Development Of Hydrocarbon Fields Research Articles

Improving the energy-efficiency of small-scale methanol production through the use of microturboexpander units

The issue of improving the energy-efficiency of container-based gas chemical plants for methanol production in field conditions is considered. The relevance of the direction is determined by the necessity for development of remote Arctic hydrocarbon fields. The object of research is energy-efficient conversion of waste gases energy and surplus thermal energy in small-scale system of methanol production using technology of synthesis gas generation by non-catalytic partial oxidation of natural gas. Approaches to the design and analysis of structural solutions for microturboexpander units are considered. A technique combining traditional approaches to the calculation of equipment and modeling by the finite element method in ANSYS is proposed. The developed methodology facilitates calculation of design parameters for microturboexpanders and allows taking into account peculiarities of working medium, thermobaric conditions and gas flow characteristics.

Consideration of geomechanical effects in reservoir simulation for hydrocarbon field development

This paper presents a review of mathematical models and functionality for consideration of geomechanical effects during hydrocarbon field development provided by modern flow simulation software (reservoir simulators). The discussed features include variation of reservoir properties with changes in fluid pressure; modular and coupled approaches to joint simulation of fluid flow and geomechanical processes; and available options for special geomechanical effects – such as erosion or formation of new fractures and impact on characteristics of existing fractures. Possible directions for further developments in this area of reservoir simulations are underlined.

Distribution of fractured reservoirs in the Chayanda field (Eastern Siberia)

The results of laboratory studies of nearly 1,300 samples from 50 wells of reservoirs of three productive terrigenous horizons represented by sandstones and siltstones are considered. Intergranular and fractured components mainly make up the porosity structure of reservoirs and their values influence the main parameters of rocks, including filtration-capacitive properties of reservoirs, and determine the processes of hydrocarbon field development. The spatial distribution of the intergranular and fractured components of reservoir porosity affects the development and exploitation of oil and gas reservoirs and determines the relevance of this study. The values of the fracture and intergranular component of porosity were determined by the author’s method using data on open porosity and the rate of elastic wave propagation in rock samples and the mineral skeleton of these samples during the simulation of reservoir conditions. A mosaic area distribution of fractured porosity values, caused by a long geological and tectonic history of the area development, was revealed. We identified zones of increased fractured porosity up to 0.7–0.8 % (percent absolute porosity) in the north and center of the western part of the field, and zones with minimum fractured porosity values of less than 0.2–0.3 % in the eastern part of the field. Results of laboratory core studies showed the presence of fractured porosity in reservoirs up to 1.26 %. The data on the size and distribution of fractured reservoirs across the Chayanda field area may be used to refine the field development project.

Prediction of Overpressure Zones in Marine Sediments Using Rock-Physics and Other Approaches

The paper discusses the problem of localizing zones of high pore pressure in sub-bottom sediments (first tens of meters under the seafloor). Prediction of the overpressure zones in the near-surface is required for the mitigation of risks at the early stages of the offshore hydrocarbon field exploration and development. The results of seismic data interpretation generally serve as the main source of information for this kind of problems, yet there are other methods to predict overpressure zones in the subsurface. The paper presents the results of the overpressure zone prediction using a set of methods including empirical ones, and the approach based on rock-physics modeling that features the soft-sand model of unconsolidated media effective properties. While the rock-physics modeling grants the most reliable result, it is also the most demanding method to the input data. Hence, it can be used to verify other methods of the overpressure zone prediction. We present the results of the overpressure zone prediction at the research site on the Black Sea shelf. The mitigation of the drilling risks via changing the drilling conditions is discussed in detail. As the drilling through the overpressure zones is often a necessity, the engineering solutions proposed in the paper can be applied elsewhere when facing similar problems typical for offshore exploration.

Estimation of well drainage radius and reservoir pressure maintenance system efficiency in a tight reservoir by the data obtained by minifrac in the offset horizontal wells with multifrac

The low efficiency of classical methods of well testing during the development of hydrocarbon fields with tight and ultra-tight reservoirs forces engineers to use indirect approaches, one of which is the analysis of pressure drop curves during minifrac and main hydraulic fracturing operations to estimate reservoir pressure by the Nolte method. The paper focuses on obtaining a qualitative assessment of reserve recovery for an area of a field with hard-to-recover reserves with the wells arranged linearly and the distance between them of 500 m by estimating the drainage area and the impact of the pressure maintenance system in a reservoir with permeability of 1 mD or less based on restored inter-well reservoir pressure from the Nolte after-closure analysis of falloff data by quantitative and qualitative pore pressure estimations for each of the frac ports in a horizontal well with multifrac.

