In the case of many workover operations associated with fluid loss inside the well or multistage refracturing, one of the most significant uncertainties is the fluid entry point. Starting from uneven depletion of the horizontal part of the well, not knowing the fluid entry point may lead to ineffective well restimulation and absence of any positive effect. In this paper new technique will be reviewed for several locations across Russia. Implementation of high-frequency pressure monitoring (HFPM) method and based on it, Well Watcher Stim technology, allows locating downhole events caused during well workover and refracturing without interruption of the well stimulation operations. The high frequency pressure monitoring technology is based on automatic processing of wellbore pressure oscillations recorded at the wellhead. The wellbore completion elements such as hydraulic fractures, casing diameter changes or wellbore restrictions serve as effective reflectors for the tube waves. In this paper, we will demonstrate an integrated approach to the utilization of high-frequency pressure monitoring technique, which has served as an engineering tool for fluid entry point validation in the projects all across Russia. The project validated the intrinsic benefits of the new approach in solving uncertainties about the fluid entry point. The Well Wacther Stim technology requires minimum changes in operational procedures, is easy and safe to install and provides real-time answers that allow the frac engineer to take decisions on location and optimize the re-fracturing process Selected stimulation approach enables the horizontal well refracturing operation to be concluded within 2-3 days, minimizing well intervention operations and reducing the overall costs and risks of the restimulation. The selected workover approach demonstrates reliable technique for fluid loss extensional control in well workover. One of the opportunities which is became available with high-frequency monitoring is analyze of conditions of well construction and downhole equipment. That was practically confirmed at a well with completion for multi-stage fracturing. Suspicion about damage of casing or sliding sleeves and corrosion of isolation packers was verified and localized. Further application of Well Watcher Stim made possible to decrease leakages by conventional reservoir dynamic fracture diversion technology and provide multi-stage fracturing with constant control of identified zones. This paper presents case studies of the technology that was used widely in Russia in the recent years proving reliability of high-frequency pressure monitoring technique. It will provide meaningful insight for the petroleum engineer who will look after solving uncertainties during well workover operations and refracturing.

The article demonstrates the results of experimental and field studies of the thermal foam-acid treatment technology with the use of water solutions of heat and gas generating system. The potential temperature of the heat-generating reaction upon mixing of agents was estimated in laboratory conditions and the physical and chemical properties of acid solutions were determined. A series of filtration experiments was conducted on treating dolomitized core samples with a basic hydrochloric acid solution.The constant of the rate of reaction between the basic acid solution and dolomitized carbonate rock was determined based on the experiment results. The article provides a brief analytical overview of world experience of the thermochemical treatment of the bottomhole area. The technology selected for the tests called thermo-foam-acid and implies the step-by-step injection of water heat and gas generating solutions with an addition of surfactants and an initiator into the bottomhole area. The heat-generating reaction is accompanied by the generation of a large amount of heat, gases and hot foamed acid. Heating melts high molecular weight oil compounds, washes oil sheen from rock surface and increases the speed of its dissolution with hydrochloric acid. This foam acts as a diverter for the next portion of active acid and prevents undesired stimulation of high-permeability interlayers and fractures. Surfactants in the acid solution increase its ability to penetrate pores and microfractures. The physical modeling of a thermal foam-acid treatment has been performed. Arlanskoe (Kashirskian-Podolskian deposits) and Nadezhdinskoe (Famennian stage) fields where carbonate formations are characterized by high and increased oil viscosity, low reservoir temperature, fractured and dolomitized reservoirs were selected as a site to perform field tests. Well operation at these formations is complicated by the precipitation of asphaltenes, resins and paraffins in the bottomhole area. Solution injection parameters were recorded during treatments based on this technology. The technological efficiency of this treatment was confirmed based on bottomhole pressure and temperature changes during injection operations. Technology efficiency was analyzed and the well flow rate was monitored based on the field test results. The main stages of this work are shown in Figure 1. Figure. 1 Project stages

