Development of oil rims at oil-gas-condensate fields is accompanied by a high risk of gas coning which leads to well productivity losses followed by conversion of such wells to an idle stock. In order to increase the oil recovery factor of oil rims and to eliminate early gas breakthroughs, horizontal wells drilled in thin oil rims are equipped with autonomous inflow control system. The study describes the experience of AICD application for one of the largest fields in East Siberia with an oil rim and a large gas cap, where an integrated analysis of the AICD well performance was conducted for the first time in Russia. This analysis includes: choosing well-candidates, performing AICD lab testing, sector reservoir simulation, modeling of AICD effect, followed by the actual well performance analysis after running AICDs. All this became possible due to the well-organized cooperative work of the operator and the contractor. The wells included in this study were successfully put into production at lower GOR values compared to their surrounding wells

This article describes general information about the geological structure, the identified complications during the construction of wells at the Kovykta gas condensate field associated with abnormally high reservoir pressure (AHRP). Based on the initial data and analysis of previously drilled wells, the requirements for equipment, the choice of drilling fluid density and the applied engineering solutions were formed. The goals and objectives of the project are outlined and the conditions in the process of drilling the section are presented, technological schemes and procedures are compiled during operation. Introductory training on managed pressure drilling technology was conducted with the personnel of the drilling and oilfield service companies. The revealed new mining and geological conditions and the complications that arose with them, and well-timed decisions allowed us to achieve the design depth of the section. The possibility of using brine for drilling the section using mudcap drilling technology was also confirmed. According to the final data, after drilling and fastening the section, new goals have been set for new wells at AHRP intervals. During the section drilling, various works were repeatedly performed in the presence of wellhead excess pressure, but the developed procedures, analysis, and risk assessment allowed to complete the project without incidents or accidents. Based on the gained experience, a number of decisions were made to optimize the well construction process at the field.

The near-critical initial state of the formation fluid with a unique content of C 5+ components in a tight reservoir with high temperature and abnormally high reservoir pressure (AHRP) causes significant difficulties in collecting samples of the formation fluid and assessing their adequacy to the actual reservoir mixture both in composition and identified phase state (gas condensate or oil) and phase behavior. The paper presents the result of the work of the project multidisciplinary team, which includes specialists from the PJSC «NOVATEK» group of companies and the leading Russian Institute of Oil and Gas Problems (OGRI RAS), of studying the near-critical gas condensate system in a HPHT tightreservoir. The effect of well completion and sampling conditions on the composition, phase state and phase behavior of fluid samples is shown. The influence of formation water and residual liquid hydrocarbons (HC), capillary effects, adsorption, and the specifics of the PVT-model tuning on the dew point pressure, the condensate lossdynamics, and the variation of composition and phase state of the fluid with depth is assessed. The results made it possible to clarify the understanding of the reservoir system,develop a program for further research, and improve the history matching of the flow model. The performed modeling of various factors in a porous medium for the conditions of the studied reservoir showed that the presence of formation water and capillary effects do not noticeably affect the phase behavior of the fluid, but the possible presence of scattered hydrocarbons and the adsorption / desorption of hydrocarbon components can lead to considerable changes in the dew point pressure and the condensate loss dynamics. The significant influence of the PVT model tuning on the calculated distribution of the initial fluid composition over the reservoir volume is demonstrated, including the position of the gas-oil contact and its type (classical gas-liquid contact or supercritical transition to the liquid state).

Installation of production tubulars is a critical job that has a direct impact on the overall productivity of the well. Thus, it is equally significant to predict the accurate flowing bottom-hole pressure (FBHP) in order to garner utmost benefits from the system by constructing the right vertical lift performance (VLP) curves. In fact, constructing the accurate VLP curves helps us identify the liquid loading times of wells and hence be able to predict when to install velocity strings or different artificial lift systems. For years, efforts have been made into developing mechanistic models and correlations to predict FBHP. However, all present correlations are developed under laboratory conditions and each have their own limitations for specific types of flow regimes. Mechanistic models integrate the physics of downhole conditions and yet they do not provide accurate results for FBHP. Therefore, artificial neural network (ANN), functional networks (FNN), and long-short term memory (LSTM) models were utilized in this paper. The designed models have been validated over a diverse range of data sets. More than 30,000 data points were collected from various wells with wide range of inputs. The inputs utilized in the AI models are from daily flowback data including wellhead pressure, wellhead temperature, true vertical depth, fluid specific gravity, chloride content, watercut, fluid rates, and water gas ratio. The data were then split as per the ratio of 4:1 for training and testing in order to generate accurate results. Then, the models were tested on other new well to test their accuracy. ANN model has proven to be the most accurate machine learning model and therefore, the results from the designed model were compared with the results of existing empirical correlations and it was evident that AI model outperformed them in terms of average absolute percent error (AAPE), and correlation coefficient (CC).