The practice of hydrodynamic surveys in complex design wells

The article examines the issues of the research and data interpretation in complex completion wells: horizontal, horizontal multi-hole, horizontal with multistage hydraulic fracturing, with fishbone drilling, multi-section. It presents the examples of an integrated approach to solving the tasks of hydrocarbon field development due to the data of hydrodynamic and field geophysical surveys.

Sensitivity analysis of oil and gas production as a result of increasing the drainage area with changes in well parameters during different completion of wells

Drilling of wells and their return to other horizons are planned in certain sequences and intervals in order to obtain maximum economic efficiency during the development and operation of hydrocarbon fields. It is important to determine the real layout of production wells, to study the relationship between them depending on various parameters. In the presented work, depending on the reservoir and well parameters, the drainage areas of horizontal wells and the interrelationships between these wells were determined, and the maximum final production of such wells was determined. The joint hydrodynamic model of the reservoir-well was used in the research. The results of the work can be used to determine the drainage areas depending on the angle of inclination of horizontal wells and to determine the relationship between them, to increase the economic efficiency of the field by reducing the additional costs of drilling unnecessary wells during field development. Keywords: sensitivity analysis; drainage area; skin factor; hydraulic fracturing; acid treatment; formation damage; production rate.

Environmental safety issues and challenges and geodynamic monitoring at the Karachaganak oil and gas condensate field

Purpose. Environmental safety evaluation and geodynamic monitoring of the Karachaganak oil and gas condensate field (KOGCF) explored on the north board of the Pre-Caspian depression in order to predict the consequences of long-term operation of this field. Methodology. Synthesis and system analysis of the articles and archival literature on environmental hazards and geodynamic monitoring of the complex methods, repeated levelling process, GPS-measurements, high-precision gravimetry and seismological monitoring. Findings. At a qualitative and quantitative level, the activation of vertical and horizontal movements of rock masses, changes in the field of local gravity anomalies, more frequent earthquakes whose hypocentres are located at depths comparable to the intervals of field development are substantiated. Trends and tendencies in the study on the relationship between the continuously changing geodynamic state of the subsoil and field-geological processes are outlined. All these manifestations in one way or another find manifestations in the environmental risks of the area of the exploited deposit. In the conclusions, it is recommended to carry out a set of measures to reduce environmental risks. Originality. The results of geodynamic monitoring at the KOGCF for the northern board of the Pre-Caspian depression for the first time made it possible to obtain convincing evidence in favour of noticeable seismic-deformation processes in the upper part of the earths crust under the influence of hydrocarbon production processes. Practical value. The conclusions obtained in the work confirm the necessity and binding of geodynamic monitoring in order to study and assess the possibility of different scenarios of geodynamic situations related to the development of hydrocarbon fields, are recommended for levelling factors of potential geodynamic risk at the KOGCF.

COMPLICATIONS IN THE OPERATION OF OFFSHORE CONDENSATE WELLS AND THE CHOICE OF METHODS TO COMBAT THEM

The article provides a brief analysis of the complications in the operation of offshore condensate wells and the choice of methods to combat them. The issue of improving and accelerating the development and operation of oil, gas and gas condensate fields has always been relevant and is still relevant today. Development and operation of hydrocarbon deposits is accompanied by the following complications: Complications in the operation of oil wells; irrigation of oil well products; intensification of sand manifestations in deposits; Complications in the operation of clean gas fields; Complications in the operation of gas condensate wells, etc. In order to eliminate all these complexities in the development and operation of hydrocarbon fields, the development of measures in the dissertation, their implementation is very important, as they increase the coefficients of oil, gas and condensation and reduce the cost of oil, gas and condensate.. Keywords: condensate, complexity, hydrocarbon, sand formation, gas condensate, gas supply.

