays, our understanding of the complexities of the flow mechanism（sorption process and flow behavior in complex fracture systems- induced or natural） leaves much to be desired. In this paper, we present and discuss a novel approach to modeling, history matching of hydrocarbon production from a Marcellus shale asset in southwestern Pennsylvania using advanced data mining, pattern recognition and machine learning technologies. In this new approach instead of imposing our understanding of the flow mechanism, the impact of multi-stage hydraulic fractures, and the production process on the reservoir model, we allow the production history, well log, completion and hydraulic fracturing data to guide our model and determine its behavior. The uniqueness of this technology is that it incorporates the so-called ＂hard data＂ directly into the reservoir model, so that the model can be used to optimize the hydraulic fracture process. The ＂hard data＂ refers to field measurements during the hydraulic fracturing process such as fluid and proppant type and amount, injection pressure and rate as well as proppant concentration. This novel approach contrasts with the current industry focus on the use of ＂soft data＂（non-measured, interpretive data such as frac length, width,height and conductivity） in the reservoir models. The study focuses on a Marcellus shale asset that includes 135 wells with multiple pads, different landing targets, well length and reservoir properties. The full field history matching process was successfully completed using this data driven approach thus capturing the production behavior with acceptable accuracy for individual wells and for the entire asset.

A unified model for the formation and distribution of both conventional and unconventional hydrocarbon reservoirs

The discovery and large-scale exploration of unconventional oil/gas resources since 1980s have been considered as the most important advancement in the history of petroleum geology;that has not only changed the balance of supply and demand in the global energy market,but also improved our understanding of the formation mechanisms and distribution characteristics of oil/gas reservoirs.However,what is the difference of conventional and unconventional resources and why they always related to each other in petroliferous basins is not clear.As the differences and correlations between unconventional and conventional resources are complex challenging issues and very critical for resources assessment and hydrocarbon exploration,this paper focused on studying the relationship of formations and distributions among different oil/gas reservoirs.Drilling results of 12,237 exploratory wells in 6 representative petroliferous basins of China and distribution characteristics for 52,926 oil/gas accumulations over the world were applied to clarify the formation conditions and genetic relations of different oil/gas reservoirs in a petroliferous basin,and then to establish a unified model to address the differences and correlations of conventional and unconventional reservoirs.In this model,conventional reservoirs formed in free hydrocarbon dynamic field with high porosity and permeability located above the boundary of hydrocarbon buoyancy-driven accumulation depth limit.Unconventional tight reservoirs formed in confined hydrocarbon dynamic field with low porosity and permeability located between hydrocarbon buoyancy-driven accumulation depth limit and hydrocarbon accumulation depth limit.Shale oil/gas reservoirs formed in the bound hydrocarbon dynamic field with low porosity and ultra-low permeability within the source rock layers.More than 75%of proved reserves around the world are discovered in the free hydrocarbon dynamic field,which is estimated to contain only 10%of originally generated hydrocarbons.Most of undiscovered resources distributed in the confined hydrocarbon dynamic field and the bound hydrocarbon dynamic field,which contains 90%of original generated hydrocarbons,implying a reasonable and promising area for future hydrocarbon explorations.The buried depths of hydrocarbon dynamic fields become shallow with the increase of heat flow,and the remaining oil/gas resources mainly exist in the deep area of“cold basin”with low geothermal gradient.Lithology changing in the hydrocarbon dynamic field causes local anomalies in the oil/gas dynamic mechanism,leading to the local formation of unconventional hydrocarbon reservoirs in the free hydrocarbon dynamic field or the occurrence of oil/gas enrichment sweet points with high porosity and permeability in the confined hydrocarbon dynamic field.The tectonic movements destroy the medium conditions and oil/gas components,which leads to the transformation of conventional oil/gas reservoirs formed in free hydrocarbon dynamic field to unconventional ones or unconventional ones formed in confined and bound hydrocarbon dynamic fields to conventional ones.

