Reservoir Petrophysical Parameters Research Articles

Three dimensional time-variation simulator for water flooding reservoir based on “effective water flux”

Long-term water flooding leads to changes in pore throat structure, resulting in alterations in macroscopic reservoir petrophysical parameters. However, commercial numerical simulation software does not have this capability. Ignoring variations in physical parameters during the formulation of development plans and numerical simulations can lead to significant prediction errors, which severely impacts oil field recovery. This paper, based on an analysis of effective flow rate and waterflood intensity, proposes a new erosion degree characterization parameter: Effective water flux, to represent the time-varying patterns of physical parameters. It is embedded into a black oil model to develop a time-variation simulator, whose accuracy and stability in both black oil and time-variation models are validated through comparison with the commercial numerical simulation software CMG. The study further explores the effects of different parameter variations on the development process. It was found that increases in permeability and oil viscosity exacerbate heterogeneity and reduce displacement efficiency, while decreases in residual oil saturation and water phase permeability under residual oil saturation enhance water flooding efficiency. In complex models, the effects of variations in different parameters intertwine, collectively influencing development outcomes. This paper advances the development of time-variation numerical simulation technology.

Response Patterns of Acoustic Wave Characteristics to Reservoir Petrophysical Parameters in Different Bedding Directions: A Case Study of Low- and Middle-Rank Coals in Xinjiang, China.

The physical properties of coal reservoirs, important parameters for evaluating the production potential of coalbed methane (CBM) resources, can be assessed nondestructively and in real-time using acoustic wave technology. In this study, we collected 48 low- and middle-rank coal samples oriented in different bedding directions from seven typical coal mines, encompassing the Zhunan, Tuha, and Kuqa-Bay coalfields in Xinjiang, China. We clarified the characteristics of the physical parameters (apparent density, fracture, porosity, and permeability) and acoustic wave of coal variations through acoustic wave, porosity, and permeability experiments, revealing the response law of acoustic wave characteristics to the physical parameters of coal. The results indicated that the acoustic wave velocity and dynamic elastic modulus (E d) of coal samples oriented in the perpendicular bedding direction are larger than those oriented in the parallel bedding direction; however, the dynamic Poisson's ratio (μd) of coal samples oriented in different bedding directions does not significantly differ. The existence of fractures significantly reduces the acoustic wave velocity and E d of the coal. The greater the apparent density of coal, the tighter its structure, resulting in a faster acoustic wave velocity. The larger the porosity of coal, the greater its internal voids, leading to a more pronounced attenuation of acoustic energy and a slower acoustic wave velocity. The more developed and interconnected the bedding fractures of coal bodies oriented in the parallel bedding direction, the higher their permeability, resulting in a smaller decrease in acoustic wave velocity. Conversely, the more developed the bedding fractures of coal bodies oriented in the perpendicular bedding direction, the more pronounced their attenuation of acoustic wave velocity. Finally, the regression equations for E d with the square of P-wave velocity (V P 2) and μd with the square ratio of V P to S-wave velocity (V P 2/V S 2) were established for coal. The study findings can help evaluate and predict the reservoir quality of coal seams, assess CBM, and improve the safety and efficiency of its extraction.

A novel method to identify preferential flow paths by considering the time-varying effect of petrophysical parameters in ultra-high water-cut reservoirs