The paper considers gas option beginning and forcing in case of U 2-6 reservoir of oil and gas condensate Novoportovskoye field, which is an underlaying-typed oil rim with a massive gas cap. Based on conducted analysis the recommendations for the further gas option development with oil production losses minimization and gas production maximization were formulated.

Objective and Scope The oil and gas fields of the Bolshekhetskaya depression are characterized by significant remoteness from the existing infrastructures (roads, power lines, pipelines), as well as the severe Extreme North climatic conditions of the Yamalo-Nenets Autonomous District. The authors have worked out a complex approach to developing fields in this region to ensure a high hydrocarbon recovery level with economically viable indicators. The use of innovative solutions was tested at Pyakyakhinskoe field of the Bolshekhetskaya depression where commercial production started in 2016. Methods and Techniques Used, Process Description The development method worked out by the authors ( S.A. Solyanov, M.G. Mavletdinov, A.V. Zaytsev ) is unprecedented and was patented in 2016 (invention 2635926, 2017). The benefit of this development system is the cellular structure of the development elements consisting of seven horizontal or multihole wells, which allows exercising efficient control over development and also regulating voidage replacement in each cell. The development system is closed, which allows starting well development by cells. The well construction technology was improved to implement the proposed development system with the use of multihole wells. The substantiation of this technology implies the application of only the standard drilling and geological steering equipment. Results, Conclusions Today, two targets with the main oil reserves, BU 15 1 and BU 15 2 , are completely drilled with wells using the proposed development system and commissioned at Pyakyakhinskoe field. The current target development data confirm the forecast efficiency indicators and also the high efficiency of the developed technological and operating solutions. It is decided to apply this development system to other analogous targets of the Bolshekhetskaya depression. Well technologies with multizone hydraulic fracturing and multihole wells with a different number of wellbores were introduced and technologies of insulating separate intervals were tested for gas-condensate targets. These well technologies allowed increasing the commercial construction rate by 22.0-41.3% (depending on the drilled targets) and ensuring 100% successful liner running into the main horizontal section without additional activities and technical means. Novel and Accomplishments The development method worked out by the authors ( S.A. Solyanov, M.G. Mavletdinov, A.V. Zaytsev ) and implemented at oil targets of Pyakyakhinskoe field is unprecedented and was patented in 2016 (invention 2635926, 2017). The efficiency of using the closed development system based on horizontal injection wells and multihole horizontal production wells is confirmed with the actual well operation values, the planned indicators have been achieved in full measure. The production company has decided to apply this system to other targets.

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.

The present work is dedicated to the problem of developing oil and gas condensate pools with thin oil rims for neocomian deposits in the Urengoy region, and to the search for effective methods of oil production from thin rims. The key problems in the development of thin rims are the low cumulative oil production per well, as a result - low profitability and oil recovery ratio. The reasons are known: a sharp decline in initial oil rate due to the rapid increase in water cut and growth of gas factor associated with the water and gas coning. The results of hydrodynamic modeling at early stage in the development of oil rims often lead to optimistic forecasts that are not confirmed in practice. The paper provides an analysis of the reasons for optimistic calculations, tuning up models for the results of the development and operation of oil wells with different completion relative to the GOC. Obtaining history-matched oil and gas production systems made it possible to obtain a more reliable production forecast for oil wells, to substantiate the preferred target subsea depth for the completed interval in the rim and the type of completion. Scenarios with the completion of the horizontal section at a distance of one third from the GOC and OWC, or in the middle between the contacts, have been considered and analyzed. A comparison of the calculated performance of the wells with the actual one had been made. An economic evaluation of the operational efficiency of wells drilled on thin rims shows that their profitability based on oil production is marginal. The closer completion intervals of the oil horizontal wells to the GOC the higher economic efficiency of their operation due to additional volumes of gas and condensate production from the gas cap. The use of double-wellbore and multi-lateral completion of horizontal wells in the oil rim increases the economic attractiveness of the project. The integrated approach proposed in the paper to the organization of production and oil and gas processing systems from such oil wells makes it possible to technologically efficiently operate wells and ensure almost full utilization of associated gas. The joint development of gas condensate pools with thin oil rims allows for the cost-effective development of the ones.