The impact of geological uncertainty on primary production from a fluvial reservoir

Deposition of fluvial sandbodies is controlled mainly by characteristics of the system, such as the rate of avulsion and aggradation of the fluvial channels and their geometry. The impact and the interaction of these parameters have not received adequate attention. In this paper, the impact of geological uncertainty resulting from the interpretation of the fluvial geometry, maximum depth of channels, and their avulsion rates on primary production is studied for fluvial reservoirs. Several meandering reservoirs were generated using a process-mimicking package by varying several con- trolling factors. Simulation results indicate that geometrical parameters of the fluvial channels impact cumulative pro- duction during primary production more significantly than their avulsion rate. The most significant factor appears to be the maximum depth of fluvial channels. The overall net-to-gross ratio is closely correlated with the cumulative oil production of the field, but cumulative production values for individual wells do not appear to be correlated with the local net-to-gross ratio calculated in the vicinity of each well. Connectedness of the sandbodies to each well, defined based on the minimum time-of-flight from each block to the well, appears to be a more reliable indicator of well-scale production.

3D numerical simulation of heterogeneous in situ stress field in low-permeability reservoirs

Analysis of the in situ stress orientation and magnitude in the No.4 Structure of Nanpu Sag was performed on the basis of data obtained from borehole breakout and acoustic emission measurements.On the basis of mechanical experiments,logging interpretation,and seismic data,a 3 D geological model and heterogeneous rock mechanics field of the reservoir were constructed.Finite element simulation techniques were then used for the detailed prediction of the 3 D stress field.The results indicated that the maximum horizontal stress orientation in the study area was generally NEE-SWW trending,with significant changes in the in situ stress orientation within and between fault blocks.Along surfaces and profiles,stress magnitudes were discrete and the in situ stress belonged to theⅠa-type.Observed inter-strata differences were characterized as five different types of in situ stress profile.Faults were the most important factor causing large distributional differences in the stress field of reservoirs within the complex fault blocks.The next important influence on the stress field was the reservoir’s rock mechanics parameters,which impacted on the magnitudes of in situ stress magnitudes.This technique provided a theoretical basis for more efficient exploration and development of low-permeability reservoirs within complex fault blocks.

Subsurface analytics: Contribution of artificial intelligence and machine learning to reservoir engineering, reservoir modeling, and reservoir management

Traditional Numerical Reservoir Simulation has been contributing to the oil and gas industry for decades.The current state of this technology is the result of decades of research and development by a large number of engineers and scientists.Starting in the late 1960s and early 1970s,advances in computer hardware along with development and adaptation of clever algorithms resulted in a paradigm shift in reservoir studies moving them from simplified analogs and analytical solution methods to more mathematically robust computational and numerical solution models.

Application of Pore Evolution and Fracture Development Coupled Models in the Prediction of Reservoir "Sweet Spots" in Tight Sandstones

The Chang-63 reservoir in the Huaqing area has widely developed tight sandstone ＂thick sand layers, but not reservoirs characterized by rich in oil＂, and it is thus necessary to further study its oil and gas enrichment law. This study builds porosity and fracture development and evolution models in different deposition environments, through core observation, casting thin section, SEM, porosity and permeability analysis, burial history analysis, and ＂four-property-relationships＂ analysis.

Sarvak Formation Reservoir Modeling, in Oilfield Kuhmond (Southwestern Iran)

Sarvak formation is one of the important hydrocarbon reservoirs in the Zagros Basin that is one of the mid-Cretaceous carbonate units in Bangestan. This formation is located in the Kazhdomi Formation with the same slope. Geology, Kohmond field is located in the southeast of Bushehr and north and northwest of the Fars province. In this project, the geology, the tank and Petrophysics features were studied in the field with sedimentology;stratigraphy, Petrophysics, sedimentary environments and reservoir data analysis. According to studies, sedimentary environment of Sarvak in the Kohmond field is diagnosed as a ramp carbonate platform. Sarvak reservoir modeling in this field was done by using Petrelli software. The results indicate parts with high porosity, which are focused more in central and southeastern parts of the field and can contain large amounts of oil.