Nowadays, the vast majority of the oil fields of the Republic of Belarus are at the last stage of development. In this connection, the goal of Belarusian oil industry is to search, to explore and to develop ultra-low permeable tight fractured carbonate rocks. Commercial production of such resources is only possible with the use of advanced stimulation methods, such as hydraulic fracturing / multi-stage hydraulic fracturing. Taking into account the features of tight carbonate rocks, the use of conventional hydraulic fracturing technologies cannot provide optimal results, and therefore, selection of more advanced approaches to hydraulic fracturing is necessary. Selection and optimization of technologies based on theoretical research is not possible, instead it requires practical implementation, and according to our experience, flexibility in decision making. This article presents the experience of unconventional reservoir development in the Republic of Belarus from 2014 to 2020. We briefly described the main technologies used and how these technologies evolved depending on the resulting operational and economic effect. The technology of repeated multi-stage hydraulic fracturing in an unconventional reservoir is described; the possibility of producing from previously untapped reservoir zones within the horizontal wellbore by creating additional flow channels (hydraulic fractures) was confirmed.

One of the engineering tasks of hydraulic fracturing design is the correct selection of the propping agent. Ceramic proppant, which is used in most fields in Western Siberia, makes a proppant pack that is several times more permeable than the formation (sometimes even 1000 times). However, the gelling agent used for treatment, depending on the size of the proppant, reduces the permeability of the proppant pack from 2 to 5 times. However, workover operations after hydraulic fracturing and during production period has a significant colmatage effect on the near-wellbore zone and can significantly reduce the productivity of the well. A common practice in the fields of Western Siberia is to prop a fracture at the near-wellbore zone with a proppant of mesh size 12/18. Despite a small difference in the calculated skin factor, the analysis of operations at the Salym group of oilfields shows a significant change in the production decline rate on wells with 16/20 and 12/18 mesh size propping agents. Engineering group of the Salym group of oilfields conducted trials on hydraulic fracturing treatments with a mesh size 10/14 and, after successful results, 6/10 proppant. The treatment results, lessons learned and the analysis of production of these wells is the scope of this work.

A case study is presented discussing a specific completion strategy applied in the Daqing oil field, Block Long26, and the outskirts of tight oil wells. An alternative fracture completion method and enhanced flowback technology were used to develop these tight oil fields. The methodology applied resulted in improved efficiency of the fracture completion strategy and post-stimulation flowback, which reduced operational time and related costs. Optimized fracture cluster spacing length was determined based on the operational time efficiency and engineered fracture completion design. Laboratory testing was performed to select fluid recipes, and field trials were performed for the correlated custom-made microemulsion technology, which enhanced post-fracture flowback to shorten operational time and increase the return on investment ratio and production. Field results and post-fracture completion production are promising. Several post-fracture completion production surveys have been applied in the Daqing field, Block Long26. The most popular completion strategy applied in this field involves using less than three perforation clusters in each fracture stage, applied using multiple, horizontal fracture stages, with longer and (normally) much greater fracture spacing length, thus requiring less fracture cluster treatments along the horizontal laterals. After stimulation, normally, additional days are necessary to observe the oil drop showing; thus, alternative flowback technology is necessary to enhance post-stimulation flowback to help improve the return on investment ratio. Limited entry fracture and/or extreme limited entry fracture technology were part of the intensive fracture cluster completion strategy to benefit fracture completion and production. Field operations involved doubling the current perforation and fracture clusters in one fracture stage. Laboratory methods were used to select the appropriate mircoemulsion additives to form a fracturing fluid recipe to aid oil production and enhance flowback.