The continental clastic reservoirs mainly distributed in the eastern region of China are regarded as the “ballast stone” for ensuring national energy security. After long-term waterflooding, reservoir petrophysical parameters have changed drastically. When the ultra-high water-cut period is achieved, the preferential flow paths are widely distributed inside the reservoir, resulting in severe ineffective water circulation and high difficulty in inhibiting water cut rise and stabilizing oil production. Due to the slow calculation speed and low identification accuracy of the existing methods, it is crucial to propose a novel method to identify preferential flow paths by considering the time-varying impact of petrophysical parameters in ultra-high water-cut reservoirs. To tackle this issue, massive dynamic and static data are collected from typical water-drive reservoirs in the Daqing oilfield to analyze the dynamic characteristics of preferential flow wells and the time-variation laws of reservoir parameters. A rapid evaluation index system for preferential flow paths is thereafter established. By describing the time-variation of reservoir permeability and fluid apparent viscosity and introducing a dynamic flow resistance coefficient to infer the inter-well or inter-layer connectivity, a novel method with the time-varying effect of petrophysical parameters considered is developed to quickly identify preferential flow paths in ultra-high water-cut reservoirs. A critical criterion of preferential flow paths is further constructed. Finally, the proposed method is used to determine the spatial distribution of preferential flow paths in a typical block of the Daqing oilfield. Results demonstrate that, once a preferential flow path is formed, some distinct dynamic characteristics of injectors and producers will be exhibited. Based on the estimated dynamic flow resistance coefficient, the preferential flow paths are further classified into four types: non-preferential, primary preferential, intermediate preferential, and strong preferential flow paths. Using the proposed method, the identification accuracy of preferential flow paths exceeds 95%, and the identification speed is more than 10 times faster than the traditional methods.

Stability of THAI in situ combustion process in reservoirs with layers of grading permeabilities and porosities: Detailed qualitative investigations

The world-wide reserves of heavy oil, tar sand, and bitumen, etc., outweigh those of conventional oil by a factor of 7/3. Given that the conventional reserves are being rapidly depleted, the need to develop and produce the unconventional resources has never been so critical. However, the proven most efficient and environmentally-friendly technology, namely the THAI process, still requires further study, and it has no documented design procedures that factor in the non-ideal geological features of heavy oil and bitumen reservoirs. Throughout the literature, there is little reported on the effects of gradations in reservoir petro-physical parameters on the performance of the THAI process. Consequently, this work reports the results of numerical simulations for four different kinds of reservoirs, each having progressive gradations in permeabilities and porosities. The major findings from this in depth study include.(i) In terms of the temperature distribution, regardless of the permeability and porosity gradations, the high temperature zone is always skewed towards the highest permeabilities and porosities zone. Furthermore, it is found that, in any model in which the shoes of the VI wells have no direct communication pathway with the highest permeabilities and porosities zones of the reservoirs, the high temperature zones occur in two chambers, otherwise, there is one high temperature zone.(ii) It is found that generally, the combustion front tends to be lopsided in favour of the most permeable and porous zone. In the case of a bottom-up progressive increase in permeabilities and porosities (model L1), the single combustion front has greatest advance horizontally at the top and axially in the middle of the reservoir, while in model L2 (the converse of model L1), the combustion fronts propagated in two chambers before the chambers overlapped in the toe region of the HP well where it advanced fastest. Therefore, the combustion zone in model L1 was far more stable than in model L2.(iii) It is found that the combustion fronts in model L3, with the lowest permeabilities and porosities at the centre in the longitudinal direction, propagated in two chambers that overlapped each other around the toe region of the HP well and advanced greatest in the HP well and on either lateral edge of the reservoir. In model L4, which has lateral gradation in permeabilities and porosities, however, the thinner edge of the wedge-shape combustion front had advanced fastest along the vertical mid-plane where the HP well was located. Thus, the combustion zone in model L3 was far more stable than that in model L4.(iv) It is found that in all the models except model L4, there exist rich oil saturation zones in the most permeable and porous regions located ahead of the mobile oil zone (MOZ) of each reservoir. These are formed due to restrictions in the pathways via which the mobilised oil can drain into the HP well. In model L4, the HP well is already in the most permeable zone and consequently, the fluids that favourably reach there are rapidly gravity-drained into the HP well.

Assessment of reservoir petrophysical parameters using well logs for the Abu Madi Formation, Level III, in Baltim North Field, Nile Delta, Egypt; A case study on BN-2 well

Assessment of reservoir petrophysical parameters using well logs for the Abu Madi Formation, Level III, in Baltim North Field, Nile Delta, Egypt; A case study on BN-2 well

Petrophysical properties and volume estimation of hydrocarbon resources in x field, onshore niger delta: A reservoir characterization study