Predicting dynamic formation pressure using artificial intelligence methods

Determining formation pressure in the well extraction zones is a key task in monitoring the development of hydrocarbon fields. Direct measurements of formation pressure require prolonged well shutdowns, resulting in underproduction and the possibility of technical problems with the subsequent start-up of wells. The impossibility of simultaneous shutdown of all wells of the pool makes it difficult to assess the real energy state of the deposit. This article presents research aimed at developing an indirect method for determining the formation pressure without shutting down the wells for investigation, which enables to determine its value at any time. As a mathematical basis, two artificial intelligence methods are used – multidimensional regression analysis and a neural network. The technique based on the construction of multiple regression equations shows sufficient performance, but high sensitivity to the input data. This technique enables to study the process of formation pressure establishment during different periods of deposit development. Its application is expedient in case of regular actual determinations of indicators used as input data. The technique based on the artificial neural network enables to reliably determine formation pressure even with a minimal set of input data and is implemented as a specially designed software product. The relevant task of continuing the research is to evaluate promising prognostic features of artificial intelligence methods for assessing the energy state of deposits in hydrocarbon extraction zones.

Strategic risk management of development of the Arctic offshore fields

The authors of the article study the basic risks in development of hydrocarbon offshore fields in the Arctic as well as methods of managing the existing risks. Development of hydrocarbon offshore fields in the Arctic is connected with numerous challenges due to its unique natural and climatic conditions (ice pack, squally winds, rough sea, etc.). Any activity in such conditions makes high demands for the investment (realization of such projects is extremely capital intensive) and for environmental and industrial security. Due to the high level of work complexity currently only one offshore field is being developed in the Arctic. However, Russian energy companies are considering the perspective possibility of extraction of hydrocarbon resources in such conditions. In order to explore the Arctic offshore fields efficiently it is necessary to apply the methods of risk management which are able to minimize the possibility of unwanted events. In most cases the method of risk management is chosen depending on the stage of realization of the project on developing an offshore field: prospecting, exploration or exploitation of a deposit. The authors of the article conditionally divide the risk management methods into two categories: universal (which can be applied at any of the above mentioned stages of the deposit's development) and unique (to be used only at one certain stage). The analysis conducted made it possible to reveal the main advantages and disadvantages of the risk management methods under consideration. The combination of universal and unique methods became the basis for the risk management system which takes into account the specifics of the stages of development of Arctic offshore hydrocarbon fields.

A new approach for the demonstration of acidizing parameters of carbonates: Experimental and field studies

Acid stimulation of carbonates is the most common method of production intensification in practice of hydrocarbon field development. Injection of acid compositions improves hydrodynamic connection of the wellbore with the reservoir by creating extended filtration channels – wormholes. Wormholes increase the effective drainage radius of production wells, which provides incremental oil. Scientists around the world have conducted a considerable amount of experimental and numerical research at the fundamental level aimed at studying the complex process of interaction of acid compositions with carbonate rock. The results of the studies repeatedly noted the critical role of technological parameters of acid treatment, the competent choice of which often provides a positive result of stimulation. However, a significant number of studies have been performed and tested only at the theoretical level or under ideal laboratory conditions, and their transfer to real heterogeneous productive reservoirs turns out to be a failure. Our study demonstrated a fundamentally new approach to justify the technological parameters of acid stimulation of carbonates (volume of acid and reaction time) based on laboratory experiments and field studies. We developed a rating matrix that characterized the effectiveness of acid treatments in terms of changes in well performance and reservoir properties, as well as the multiplicity of exposure, for a wide range of technological parameter changes. The application of this approach allows not only to evaluate the effectiveness of actually performed acid treatments, but also to quickly determine the perspective of different design options for future interventions. The operability of matrix was confirmed by positive pilot tests at wells in Perm Krai (Russia), and the test results were 8–31% higher than the planned results. The algorithm we described was useful in designing acid treatments. This method effectively improved the oil and gas recovery under the condition that the reserve structure deteriorated annually and the number of candidate wells decreased.

Subsurface Technology Pivoting from Oil and Gas to Geothermal Resources: A Sensitivity Study of Well Parameters