The paper presents the results of applying the methodology of well flowback and startup after hydraulic fracturing (HF), previously proposed in ( Osiptsov et al., 2019 ), where the preferred conditions for well flowback after hydraulic fracturing are formulated in the form of a field experiment program. The program was implemented in 2019-2020 at four out of ten wells of the Priobskoye field in Western Siberia. The comparison of the two well clean-up designs, "smooth" and "aggressive", aimed to confirm the hypothesis that the choice of a "smooth" mode can reduce undesirable geomechanical effects to preserve the fracture conductivity and increase the recovery. Adapting our own hydrodynamic and geomechanical models to actual data made it possible to control the well clean-up process in the wells of a field experiment. Well site supervision allowed authors to fully implement the research plan, and also provided the opportunity to vary the parameters of the experiment (adjusting flowrate over time, adjusting the sampling and measurement schedules) using history matched models with actual parameters of the wells. Based on the results, the obtained data were analyzed and interpreted: flow rate, water cut, bottomhole and wellhead pressure, bottomhole temperature, suspended particulate matter (SPM) concentration, drain level, expedition pump frequency and wellhead samples. At the planning stage of the experiment, a formation zone of interest (ZOI) was selected with a set of first six pilot wells, where the geomechanical effects during the flowback period have the greatest impact on production. The field experiment program, which contains the wellhead choke steps sequence of diameters and duration of the well clean-up periods for two scenarios - "aggressive" and "smooth" for particular well. In addition to the choke schedule during eruptive period, there is a need to continue the recommended well startup after the ESP run in hole (RIH). Representativeness and repeatability conditions of field tests were formulated, comparison metrics were developed in order to standardize, normalize and estimate the well performance of the well startup a. We carried out the design of a field experiment proposed in 2019 ( Osiptsov et al., 2019 ) and showed in practice that the dynamics of the well flowback and startup affects the well productivity index for a selected ZOI. In addition, we history-matched in-house geomechanical and hydrodynamic in order to quantify the production increase with regards to different flowback scenarios. Based on the available data, the boundaries of the pressure fluctuations opposite the hydraulic fracturing ports in the horizontal well were calculated in the absence of actual measurements to clarify the conditions for maintaining the conductivity of the fracture.

As the number of stages of hydraulic fracturing along the horizontal wellbore increases, the cost of fracturing starts to exceed the cost of drilling the well. Therefore, the issue of costs optimization for hydraulic fracturing in general become highly important problem. In this regard, for optimization calculations, it is necessary to operate with such important geometric characteristics of fracture as half-length and height of the fracture, which can be determined by logging, well-testing and micro-seismic studies. This paper analyzes all types of studies to determine the geometric characteristics of the fracture, except its width. Logging surveys, which have been carried out on vertical and inclined wells, allow to determine with some degree of accuracy the height of the fracture, provided that the conditions of applicability of these surveys considering well azimuth and inclined angle in the zone of fracturing & logging. Among the logging methods that have been applied to that kind of problem, the highest priority in terms of the reliability of the results obtained is given. Well testing allow us to determine the effective half-length of a fracture, but with some limitations. Micro-seismic studies allow comprehensively and in three-dimensional view to determine the configuration of a fracture in a orientational well or a system of fractures in a horizontal borehole to a certain degree of accuracy.

The Company has recently completed the first stage of a large-scale program for production of hard-to-recover (HTR) oil reserves from standard terrigenous reservoirs. This program is being worked on within the framework of the Optimal Completion Technologies and Operation Parameters of Oil Wells in Low-Productivity Reservoirs technology project implemented within the Company's perimeter. A high-rate hybrid multistage hydraulic fracturing was successfully performed on a number of horizontal wells at the Achimov Formation reservoirs thus confirming the ambitious well productivity plans. The primary goal of the project was to verify the hypothesis that the sweep area can be increased by means of a high-rate hybrid hydraulic fracturing; the next goal is to check the hypothesis that a developed network of fractures, or stimulate reservoir volume (SRV), can be formed at a hydraulic fracturing injection rate exceeding the standard values by 3-4 times. Keeping in mind the tasks of increasing the drainage area and connecting separate zones of highly compartmentalized reservoirs with each other, the basic hydraulic fracturing technology for the design purposes was a high-rate hybrid hydraulic fracturing with an injection rate of up to 12 m3/min and a combined schedule. At the preparatory data processing and interpretation stage, issues in each discipline involved – petrophysics, geology, geomechanics, and hydrodynamics – were worked out in detail and modeled. The design project of a high-rate hybrid hydraulic fracturing treatment has undergone many optimization iterations in the Planar 3D module, with further testing of the anticipated effects on a hydrodynamic simulator using unstructured three-dimensional PEBI grids. As a result of multi-variant modeling performed by a cross-functional team, a universal hydraulic fracturing design was created which predicted high efficiency of the treatment to create both the SRV and the planar fractures. To make the results of the performed pilot work more reliable, a wide range of studies was performed including production logging tests in horizontal wells with various completion systems. While assessing whether formation of the SRV is possible, downhole micro-seismic monitoring was performed, and downhole pressure was measured at neighboring wells. In the real conditions of the tested target reservoir, formation of the SRV was not confirmed at the actual injection parameters. The Planar 3D module, coupled with the hydrodynamic simulator, is an efficient tool to optimize design of the hybrid hydraulic fracturing treatment. The giant half-lengths of planar fractures predicted in the hydraulic fracturing modeling software have been proved by micro-seismic monitoring and pressure response at submersible pumps of the neighboring wells. At one of the stages, a high-rate hydraulic fracturing with 125 tons of proppant was performed entirely with a hydraulic fracturing fluid based 100% on a synthetic gelatinizing agent which showed the greatest fracture length. The Company pays great attention to this technology solution too – several tests have been initiated with respect to ‘pure’ hydraulic fracturing fluids, and work is underway to develop guideline and methodology documentation on quality control. Results of the project have changed the vision of optimal methods for stimulation of the Achimov low-permeability reservoirs. In the absence of the SRV, formation of long planar fractures by means of a system of horizontal wells with low-density spacing can increase economic viability of currently uneconomical fields or separate reservoirs (zones). The novelty of this work consists in the achieved level of integration of model values from various disciplines with the actual data. The initial and current parameters of stimulated wells demonstrate a broad perspective for optimizing the HTR reserves development system for a standard terrigenous reservoir. Successful reservoir stimulation by high-rate hybrid multistage hydraulic fracturing (MSF) opens the way to even bigger projects that envisage drilling horizontal holes up to 2,000 m long and building wells of the TAML-3 level of complexity.