A reservoir characterization study was conducted on three wells located in X Field, situated in the Onshore region of the Niger Delta. A suite of conventional digital well logs was utilized to identify hydrocarbon-bearing reservoirs, determine reservoir petrophysical parameters, and infer the depositional environment. The study delineated four hydrocarbon-bearing reservoirs, labeled A, B, C, and D, with porosity estimates ranging from 25% to 27%, and permeability values varying from 1863.22md to 2759.78md. These results suggest that the reservoirs have good storage capacity and permit free flow of fluids, consistent with prior research in the Niger Delta. The water saturation values, ranging from 43% to 70% for Well X and 53% to 94% for Well Y, indicate the presence of significant hydrocarbon in reservoir C, while Well Z did not contain any hydrocarbon. The estimation of oil and gas resources indicated that Well X contains 1.11 X 105 barrels/acre of oil and 5.16 X 107 cubic feet/acre of gas, while Well Y contains 4.43 X 106 cubic feet of gas. The analysis of the volume of shale (0.15-0.19) revealed that the reservoirs range from slightly shaly sand to shaly sand. Based on the log motifs, the study suggests that the reservoirs are mainly fluvial channel deposits, and the rapid alternation of thin beds of sand and shale indicates deposits of delta progradation and river floodplain deposits.

A new approach to predict the formation pressure using multiple regression analysis: Case study from the Sukharev oil field reservoir – Russia

Formation pressure is an important indicator of field production potential. Currently, the common practice to estimate reservoir pressure is the hydrodynamic exploration test. This method requires shutting down the well, often for a long time. Such long shutdowns lead to less production from the reservoir and worsen the economics of the field. Here, we present the method for determining the pressure without shutting down the well by using statistical methods for such tasks. In this article, we describe the method of finding the formation pressure by using multidimensional multivariate analysis of the actual reservoir data from the Sukharev field. To build the model, several operational, geological, and reservoir properties at various stages of the field pressure were combined into a model to predict reservoir pressure. Results showed that with this simple statistical method, formation pressure varies in two distinctive stages. In the first stage, the formation pressure is influenced by the reservoir petrophysical parameters, whereas in the second stage, operational parameters were more prominent. Finally, three separate formations in the Sukharev field were examined to predict reservoir pressure, and the results were in very good agreement with the actual measured data. This confirmed that the method was practical and capable of predicting reservoir pressure at any time of the well's lifetime.

Joint Application of Diagenetic, Petrophysical and Geomechanical Data for Selecting Hydraulic Fracturing Candidate Zone

The more comprehensive information on the reservoir properties will help to better plan drilling and design production. Herein, diagenetic processes and geomechanical properties are notable parameters that determine reservoir quality. Recognizing the geomechanical properties of the reservoir as well as building a mechanical earth model play a strong role in the hydrocarbon reservoir life cycle and are key factors in analyzing wellbore instability, drilling operation optimization, and hydraulic fracturing designing operation. Therefore, the present study focuses on selecting the candidate zone for hydraulic fracturing through a novel approach that simultaneously considers the diagenetic, petrophysical, and geomechanical properties. The diagenetic processes were analyzed to determine the porosity types in the reservoir. After that, based on the laboratory test results for estimating reservoir petrophysical parameters, the zones with suitable reservoir properties were selected. Moreover, based on the reservoir geomechanical parameters and the constructed mechanical earth model, the best zones were selected for hydraulic fracturing operation in one of the Iranian fractured carbonate reservoirs. Finally, a new empirical equation for estimating pore pressure in nine zones of the studied well was developed. This equation provides a more precise estimation of stress profiles and thus leads to more accurate decision-making for candidate zone selection. Based on the results, vuggy porosity was the best porosity type, and zones C2, E2 and G2, having suitable values of porosity, permeability, and water saturation, showed good reservoir properties. Therefore, zone E2 and G2 were chosen as the candidate for hydraulic fracturing simulation based on their E (Young’s modulus) and ν (Poisson’s ratio) values. Based on the mechanical earth model and changes in the acoustic data versus depth, a new equation is introduced for calculating the pore pressure in the studied reservoir. According to the new equation, the dominant stress regime in the whole well, especially in the candidate zones, is SigHmax>SigV>Sighmin, while according to the pore pressure equation presented in the literature, the dominant stress regime in the studied well turns out to be SigHmax>Sighmin>SigV.