A concept has been developed for gas, gas-condensate and oil fields exploitation planning in the Arctic region, taking into account the limitations of the existing external and internal infrastructure. The work was carried out as part of an integrated project management system to determine business opportunities and initiate the transition of field development projects to the pre - project development phase (Pre - FEDD). The paper considers the formations and geological structures of the Bolshekhetskaya Depression in the license areas: License area "Nakhodkinskiy" Licensed area "Pyakyakhinsky" License area "South Messoyakhsky" License area "Halmerpayutinsky" License area "Salekaptsky" Licensed area "West Tazovsky" License area "Vareisky" The choice of the profile of the horizontal section of the well is one of the main issues in the design and affects not only the final gas and condensate recovery, but also helps to clarify the geological structure of the formation during the well construction, as well as include all productive layers in the development, reduce the risk of complications during operation. Usage of longer horizontal wells will reduce drill footage; to increase the flow rate and profitability of wells; it is more rational to use formation energy due to lower values of depression on the formation and correspondingly reduced losses of condensate in the formation.

This work describes the technological solutions that were used in the development of the Novoportovskoye field - a large oil and gas condensate field in the Yamalo-Nenets Autonomous Okrug. In particular, optimization of the associated gas utilization strategy is considered by organizing the reservoir pressure maintenance. The decisions were based on 3D mathematical calculations, analytical estimates, analysis of field information and reservoir simulation. The paper presents the results of calculations performed to determine the specific efficiency of gas injection at productive formation. Additionally, weight coefficients of gas injection were calculated for gas well sites to identify the best injection zones. The paper provides the estimation of the current effect of the continuous two-year gas injection. The formation response to the gas injection into the gas cap was estimated by the usage of pressure-observation wells data, data from wells equipped with fiber-optic monitoring systems and by performing retrospective simulation. The calculations made it possible to achieve complete utilization of associated petroleum gas and significantly increase the oil recovery factor.

On the example of a gas condensate reservoir of field in Western Siberia with HPHT conditions, high condensate content and low permeability, the problem of reducing well productivity during operation are considered. Restoring of the near wellbore area permeability methods, reduced due to the buildup of retrograde condensate are studied. The effectiveness of previously performed acid treatments and solvent injection has been considered in order to increase the productivity of such wells. The analysis of the ambiguity and variable success of such events is carried out. An unconventional, but promising method of the condensate saturation reducing in the near wellbore areaof wells with multi-stage fracturing is proposed. These wells operate Achimov deposits with HPHT. This method consists of creating special thermobaric conditions in the near wellbore area, which allow to vaporize the largest part of the hydrocarbon condensate accumulated around the borehole. A condensate-saturated gas is extracted from the well to the surface. A search was held for simple, available and inexpensive technologies aimed at increasing both pressure and temperature in the wellbore and near-wellbore region. Based on the results of calculations performed on digital wells models in OLGA software, the thermobaric conditions created at the bottom due to the thermobarochemical effects are determined. The measures effectiveness of the retrograde condensate evaporation in the near wellbore areaand restoration of well productivity have been evaluated.

Formation and fracture damage coupled with condensate blockage might significantly reduce the productivity of the hydraulically fractured gas condensate wells. Implicit numerical representation of a hydraulic fracture oversimplifies and disables distinction of individual physically occurring mechanisms causing the well deliverability loss. In this paper, more realistic analysis of production impairment is presented by explicit fracture modelling using an in-house tool. The objective is identification and ranking of the main factors and flow characteristics contributing to productivity drop. The in-house tool can be characterized as an interface between a fracture design modelling software and a reservoir simulator. An accurate fracture geometry and spatial property mapping is incorporated into a reservoir model via local grid refinement (LGR) generation. An additional functionality of the in-house tool also allowed, based on the fracture report, to determine the initial distribution of the leak-off fluid around the fracture. A mechanically induced damage zone surrounding the fracture was reproduced by permeability/porosity reduction or transmissibility modification on the boundary between the matrix and fracture interface. Permeability modification along with stress-dependent transmissibility option were used to represent the damage of proppant pack on fracture gridblocks. Explicit and comprehensive numerical representation of the near fracture flow performance was first implemented in a synthetic model. The conducted study revealed that the damage both inside the fracture and in the formation accelerates and enhances the condensate blockage effect. High-velocity capillary number effect within the fracture masked the negative contribution of liquid drop-out on relative permeability curves and can also overwhelm the turbulent non-Darcy flow impact. To validate the observed phenomena a single well reservoir sector model with explicit hydraulic fracture representation was calibrated against the real production data. Adequate history match of the measured BHP was only possible with dramatic fracture and formation permeability reduction to account for damage processes. Condensate blockage effect caused more than 50% loss of gas flow rate.