The article covers methodology for rapid assessment of optimal development parameters for offshore fields. The first stage determines maximum allowable expenditures for field construction that make the project efficient, following selection of the offshore facility type required for production. The second stage evaluates the well density for every cost-effective offshore facility considering the best economical option for field development.

In this paper, some features of conducting experiments on core samples to determine mechanical properties were established. Detailed description for such type of testing is poorly described in regulatory documents (Russian State Standard, ASTM). Problem of specific test methods selection in accordance to task before the geomechanical modeling is considered. For the most issues, a series of experiments to build a failure envelope is required. Details of sample preparation for compression tests are regarded. In particular, the advantages and disadvantages of different methods for preserving in-situ core saturations are discussed: the collection of an isolated core with subsequent conservation or the preparatory work with the extraction, drying and saturation of samples. While conducting multi-stage compression tests for building Mohr circles, chose of the right moment to stop the loading stage has a significant effect to prevent destruction of the sample in the early stages. This paper demonstrated that for specimens characterized by a shear failure type, it is recommended to focus on the plot "axial stress - volumetric strain". In particular, the inflection point of the curve, that is the moment of reaching the maximum value of volumetric deformation could be selected as a criterion for the loading stage termination. For samples with high porosity, a complete testing cycle to build the Mohr circles and the entire failure curve is given.

The article describes the theory of "clamped" water to justify the position of the oil-water contact of the reservoir, exposes in detail the experience of applying this theory on the example of an oil reservoir in Famennian organic deposits of the Vostochno-Lambeyshorskoye field of the Komi Republic. During the field development, geologists have encountered a problem of different oil-water levels established in different parts of the structure, which is determined by well data with a high degree of confidence. The analysis of reservoir pressure data shows, that the separation of the reservoir into tectonically shielded blocks with different levels of water-oil contact is impossible. According to the results of seismic facies modeling and sequence stratigraphy, there were not identified any significant channels that could separate the reservoir by area. The solution to the problem of substantiating the oil-water contact was found by applying the theory of "clamped" water. The idea of this theory is that during the migration of hydrocarbons into the trap, controlled by lithology and faults, there remain the so-called hydrodynamically isolated "pockets" (hereinafter referred to as "pockets") in which the formation water is sealed with oil and the oil-water contact is fixed at the level of the structure bend. The article describes the mechanism for the formation of such "pockets". In the issue, a new conceptual model of the Famennian reservoir of the Vostochno-Lambeyshorskoye field was created as a layer-uplifted deposit, controlled by lithology, with different horizontal oil-water levels. The oil-water level is gradually increasing from north to south, along the path of hydrocarbon migration from the source rock to the reservoir. Oil-water levels are controlled by structural inflections defined on the maps of the reservoir bottom.