Sensitivity analysis of changing Reservoir Saturation involving Petrophysics and Rock Physics in ‘Royal G’ field, Niger Delta

Adequate reservoir information is needed for accurate reservoir characterization towards enhancement of hydrocarbon recovery. The reservoir petrophysical parameters and elastic (seismic) properties are related to the quantity of reservoir rock fluids as well as the interaction of fluid types in the reservoirs’ pore space. Apart from the usually study of the petrophysical properties, the elastic properties are also vital because they are affected by the pore fluids interchange during hydrocarbon production or extraction. This study is aimed at examining and predicting those elastic properties that are most responsive and sensitive to changes during the fluid substitution. Information from three well logs from the ‘Royal G’ field’ situated in Niger Delta (onshore) were used for the petrophysical analysis and rock physics interpretation. The 3D crossplot outcomes were established by utilising Gassmann's fluid replacement or substitution modelling evident considering 0% oil and 80% brine (full) saturations in the reservoirs. Reservoir A and B have porosity, permeability and hydrocarbon saturation of 10–29%, 285–670 mD and 62–90% respectively. The 3D crossplot of the pseudo elastic logs give descriptive and distinct lithology and definite fluid content separation. Rock properties identified and noted to be extremely sensitive/reactive for lithology as well as fluid differentiation in the probed reservoirs are Acoustic Impedance, Density, Poisson ratio and Lambda-Rho. The outcome will generally enhance production and recovery of hydrocarbon.

A novel custom ensemble learning model for an improved reservoir permeability and water saturation prediction

With the advances of technology, many new well logs have been acquired over the past decade that carries vital information about the reservoir and subsurface layers. Thus, identifying the most relevant data that can improve the determination and prediction of petrophysical parameters has become very challenging. There has been an increase in the application of machine learning models that can accurately determine the petrophysical parameters of reservoirs, but further studies are still in demand. In this study, enhanced data analytics were used together with the visualisation techniques to pre-process the wireline logs acquired from the Volve field in the North Sea.Descriptive statistical methods were used to understand the relationship between the variables (input and output parameters), followed by applying the Extreme Gradient Boosting (XGBoost) regression model to predict the reservoir permeability and water saturation. A new ensemble model of Random Forest and Lasso Regularisation with an enhanced feature engineering technique was then proposed to improve the accuracy of the results. It appeared that the proposed ensemble model has a better performance than the traditional XGBoost and the hybrid PCA-XGBoost models in terms of precision, consistency and accuracy. The immense potential of ensemble modelling to enhance reservoir characterisation has been demonstrated by the success of this research.

Reservoir quality of Abu Roash (G) member in Karama Oil Field, East Bahariya Concession, North Western Desert, Egypt

In the present study, well logs and petrophysical core data are integrated to analyze Abu Roash (G) reservoir characteristics in Karama oil field, North Western Desert, Egypt. Conventional core data analysis of about 64 samples from Karama-4 well had been used in characteristic evaluation of the target reservoir. These data include permeability (horizontal and vertical), porosity (helium and fluid summation), and matrix density. The available core data were used to generate statistical analysis, histograms and new relations for porosity, and permeability data. The core analysis results show fair porosity and permeability values where the lithology is mainly carbonate (limestone and dolomite) with some sandstone. Well logging data of 4 wells were analyzed to evaluate the reservoir petrophysical parameters. These parameters include gross thickness, net pay, effective porosity, shale volume, water saturation, and hydrocarbon saturation. These reservoir parameters are mapped to illustrate vertical plotting and the aerial distribution. The aerial distribution maps showed that the best locations of hydrocarbon accumulation are at south, southeastern, and southwestern directions of study area. The petrophysical parameters also offered in the form of vertical variation logs (vertical litho saturation cross plots). They indicate that the lithology is intercalations of carbonate, mud, and sand streaks. In sand streaks, there is an observed increasing in the values of total and effective porosities and hydrocarbon saturation as well as decreasing in shale volume and water saturation. The results give an impression that the sand streaks in the studied formation are good reservoirs where the effective porosity ranges from 18.3 to 33.3% and the hydrocarbon saturation reaches up to 61.5% in in some zones in the different wells.