Summary There is enough geothermal energy several miles underneath to supply more power globally than the entire oil and gas industry. Geothermal energy is renewable, abundant, and has a minimal carbon footprint. However, the current geothermal energy use is only 1% of the global energy production. To scale it up, several technical problems need to be solved, addressing how, where, and when to harness it safely, efficiently, and cost-effectively. In this paper, the synergies and differences between the hydrocarbon and geothermal wells are reviewed and an opportunity assessment and management framework are proposed to improve the outcomes of diverse geothermal hydrocarbon projects. Producing geothermal energy from existing hydrocarbon wells, as electricity and/or low-temperature waste heat, can yield significant advantages over traditional geothermal wells, especially in terms of reduced capital expenditure. Geothermal and hydrocarbon well studies related to geothermal hydrocarbon field development are reviewed, presenting the similarities and differences between the geothermal and hydrocarbon wells, and the challenges for economical geothermal hydrocarbon field development. To unlock the potential of geothermal hydrocarbon field development, several areas of research are identified and explored. There are many hydrocarbon wells drilled worldwide that are either abandoned or will be abandoned in the future. This inherently brings exit options repurposing these wells in terms of extracting residual value in an environmentally friendly way. There is a great potential to extract energy in the form of low-temperature waste heat and/or work with the right power fluids, including CO2. In this study, a numerical solution and several analytical solutions are presented for closed-loop wells (i.e., concentric pipes in wells). They can be extended to enhanced geothermal systems (EGSs) (i.e., injecting and producing casedhole wells with perforations along vertical, inclined, and horizontal sections) by allowing fluid inflow into the wells. The time- and space-dependent temperature solutions for all well configurations are obtained for time- and space-dependent fluid and flow properties. A sensitivity study is then performed, showing the effects of several parameters on the flowing fluid temperature for such parameters as the fluid flow rate, well length, inner tubing and annulus diameters, geothermal temperature, and overall heat transfer coefficients. Existing hydrocarbon fields produce larger volume of waste water over their lives, increasing their operating costs owing to greater water management expenditure. Conceptually, those operating costs could be reduced by electricity and/or heat coproduction. The proposed modeling approach is useful for the design of EGSs and closed-loop systems. It can also be used as an operational tool to monitor the well and reservoir performance over the life of a deep geothermal resource. Last but not least, it can be used to assess the conditions for economically converting abandoned oil and gas wells for sustainable geothermal energy production.

Hydrocarbon Field (Re-)Development as Markov Decision Process

Summary Hydrocarbon field (re-)development requires that a multitude of decisions are made under uncertainty. These decisions include the type and size of surface facilities, location, configuration, and number of wells but also which data to acquire. Both types of decisions, which development to choose and which data to acquire, are strongly coupled. The aim of appraisal is to maximize value while minimizing data acquisition costs. These decisions have to be done under uncertainty owing to the inherent uncertainty of the subsurface but also of other costs and economic parameters. Conventional value of information (VOI) evaluations can be used to determine how much can be spent to acquire data. However, VOI is very challenging to calculate for complex sequences of decisions with various costs and including the risk attitude of the decision-maker. We are using a partially observable Markov decision process (MDP) to determine the policy for the sequence and type of measurements and decisions to do. A partially observable MDP (POMDP) is characterized by the states (here: description of the system at a certain point in time), actions (here: measurements and development scenario), transition function (probabilities of transitioning from one state to the next), observations (measurements, appraisal activity), and rewards [costs for measurements, expected monetary value (EMV) of development options]. Solving the MDP gives the optimum policy, sequence of the decisions, the probability of maturation (POM) of a project, the EMV, the expected loss, the expected appraisal costs, and the probability of economic success (PES). These key performance indicators can then be used to select in a portfolio of projects the ones generating the highest expected reward for the company. Combining the production forecasts from numerical model ensembles with probabilistic capital and operating expenditures and economic parameters allows for quantitative decision-making under uncertainty.

Staffing for the development of the Arctic offshore hydrocarbon fields

ABSTRACT The development of offshore deposits of hydrocarbon resources requires the involvement of not only advanced equipment and technologies, but also highly qualified specialists, the creation of educational and research centers. It is extremely important to find a rational strategy for offshore production and use of natural resources, harmonized with socio-economic objectives in order to preserve the vulnerable nature and ethnic heritage of the Russian Arctic, as well as to determine the optimal number of personnel involved in projects. The most important tool for strategic planning in the development of offshore hydrocarbon fields will be the proposed model of the balance between the existing human potential and the need for it, reflecting the specifics of the requirements and competencies for human resources at the stages of geological exploration, production and transportation of oil and gas raw materials. The results of the authors' research on the analysis of the staffing of projects for the hydrocarbon resources development in the Arctic and the tools for forecasting and planning the number of personnel of a certain qualification for work in the Arctic zone, described in this paper, can be used in a comprehensive analysis of the needs for the provision of existing and prospective projects in the Arctic.