Application of Seismic Data to Reservoir Modeling of the Chegu 201 Block

Great uncertainty exists in reservoir models built for blocks where well spacing is uneven or large. The uncertainty in reservoir models can be significantly reduced by using Coordinate Cokriging Sequential Gaussian Simulation technology, in combination with the restriction of seismic characteristic data. Satisfactory reservoir parameter interpolation results, which are more accurate than those derived only from borehole data, are obtained, giving rise to a reasonable combination of widespread and dense-sampled seismic (soft data) data with borehole data (hard data). A significant effect has been made in reservoir parameter modeling in the Chegu 201 block of the Futai Oilfield by using this technology.

Integrating the geology, seismic attributes, and production of reservoirs to adjust interwell areas: A case from the Mangyshlak Basin of West Kazakhstan

Dynamic models of the seismic,geological,and flow characteristics of a reservoir are the main tool used to evaluate the potential of drilling new infill wells.Static geological models are mainly based on borehole data combined with dynamic analyses of production dynamics.They are used to determine the redevelopment of and adjustments to new drilling locations;however,such models rarely incorporate seismic data.Consequently,it is difficult to control the changes in geological models between wells,which results in the configuration of well positions and predicted results being less than ideal.To improve the development of adjusted areas in terms of their remaining oil contents,we developed a new integrated analysis that combines static sediment modelling,including microfacies analysis(among other reservoir and seismic properties),with production behaviours.Here,we illustrate this new process by(1)establishing favourable areas for static geological analysis;(2)studying well recompletion potential and the condition of non-producing wells;(3)conducting interwell analyses with seismic and sedimentary data;(4)identifying potential sites constrained by seismic and geological studies,as well as initial oilfield production;(5)providing suggestions in a new well development plan.

Static Reservoir Modeling, a Case Study from Early Cretaceous Yamama Formation, Southern Iraq

Constructing a static reservoir model or a 3D geological model is a widely used modern tool to employ subsurface information expose the setting and properties of hydrocarbon reservoirs. The current study attempts to build a 3D reservoir model of the Yamama Formation (an important oil reservoir in Southern Iraq), from digital logs data and drilling information. This would lead to a better understanding of the relationships between different reservoir elements, then expose many characteristics of the reservoir, such as the facies distribution and petrophysical properties. The data of the Yamama Formation (Early Cretaceous Carbonates) were taken from four wells of Gharraf Oilfield, Southern Iraq (GA-1, GA-2, GA-3, and GA-4). The adopted modeling approach consists of a series of steps starting with a preliminary analysis of data, followed by interpretation of these data, and terminated by geostatistical methods for building the structural model. The modeling was assisted by defining the top of each layer detected by wireline logs and final well reports of each studied well. The results of the study encompass four microfacies distributed between Inner Ramp and Mid Ramp environments. The followed 3D geological modeling scheme was capable to visualize the distribution of petrophysical properties, and the classification of Yamama Formation into several layers or reservoir units (Y1 to Y5), and thirteen subdivisions (minor units). The model could also define the places where effective porosity was enhanced. The process of Pillar Gridding, a step within the modeling, showed that the Yamama Formation is composed of two domes. The constructed model was helpful, based on the evaluation of petrophysical parameters, then to point out the most important reservoir zone (Zone Y3_top) that has Effective Porosity of (13.6%) and water saturation of around (10.6%).