This article discusses the problem of creating a hydrogen storage in an aquifer. It is assumed that the process of hydrogen injection and the life cycle of its storage should provide the most complete reverse production of the injected gas in a few years. The features of injected gas distribution in an aquifer are considered, taking into account a number of parameters. For example, the effects of gas breaking through a cap rock and fluids migration under influence of natural water flows from aquifers associated with the target reservoir. An effective storage and subsequent production system are proposed allowing to control geometry and volume of gas bubble in the reservoir. The results are obtained on the basis of large-scale 3D geological and hydrodynamic modeling of filtration through porous medium of a multicomponent system in the form of hydrogen, methane and water mixture on synthetic 3D models. Corresponding studies were performed on a certified hydrodynamic simulator using a composite model. Large-scale 3D geological and hydrodynamic modeling made it possible to justify the method of compact hydrogen storage in an aquifer. Closed systems, without contact with large volumes of water in adjacent aquifers, do not allow significant gas volumes to be stored under technologically realistic parameters. Presence of an active aquifer dramatically changes injected gas configuration and facilitates its migration from the zone of possible reverse production. The necessity of creating a permanently operating associated water injection system is substantiated to control geometry of the created hydrogen storage together with methane. It is shown that without controlled injection of water, both at the stage of creating the storage and at the stage of storing hydrogen, it is not possible to ensure its subsequent sufficiently complete production to the surface in a reasonable time with technologically justified costs. Otherwise hydrogen reserves are being scattered due to gas migration over very large distances from gas injection wells. Strong influence of the aquifer system parameters associated with the target reservoir is illustrated for dynamics of hydrogen propagation.

Seismic tomography is one of the main tools for obtaining a depth velocity model. Its result largely determines the estimated geometry of oil and gas reservoir. Tomography is a deterministic procedure and does not provide an opportunity to assess the reliability of the results. However, in fact these results directly affect the subsequent economic decisions. For this reason, the aim of the current work is to develop a method of multivariate tomography which allows to determine the reliability of the results. The paper considers several factors of multivariance. Factor of input data quality is generally considered and stochastic averages tool is proposed for estimating input data reliability. Typically, input data estimation involves calculating supergathers. Usage of equivalent weights for supergathers accumulation means that all gathers have an equivalent quality but in practice this is far from the truth due to various regular noises. Replacing weights by random ones is equivalent to filtering with random kernel. These means assigning a random confidence levels to input gathers. This allows to generate many realizations of the input data for inverse problem. Also incorporation of tomography smoothness parameters variation to inverse problem is proposed. Such approach differs from traditional ones where these parameters are set by a specialist based on purely personal ideas. All together this allows to generate many realizations of depth velocity model and estimate its reliability. The proposed method of multivariate tomography doesn't use the known statistical distributions of the input data errors, thus, it is the most general and realistic. Its result can be utilized in the assessment of economic risks.

The composition and properties of oil change during its flow through the reservoir, which is associated with the high molecular weight resins and asphaltenes retained in the pores. Oil is retained in the thinnest capillaries and narrow contacts of hydrophilic mineral grains (capillary-retained oil) and as a film on the surface of hydrophobic minerals (oil films). To confirm this, core analysis tests were performed on three pre-prepared core columns made up of standard core samples with different porosity ϕ , absolute permeability k , irreducible water saturation S wir and other properties. Oil was flowing through the column and displaced by water with pre-determined physical properties. The properties of the core specimens, oil and water, as well as the thermobaric conditions of flow experiments were selected so that they corresponded to the reservoir conditions of the Pashian horizon of the Romashkinskoye oilfield of the Republic of Tatarstan. In the case of the mature Romashkinskoye oilfield, the relevant objective is to quantify and localize the remaining reserves of capillary-retained oil and oil films and substantiate effective technologies for their extraction. To prove that the composition of oil change during flow through porous media, the light absorption coefficient of oil k la was investigated that depends on the relative content of resins and asphaltenes in the oil. Oil was studied using a photometer in a continuous mode during the entire period of oil displacement test. Oil samples were collected and subjected to preparation at the inlet and outlet of the core column, their optical density D, light absorption and transmission coefficients were measured in vitro, and statistical data were processed. It has been found that regular changes in the oil k la occur both at the stage of the core column saturation with oil (a regular decrease), and as oil is displaced from the core samples by water (a regular increase). The identified patterns are the function of the rock and oil properties, the established rate of the column saturation with oil and oil displacement by water, and the amount of residual and displaced oil. The obtained data have shown the promising outlook for continuing laboratory experiments to study not only changes in the properties of oil when it is displaced by water, simulating the development processes, but also those occurring in the column as it is saturated with oil, simulating the processes of primary migration and accumulation of oil in a natural reservoir.