Application of probabilistic reasoning for risk assessment and mitigation in hydrocarbon field development

The article considers the problem of risk management in hydrocarbon field development. The approach to risk assessment and mitigation, based on the application of probabilistic reasoning models, is proposed. A special kind of Bayesian networks – influence diagrams, and associated probabilistic decision trees were proposed as models. An example of its application to the task of assessing and reducing the risk of non-execution of the project document due to unconfirmed reserves is given. As part of the example, the task of assessing the feasibility of drilling an exploration well is considered.

PETROPHYSICAL STUDY OF ‘GLORY FIELD’ RESERVOIR IN SOUTHERN PART OF NIGER DELTA, NIGERIA USING WELL LOG DATA

This purpose of this study is to evaluate the petrophysical properties of hydrocarbon bearing reservoirs in ‘Glory Field’ onshore Niger Delta using well log data from five wells. Petrophysical properties evaluated are shale volume, thickness, porosity, net to gross, formation factor, irreducible water saturation, permeability, water saturation, hydrocarbon saturation and pay thickness. The well logs suite contained the following logs: gamma ray, resistivity, density and neutron logs. A total of three reservoir sands (Sand A, Sand B, and C) were identified and correlated across all five wells using Schlumberger Petrel Software. From the result, on average density, Vp/Vs ratio, AI, shale volume, net to gross ratio, net thickness, effective porosity, permeability, water saturation and hydrocarbon saturation values are 2.15g/cm3, 2.28, 5406.67gcm3ms-1, 26%, 74%, 66.99ft, 25%, 2331.14mD, 48% and 52% respectively for sand A reservoir, while 2.17 g/cm3, 2.05, 6117.38 gcm3ms-1,14%, 86%, 185.04 ft, 26%, 2359.88mD, 56% and 46% respectively for sand B reservoir, and 2.18g/cm3, 2.01, 6275.95gcm3ms-1, 14%, 86%, 197.52ft, 25%, 2121.27mD, 53% and 47% respectively for sand C reservoir. The results of this research revealed very good effective porosity (>20%), excellent reservoir permeability (>1500mD) and pay zone thicknesses exceeding 70ft which are sufficient for hydrocarbon production and field development.

Improving the quality of reservoir pressure gridding by regularizing the CRMP-TM history matching problem

To enable rapid decision making in the process of hydrocarbon field development, experts are increasingly moving away from slow 3D hydrodynamic models in favor of simpler proxy-models. In particular, to solve such an important task of development analysis as reservoir pressure gridding, the CRMP-TM proxy-model was previously proposed. This proxy model allows estimating the values of reservoir pressures for wells for each step of the simulated time interval. The achieved pressure values may be used as input data for the problem of reservoir pressure gridding. This article provides examples of situations in which the previously published methodology of using the CRMP-TM model is not applicable. A new technique has been proposed that makes it possible to expand the applicability of this model to the considered situations, as well as to make the estimates of formation pressure values for injection wells more accuracy. The results of numerical experiments are presented, confirming that the accuracy of the estimates increases when using the new technique.

Arctic shelf: topical economicproblems of hydrocarbon field development

Arctic shelf: topical economicproblems of hydrocarbon field development

Research of the widespread methodologies for forecasting gas deposit development under the gas drive

The determination reliability of development technological indicators plays an important role in the further field development, since they affect the field development rate, the drill footage, the amount of capital investments, the construction of ground communications, etc. Therefore, the choice of the methodology for forecasting technological indicators plays a decisive role in making investment decisions. To forecast the technological indicators of the gas/gas-condensate fields development a significant number of methods have been developed, among which the main ones are the methods of integrating the differential equations of fluids unsteady filtration within a porous medium inhomogeneous in reservoir properties, consistent change in stationary states and the basic laws extrapolation of the actual data dynamics. The above methods are characterized by varying degrees of the calculated values reliability ​​and certain technological limitations. To assess the magnitude of the possiblemargin of error in the design of the hydrocarbon fields development, a study of generally accepted methods that are widely used in the oil and gas industry has been carried out. Based on the study results, it has been found that the Petroleum Experts IPM suite software package provides the highest accuracy and reliability of the predicted development indicators, since it takes into account the reservoir properties, phase transformations of complex reservoir hydrocarbon systems and the regularities of fluid movement along the wellbore. The results of the conducted research allow us to assert that the use of the main tools of hydrodynamic modeling in accordance with the world practice of designing the deve-lopment of hydrocarbon fields will increase the production efficiency of residual hydrocarbon reserves at the final stage of development, which form the main potential for increasing its own production in Ukraine.