Analytical modeling of effect of volume of shale different calculation methods on reservoir petrophysical parameters

The effect of volume of shale different calculation methods on reservoir petrophysical parameters was analytically modelled and evaluated using ‘PETRARCAL.’ It is essential to characterize the hydrocarbon reservoir as precisely as possible in other to calculate petrophysical properties of interest in the region and to decide the most effective way of recovering as much of the hydrocarbon as economically possible and to rank the reservoir involved in the integration of vast amount of data needed in reservoir characterization. A petrophysical parameter calculator ‘PETRARCAL’ was programmed. The graphic user interface was designed using MATLAB to calculate the reservoir petrophysical properties such as gamma-ray- Index, the volume of shale using different calculation methods, and other volumes of shale dependent petrophysical parameters such as permeability, porosity, hydrocarbon saturation, water saturation, and hydrocarbon pore volume were mathematically coded in MATLAB. The plot of all the computed volume of shale versus gamma-ray index for different mathematical relationships Showed a similarity between tertiary, consolidated, and Steiber volume of Shale computational methods, trending exponential to almost linear curve. However, the Clavier method was completely different, with a decrease hyperbola curve. From the wireline log, with GRlog of 52, GRMin of 19, and GRmax of 81, the computed IGR is 0.53228. The resulting shale volume is 0.360, 0.242, and 2.319 0.275 for Dresser consolidated, Dresser tertiary, Clavier, and Stieber computational methods. Density corrected porosity (ϕDC) values from the wireline were determined to be 69.8%, 73.7%, 4.5%, and 75.6% for dresser consolidated, dresser tertiary Clavier, and Steiber methods, respectively. Permeability was computed to be 10,778, 16,858, 0.0021, and 14,912 for consolidated, tertiary,Clavier, and Stieber methods, respectively. Arbitrary use of just any of the volume of shale calculation methods will be an abuse of its application without understanding the environment of study. PETPARCAL can be used as a petrophysical parameter calculator for quick reservoir evaluation for petrophysicists and geoscientists. The efficacy of MATLAB application in geoscience modeling is excellent as it has been applied in this study.

Quantitative assessment of the tight gas reservoirs in the Obaiyed field, Shushan Basin, NW Egypt

ABSTRACT Obaiyed field lies in northern west Shushan Basin, which considers one of the largest Mesozoic coastal basins in northeast Africa, with high thickness sediment from the Jurassic to Palaeogene. The petrophysical parameters show difficulty in the development of the high gas reserve in the field, which led us to assess the geological systems that could constrain the formation and evolution of the basin concerning the study field. We simulated the tectonic evolution of the basin using a 1D-Airy isostasy backstripping technique with python coding and PetoMode® software. Also, we evaluated the current reservoir petrophysical parameters using TechLog® software. Based on integrating our results, we propose that the Shushan Basin represents a natural case of a Continuous Basin-Centred Gas accumulations model (CBCG) because of four main reasons: a) the vast extension of the Khatatba Formation, b) the coexistence of the source and the reservoir rocks in the Khatatba Formation, c) the low-permeability and gas saturation accumulations of the Lower Safa Member and d) the abnormal pressure of the Lower Safa reservoir because of its compartmentalization, where each compartment has its pressure peak. At a regional scale, this study highlights the effect of tectonics in the evolution of the basins.

СРАВНИТЕЛЬНАЯ ПЕТРОФИЗИЧЕСКАЯ ХАРАКТЕРИСТИКА РАЗРЕЗОВ ГЕРАСИМОВСКОГО И КРАПИВИНСКОГО МЕСТОРОЖДЕНИЙ (В СВЯЗИ С НЕФТЕГАЗОНОСНОСТЬЮ ДОЮРСКИХ ОТЛОЖЕНИЙ)