Application of 3D Reservoir Geological Model on Es1 Formation, Block Nv32, Shenvsi Oilfield, China

Three-dimensional geological modeling of reservoirs is an essential tool to predict reservoir performance and improve the understanding of reservoir uniqueness in Es1 formation. The paper focuses on the use of petrel software to build three-dimensional reservoir geological model which characterizes and assesses block Nv32 that located in the west of the Shenvsi oilfield in the south of Cangzhou city, Hebei province of China, and has an oil-bearing area of 1.4 km2. This study is depending on integration data from well logs of 22 wells which provided from geology, geophysics, and petrophysics to identify and provide precise depict of the subsurface internal structure and the reservoir heterogeneity. Input data was used to build the structural model, sedimentary facies model, petrophysical properties (porosity, permeability, saturation, and N/G model, and finally to determine the reservoir volume. The lithological facies were simulated using the assigned value method. Moreover, Petrophysical properties (Porosity, permeability, oil saturation and net to gross) were constructed for each zone using the Sequential Gaussian Simulation method to guide the distribution of petrophysical properties of Es1 formation, block Nv32. Statistical analysis of the porosity, permeability, oil saturation and N/G model present that the porosity occurrence distribution is mainly concern between 0.2% - 36.39% of block Nv32 with an average porosity value of 17.5%, permeability between 0.017 mD to 974.8 mD, having an average permeability of 59.44 mD, oil saturation between 0.00 to 0.95 having an average value of 0.22, and N/G is mainly concentrated between 0.01 to 1.00 within an average value of 0.61. This research has indicated the reliability of the three-dimensional model technique as a suitable tool to provide a sufficient understanding of petrophysical distribution. The south-western and north-western indicate that oilfield is very promising an exploratory well should be drilled to find out the thickness and size of the reservoir.

Machine learning inspired workflow to revise field development plan under uncertainty

We present an efficient and risk-informed closed-loop field development (CLFD) workflow for recurrently revising the field development plan (FDP) using the accrued information. To make the process practical, we integrated multiple concepts of machine learning, an intelligent selection process to discard the worst FDP options and a growing set of representative reservoir models. These concepts were combined and used with a cluster-based learning and evolution optimizer to efficiently explore the search space of decision variables. Unlike previous studies, we also added the execution time of the CLFD workflow and worked with more realistic timelines to confirm the utility of a CLFD workflow. To appreciate the importance of data assimilation and new well-logs in a CLFD workflow, we carried out researches at rigorous conditions without a reduction in uncertainty attributes. The proposed CLFD workflow was implemented on a benchmark analogous to a giant field with extensively time-consuming simulation models. The results underscore that an ensemble with as few as 100 scenarios was sufficient to gauge the geological uncertainty, despite working with a giant field with highly heterogeneous characteristics. It is demonstrated that the CLFD workflow can improve the efficiency by over 85% compared to the previously validated workflow. Finally, we present some acute insights and problems related to data assimilation for the practical application of a CLFD workflow.

Enhanced history matching process by incorporation of saturation logs as model selection criteria

This paper proposes a methodology for an alternative history matching process enhanced by the incorporation of a simplified binary interpretation of reservoir saturation logs(RST) as objective function. Incorporating fluids saturation logs during the history matching phase unlocks the possibility to adjust or select models that better represent the near wellbore waterfront movement, which is particularly important for uncertainty mitigation during future well interference assessments in water driven reservoirs. For the purposes of this study, a semi-synthetic open-source reservoir model was used as base case to evaluate the proposed methodology. The reservoir model represents a water driven, highly heterogenous sandstone reservoir from Namorado field in Brazil. To effectively compare the proposed methodology against the conventional methods, a commercial reservoir simulator was used in combination with a state-of-the-art benchmarking workflow based on the Big LoopTMapproach. A well-known group of binary metrics were evaluated to be used as the objective function, and the Matthew correlation coefficient(MCC) has been proved to offer the best results when using binary data from water saturation logs. History matching results obtained with the proposed methodology allowed the selection of a more reliable group of reservoir models,especially for cases with high heterogeneity. The methodology also offers additional information and understanding of sweep behaviour behind the well casing at specific production zones, thus revealing full model potential to define new wells and reservoir development opportunities.