One of the most important tasks when developing oil fields with horizontal or directional wells is the inflow distribution monitoring along the wellbore. Possible irregularities in the inflow are primarily associated with heterogeneity in the filtration distribution and capacitive properties along the wellbore, unevenness in the depression distribution, possible overfilling of the wellbore, partial or complete blockage of sand filters by mechanical impurities or clay material, imperfect development of the wells (when part of the mud cake remains on the wall of the well), gradual clogging of the bottomhole zone pores, water breakthroughs and gas outs, or other reasons. Inflow profile monitoring allows identifying why the well performance has decreased and timely planning and carrying out appropriate geological and technical measures. Also, this information allows timely updating hydrodynamic models of field development to properly make strategic decisions. This paper presents the results of bench tests of a new active thermometry technology using a distributed temperature measurement system

The operation of gas wells is often fraught with complications due to water accumulated in the perforation interval and wellbore, and destruction of the bottom-hole zone. These complications drive up pressure losses and decrease operating well flow rates and production capacities of deposits. This article presents proposals for unburdening gas wells in the Vostochno-Makarovskoye field.

In the framework of the contract with the Ministry of Education 2010-2012, TNG-Group andKazan Federal University developed a mobile YaMR-Kern unit to acquire information on filtration-capacitive properties of full-sized freshly drilled and extracted core samples, to estimate porosity, to determine free and bound fluids, permeability, residual water saturation, to assess the nature of saturation by analyzing the two-dimensional distribution of relaxation times and diffusion coefficient directly at the wellsite without preliminary core preparation for studies. Efficiency of the unit was tested on more than 1600 m of full-sized core samples taken from sediments of various ages and saturated with oils of various viscosity grades. The core study directly at the wellsite, that is, immediately after its extraction to the surface, allows not to lose the very first information about the studied object as soon as possible, since the study of the core drying process showed that during the first hours the core loses up to a third of fluid-saturated porosity, and 20 days later dries out almost completely. Scanning the NMR properties of the core is carried out with high detail, every 1-2 cm, and does not involve any preparatory work, that is, the core does not break down and can later be used for laboratory studies of both full-sized core and standard samples. Such information is extremely important at the stage of exploratory drilling on poorly studied survey targets, as well as in the study of a thin-layered section of wells.

Wrong manual interpretation from the log data about the formation type and other important information can be catastrophic for the company-operator. With Machine-Learning (ML) (a branch of Artificial Intelligence) algorithms, the interpretation of formation type from the log data has been addressed. As a result, we have successfully developed a program able to accurately predict the type of formation. Using the conventional Machine Learning technique of splitting the data into training, validation and test sets, we tried six different ML algorithms to fit with the training part of the data and then verify their prediction accuracy with cross-validation scores and cross-validation predictions which tests the performance of the classifiers (ML algorithms) on the validation set. The three best performing classifiers were selected and further improved by a search of classifier's best hyperparameters. These improved classifiers are further tested on unseen data to produce a comparative analysis. Our prediction accuracy with Receiver Operating Characteristic (ROC) scores and ROC-Area Under-the-Curve (ROC-AUC) for each type of formation from the log data lies in the range of 95-99%, except for formations such as shaly sandstone and shale (50% and 84% respectively). The reason for this seemed to be under-fitting i.e., during the training, the classifiers did not see enough instances of these types of formation to know exactly what characteristics of the data make the type of formation to be shaly sandstone or shale. The issue of under-fitting was verified by skimming through the data. To resolve this problem, we suggest training classifiers with a larger data with more targets (types of formation). Furthermore, during the data cleaning (prior to classifier training) and data analysis phases we have discovered important relationships between well logs and defined relative importance of each well log for different formations. This observation can be investigated further to help eliminate the use of multiple well logs while dealing with some formations (based on prior geological knowledge) and reduce the cost of the well logging operations. Using our program with a larger well log data consisting of more formation type instances, we can train the classifiers to accurately predict the formation type irrespectively of differences in formation type. Our program is dynamic in the sense that with different targets, i.e., type of formation fluid instead of type of formation or both together, it can successfully predict either or both targets. Increasing the numbers of data instances resulted in a better training and thus, more accurate predictions. Utilization of the program will make the formation-evaluation process easier, faster, automated and more-precise.