Актуальность исследования обусловлена необходимостью воспроизводства сырьевой базы углеводородов юго-востока Западной Сибири за счет поисков и разведки залежей, приуроченных к доюрским отложениям. Цель: определить критерии прогнозирования и поисков палеозойских залежей углеводородов на основе изучения геофизического различия разрезов юрских отложений месторождений, как с палеозойскими залежами нефти, так и месторождений только с юрскими залежами нефти. Объекты: разрезы глубоких скважин Герасимовского нефтегазоконденсатного месторождения с основными запасами в пласте М – в проницаемых интервалах коры выветривания отложений палеозоя и скважин Крапивинского нефтяного месторождения, промышленная нефтеносность которого связана с терригенными отложениями юрского продуктивного горизонта Ю1. Методы: статистический анализ петрофизических параметров пластов-коллекторов по данным геофизических исследований скважин, оценка литологического состава коллекторов по петрофизическому критерию, сопоставительная оценка геофизической характеристики баженовской свиты Герасимовского и Крапивинского месторождений. Результаты. На примере геофизической характеристики разрезов 29 глубоких скважин Герасимовского месторождения и 34 скважин Крапивинского месторождения показано, что палеозойские залежи имеют уникальное «отражение» в геолого-геофизических параметрах перекрывающего мезозойско-кайнозойского осадочного разреза. Эта уникальность выражается существенно более высокими значениями удельного электрического сопротивления и карбонатизацией интервалов юрских отложений, а также отличительной характеристикой геофизических параметров интервала баженовской свиты. Для дальнейшей аргументации уникальности «отражения» залежей палеозоя в геофизических параметрах перекрывающих отложений, как критерия прогнозирования и поисков палеозойских залежей УВ, предлагается провести аналогичные исследования на нескольких месторождениях как герасимовского, так и крапивинского типов.

Inflow performance relationship of vertical wells in fractured vuggy media during semi-steady state flow regime

The inflow performance relationship (IPR) is one of the essential key parameters that control the fluids production/injection rate from wells. The presence of the vugs in addition to fractures in carbonate reservoirs introduce many difficulties related the estimation of IPR of future wells. In this study, a novel analytical IPR of dual-permeability, triple porosity model is derived for the first time. The introduced IPR formula is derived for the standard scenario model of a vertical and fully penetrating well in a circular reservoir under single-phase flow of slightly compressible fluid. The three governing flow equations (matrix flow equation, fracture flow equation and interaction between vugs and other two continuum equation) are solved simultaneously as a system of differential equations for semi-steady state (SSS) flow regime. The generated SSS IPR is the same as Darcy's straight line IPR multiplied by an error parameter (E23) which is bounded between zero and one. A detailed investigation of the effect of the reservoir petro-physical parameters like storativities, inter-porosities and fracture to matrix permeability ratio are presented. The newly presented IPR of dual-permeability, triple porosity system can be reduced to sub-models IPRs by further modification of error parameter to fit sub-model as single permeability, triple porosity (E13) or dual permeability, dual porosity (E22). The presented IPR formula has the advantage of dividing the pressure drop of the fluid flow to two components, one for the internal resistance between different continuums (which is resented by E) and the other one is the radial flow in the same continuum toward/from well-bore. The generated IPR model is double verified using both cell pressure centred finite volume numerical simulation and conventional pressure transient analysis.

Simulation of NMR response from micro-CT images using artificial neural networks

The Nuclear Magnetic Resonance (NMR) log is amongst the functional techniques in petroleum investigation to segregating the reservoir and non-reservoir horizons precisely; furthermore, the NMR log provides an improved method to determine reservoir petrophysical parameters. Unfortunately, these data are usually sparse since acquiring NMR logs in producing cased wells is not possible and it is one of the most expensive tools in the logging industry thus its associated costs are the major limitation of its usage. Consequently, researchers have recently studied to virtually extract the NMR parameters via other routes. One such route, which we propose here is the possibility of estimating the T2 distribution curve and magnetization decay by establishing a relationship between micro-CT images and NMR parameters by means of artificial neural networks (ANN) and image analysis algorithms. Specifically, two ANN networks were designed, which numerically image features from micro-CT images as inputs, while the amplitude of the magnetization and relaxation time were output parameters. We assessed the procedure by taking the error rate and correlation coefficient into consideration and we conclude that the ANN model is capable of finding logical patterns between image features and NMR responses, and is thus able to reliably predict NMR response behavior. Furthermore, we quantitatively compared ANN and random walk (RW) NMR predictions, and we demonstrate that ANN readily outperforms RW in terms of accuracy.