This paper describes the results of efficient cooperation between the Operator, the General Drilling Contractor and the Service Company, who participated in the construction of horizontal wells in Yuzhno-Tambeyskoye gas condensate field. This document describes an integrated engineering approach to selection of new technical and technological solutions, which safely achieved all the geological tasks while constructing the wells. The key innovations of real-time data transmission from downhole tools, allowed the quality of the information received to be improved which increased the average rate of penetration (ROP) and reduced the well drilling time. Furthermore, during the project execution a multidisciplinary group of experts developed and successfully implemented a set of measures aimed at reducing flat time. Comprehensive planning, an efficient organizational structure, effective communication between all the participants and the introduction of new technologies resulted in the safe and successful construction of 6 horizontal wells with 1500 m long horizontal sections delivered 10% ahead of schedule. Along with the technological progress, it is important to note that during well construction a high level of HSE was achieved with no accidents occurring throughout the entire project.

We propose a novel technique to calculate bottomhole pressure (BHP) during well clean up and production using machine learning (ML) approaches solely based on the datasets commonly collected at surface from multiphase flow rates, wellhead pressure, wellhead temperature and fluid properties. We show that the proposed technique enables creating a digital analog of the downhole pressure gauge to provide stable and safer measurements of downhole parameters. The proposed solution was built by use of classical supervised ML methods such as linear regression, regressions with regularization, and decision trees. These models were trained for given well completion and trajectory using the field datasets consisting of a time series of various surface physical data (such as rates, wellhead pressure, and temperature), acting as input features and target value data measured by downhole pressure gauge. Once the training is complete, these algorithms can predict BHP variations using only surface data. We demonstrate that the ML models are capable of predicting BHP using wellbore-specific physical parameters and showing decent prediction quality with error less than 5% during transient flow regime. Moreover, we show that these ML models are capable of evaluating the bottomhole pressure almost instantaneously, unlike traditional numerical simulations that may require certain time for calculations. The proposed approach can be an affordable and accurate alternative to traditional solutions including either inverse task problem of BHP calculation or physical measurements with pressure gauges. In the classical approach, the transient multiphase flows are studied using mathematical models and numerical simulators. In this work, ML models applied to solve the BHP prediction problem demonstrated a low prediction error and a fast prediction time. The results can be used to efficiently control the drawdown during well clean-up and production.

In the first quarter of 2019, a system of two gas-tight expandable liner hangers was successfully deployed for the first time in gas-condensate wells in the Jurassic formation, West Siberia, for the company NOVATEK-YURKHAROVNEFTEGAS LLC. The main operation was performed in the YG-2 reservoir of Middle Jurassic deposits associated with high-pressure gas condensate formation. The work was divided in two main stages and an additional run of the seal assembly (stinger) with an anchor-type locator. Stage I, included the installation of a cemented gas-tight expandable liner hanger in open hole with alternative to rotate, reciprocate during running or cementing operations. Stage II, included running of an additional expandable liner hanger (ELH) assembly, in combination with open hole hydraulic packers and multi-stage fracturing sleeves into the horizontal section. An additional stage included seal assembly deployment with the tubing production string to provide for successful stimulation of the production flow using multi-stage frac (MSF) with the subsequent transfer of the well to the operation stage.

Liquid hydrocarbon quantity optimization is among key technological indicators in the gas condensate fields development. To achieve it one needs to select and maintain optimal well-operating conditions. In this case, multiphase flow measurements are prioritized as an important optimization tool. The article presents a proven record of implementing the technology of instrumentalised virtual multiphase flow metering in the wells of the Vostochno-Makarovskoye gas condensate field to increase the efficiency of liquid hydrocarbon production. Virtual flow metering technologies that use modeling methods and adapt models to actual well-operating parameters aiming at determining well production rates are becoming increasingly popular. At that, the quality of the data at the model input does not often guarantee a qualitative determination of multiphase flow parameters. This article presents a track record of building a virtual multiphase flow meter based on single-phase streamer flow meters mounted on gas wells. Venturi flow meters were used. A series of well tests were conducted in various modes. To configure the streamer model, additional tuning studies were conducted on the separator. While testing the wells, the results of constructing a streamer model were verified by nodal analysis.