As the extensive Russian gas business matures from developing the high-permeability (Cenomanian) formations, into lower-permeability (Turonian) gas deposits, a number of economic challenges will need to be addressed in order to remain effective. The number of wells, pads and associated infra-structure and expenditure in a tight-gas environment will dramatically increase, challenging the economic outcome and environmental impact of using the established approaches. In order to achieve the maximum return, it is imperative that the established pad and well, construction and execution processes, are challenged, re-considered and subsequently optimised for the new reality. This paper will describe a worked example of such reconsideration for a potential tight-gas development in Western Siberia. Well pad construction for Oil and Gas developments in Western Siberia is well established, so very well practiced in fact that often little is changed between one development to the next, and the reservoir and well requirements are only considered through a regulatory lens. However, as the development economics become more challenging in the lower permeability environments, much more optimisation will be required in order to maximise the efficiency. The approach taken here is to start with consideration of the traditional pad design, as was implemented for three pads built during an earlier Turonian Appraisal phase; and then incrementally consider areas of optimisation until the most cost-effective and solely requisite pad design has been achieved. Instead of outsourcing pad design to a disconnected/remote third-party engineering service, hand-cuffed by decades old established practice, the approach taken was to internally create an integrated view on pad functionality, technical requirements and optionality for a successful development. The results of this approach speak for themselves, with areal percentage reductions readily achieving a level of 50%, with an obvious associated cost improvement. Additionally, the flexibility and optionality that can be built into incremental pad design/construction offer new insight into what can be achieved in these very challenging environments. As developments move into more challenging rock quality, the previous approach of delineating and carpet-bombing a field with wells and pads becomes less effective and highly impactful on the overall development economics. Almost all Global tight-rock developments are phased, in multiple stages, based on improving sub-surface, productivity and well-design knowledge incrementally. Additionally, the inherent ability, via this method, to minimise the environmental footprint cannot be overstated. Techniques that will be presented show how a holistic approach will result in the most effective use of limited resources and a reduction of the impact of the surface footprint. The novelty of this approach is that it challenges what has become, over decades, the rigid and inflexible approach for pad construction that is linked with a higher-permeability field development era. It offers a new and refreshing insight into what may be achieved when an integrated and internal approach is taken to such considerations, while remaining cost effective, fully compliant and flexible.

The well integrity monitoring including Sustained Annulus Pressure (SAP) assessment on offshore stationary platforms in the conditions of a limited number of well slots plays an important role in the development of oilfield with thin oil rims and a massive gas cap. The presence of SAP leads to uncontrolled release of gas or liquid to the surface, disruption the operating condition of the wells and its completion components, that overall can result to severe accidents at the offshore oil and gas production facility. Another difficulty that SAP brings is secondary gas cap accumulation across untargeted reservoir zones that might lead to blowouts in operating wells. To identify the causes of SAP, constant monitoring of annulus pressure, as well as proper diagnostics are needed. One of the most reliable and effective methods for identifying SAP causes is Through-Barrier Diagnostics that able to accurately localize reservoir-sources of SAP behind multiple casing strings in the wells, which helps production engineers further production strategy and weighted workover planning. Conventional diagnostics on identifying SAP sources is significantly limited by complexity of the well construction and downhole equipment. This paper describes using of Through-Barrier Diagnostics on the sources of SAP identification on the ice-resistant stationary platform named after Yuri Korchagin, detailly explains the approach and challenges on real case studies. High precision temperature and passive spectral acoustics play a key role in described technique. Passive spectral acoustics, which have a scanning radius of about a few meters, helps to detect fluid flows in the reservoir and behind casing channels in cracked cement.