Assessment of Hydrocarbon Potential in Owem Field in Niger Delta, Nigeria

Seismic data were integrated with well log to define the subsurface geometry and hydrocarbon trapping potential of Owem field, onshore Niger Delta. The research methodology involved horizon and fault interpretation to produce subsurface structural map. Wireline logs signatures were employed to identify hydrocarbon bearing sand and compute reservoir petrophysical parameters for hydrocarbon reservoir analysis. Two horizons HA and HB were identified and mapped and a time structural map was produced. Two reservoirs R1 and R2 were delineated in the wells A and B. The computed petrophysical parameters for well A showed that the thickness of Reservoir R1 and R2 are 11.5 and 12.5 meters respectively while the porosity and hydrocarbon saturation varies between 0.16 - 0.24 and 0.6 - 0.8 respectively. Similarly the average thickness and porosity of R1 and R2 for well B is about 18.0 meters and 0.12 while the hydrocarbon saturation varies between 0.7 - 0.8. The integration of seismic and well logs data has proved to be a useful tool in the reservoir analysis of hydrocarbon.

A stochastic modeling study of H56 block in Daqingzijing oilfield

After years of water injection, the underground movement of oil and water in Daqingzijing oilfield is becoming more and more complex, and the distribution of reservoir parameters between wells and remaining oil is difficult to predict. The reservoir geological model of H56 block in Daqingzijing oilfield is established with the support of numerous data by applying stochastic modeling techniques; it effectively reproduces the reservoir heterogeneity and distributes parameters in uncertain area between wells. A sequential indicator simulation algorithm is used to simulate the sedimentary facies, and facies-controlled reservoir characteristics have been performed including the reservoir petrophysical parameters and variability in the wells. In order to verify model accuracy, a comparison of porosity and permeability between model data and actual data is essentially made, the fitting of reserves and the original reserves were compared, and the whole field and the single well between the model and the history data were compared; the model shows consistency that gives confidence in using the model for numerical simulation purposes.

Forward modeling and inversion of induction logs from shaly sand reservoirs using petrophysical conductivity models

Algorithms and software have been designed for petrophysical 2D forward simulation and inversion of induction logs from oil wells drilled in shaly sandstone using conductivity models for different clay types. As comparative analysis of relative amplitudes and phases of tool responses has demonstrated, it is possible to reliably and accurately estimate fluid saturation and porosity from induction logs. The applied 2D numerical inversion of both theoretical and well logs yielded quantitative estimates of petrophysical parameters of reservoirs, with clay volume fraction assumed according to the chosen conductivity model. Correction for the presence of clay improves inversion quality if clay content as well as type are taken into account.

Using of Pickett’s plot in determining the reservoir characteristics in Abu Roash Formation, El-Razzak Oil Field, North Western Desert, Egypt

The present work was devoted to evaluate the reservoir characteristics of the Abu Roash Formation in the vicinity of El-Razzak Oil Field, North Western Desert, Egypt. The area of study is bounded by latitudes 30° 25′ and 30° 55′ N and longitudes 27° 50′ and 28° 40′ E. Nine distributed wells were utilized for this study.A new technique has been applied through Pickett’s plot, to develop some of reservoir petrophysical parameters. These parameters include capillary pressure, pore throat aperture radii, height above the free water table and bulk volume of water. This technique depends on the use of log–log plots of effective porosity versus resistivity combined with empirical relationships for calculating the capillary pressure expressed as a function of permeability, porosity and water saturation. Also, this technique gave the values of petrophysical exponents (m, n and a) which were used to calculate the accurate value of water saturation in both clean and shaly rocks and then adjust estimation of hydrocarbon saturation. The integration of these petrophysical parameters on a log–log graph of porosity versus resistivity gives the importance for Pickett plot to be used in reservoir interpretation.