Today, given the deterioration in the quality of proven reserves, a separate and extremely important issue is the possibility of using multi-stage hydraulic fracturing (MSF) in wells with complex geology. A striking example of the successful use of MSF using CT is the experience gained at the Messoyakha oil and gas condensate field, where the MSF was successfully carried out for hard-to-recover (HTR) reserves of viscous oil occurring in weakly consolidated terrigenous reservoir at low temperatures. At this stage of oil industry development, fields that are considered previously unprofitable, the so-called HTR, are increasingly involved in the development. The experience of Messoyakha oilfield is perhaps the most extensive in Russia in terms of testing various systems and strategies for completing horizontal wells with MSF in viscous oil, occurring in weakly consolidated sandy reservoirs at shallow depths and at low temperatures. Conducted work and conclusions can be used in the design and evaluation of similar in structure hard-to-recover reserves.

This paper reflects the experience of applying modern technologies to prevent annualr gas migration, crossflows and pressures (ACP), well integrity assurance during the gas and gas condensate wells construction in South Tambeyskoye field. South-Tambeyskoye gas condensate field is the largest in Western Siberia and the Arctic North of the Russian Federation. The development of this field is carried out by the JSC "Yamal LNG" (PSC "NOVATEK") - one of the worlds leading gas and gas condensate exploration & production companies with the participation of Total and CNPC. Proved and probable reserves of the field according to the international classification PRMS are estimated at 926 billion cubic meters of gas and 30 million tons of liquid hydrocarbons. At the South Tambeyskoye field, several field trial works (FTW) were carried out to prevent ACP on 4 wells: – 3 production wells on Valanzhinsky deposits with reservoir pressures up to 350 atm. – 1 production well on Jurassic deposits with reservoir pressures up to 820 atm. Technology effectiveness comparison to standard methods has been conducted based on field trial results. Based on objectives achieved using modern technology, field trial works considered succesfull.

These days more and more gas and gas condensate fields are reaching the late stage of development, which characterized with an increasing amount of challenges impeding recovery of reserves. In order to solve the problems, oil and gas companies employ different solutions which have certain conditions of practical application and different efficiency. Gas distributed compression solutions based on mobile wellsite compressors can be considered as one of the most modern and efficient solution. This technology has already established an excellent reputation in CIS countries and overseas by demonstrating the high result of implementation. However, in order to decide whether to implement this technology or not, it is required to elaborate a good feasibility study. The low level of the elaboration can easily overestimate the efficiency of the project as well as underestimate it thereby ensuing refusal of potentially efficient project. Since each project of technology implementation is unique it is not enough just utilize a common approach of project implementation to prepare an excellent feasibility study. Currently, it is quite difficult to find a methodology to prepare a decent feasibility study for mobile wellsite compressor implementation. The author while working on mobile wellsite compressor project has obtained solid experience which is reflected in this paper. Based on a dozen of integrated asset modeling simulations system of criteria for candidate selection for wellsite compressor installation was elaborated. In order to improve the efficiency and flexibility of the wellsite compressor operation an optimized approach to well hookup was advised. With the intention of improving the economic efficiency of mobile wellsite implementation set of recommendations was provided. The paper can be used as a basis for creating a solid feasibility study for wellsite compressor implementation. Recommendations provided in the article will enable not only improve the feasibility study but also minimize time and computational power allocated on the project.

Well spacing optimization is very important at the stage of drilling the reservoir. It is critical for the whole project economics. After the reservoir is already drilled it is very important to understand does existing wells drain all the reserves of infill drilling requires to improve recovery. Such task was solved on a tested area - Western part of Karachaganak gas condensate field. It has a complex geology, built as a massive heterogeneous carbonate reef of a Carboniferous age. PVT properties of the reservoir fluid significantly varies with depth. The area is produced with horizontal wells to maximize contact with the reservoir. The Multi-well Retrospective Testing (MRT) on base of multi-well deconvolution of historical rate and bottom-hole revealed well drainage area and well interference (1 – Aslanyan, 2018 ; 2 – Aslanyan 2017 , 3 – Aslanyan 2019 ). The MRT study is showing a strong pressure depletion trend and a fair connection between wells in the certain areas like core of western build up.