The pdf file of this paper is in Russian.
Today, it has become pretty obvious that the rocks that were conventionally believed to be source rocks are, in many cases, oil bearing rocks. This oil bearing potential can be attributed to both filtration of the hydrocarbon fluids in the reservoir and artificial generation of liquid and gaseous hydrocarbons by heating the solid organic matter underground. The suggested differentiated approach to estimation of the resource base allows identifying and assessing oil bearing potentials for various reservoir stimulation techniques: drawdown (due to natural reservoir properties of the rock), creation of artificial permeability, and generation of hydrocarbons by in-situ pyrolysis of the organic matter.
Smirnov, N (PetroGM) | Torres, Martin Sigifredo Zaruma (REPSOL) | Valente, Livan Blanco (REPSOL) | Tadzhibayev, Rustam (REPSOL) | Vladimirovich, Molodtsov Roman (PetroGM) | Vitalievich, Kuznetsov Igor (PetroGM) | Pavlovich, Khomenok Ivan (PetroGM)
The pdf file of this paper is in Russian.
Wells with high strength carbonate reservoir formation generally practice open hole completion strategy. It allows to substantially reduce expenditures and risks associated with well construction. At the same time, borehole stability during well's exploitation depends on strength properties on the one hand, and stresses which rocks are withstanding during production on the other. In its turn stresses depend on many factors, related with geological aspects and are controlled by drawdown pressure applied to reservoir. Nowadays all main components for well stability can be identified with logging data, core information and software tools for modeling and computation.
In order to improve reservoir quality, quite often a near wellbore area is treated with different chemical agents and compositions. Unfortunately, a few people bear in mind, that after the chemical reaction rock might overcome significant changes as it weakens and deforms. This paper describes practical application of geomechanical modeling with Mechanical Earth Model construction [
In order to determine petrophysical and mechanical properties changes before and after acidizing, mechanical tests were conducted on the core samples from Bashkirian horizon. Results were used as a basis for justification and open hole completion optimization strategy.
The paper presents progress made in research and development (R&D) of emerging plasma-based technology for well intervention applications. The technology potential for various upstream applications has been presented at some other SPE conferences (March and September 2015 and January 2016). Current development phase, which is intended for well plug and abandonment (P&A) operations, allows planning applications relevant to modern well intervention needs such as slot recovery, re-entry, lateral drilling and several others.
The experimental basis uses a project plan, which is adequate for development tasks and is periodically updated based on the achieved results. This paper presents results of the latest experiments which focused on the evaluation of cement removal ability and quantification of plasma radial reach.
The paper includes several sections. The first section is Introduction, which briefly summarizes the background of the technology as well as introduces the scope of the experiments. The second section Methods and Procedures explains experimental set-ups, defines samples and procedures used for analysis. The third section Results and Observation describes in detail the main results obtained during extensive testing of the radial reach as well as the results obtained during experiments with three different types of water- and oil- based mud samples. Special attention is given to the result of the plasma impact on casing in case of eccentric position of tubing. The last section summarizes obtained results and presents the possible benefits of plasma-based technique on well intervention applications.
Currently, the research team performs development of infrastructure and bottom-hole assembly (BHA) for tubing milling for onshore and offshore field trials. Moreover, high-pressure (HP) testing well for BHA tubing milling operation tests in high pressure of water/brine environment is also under development. The testing environment will serve for the proof of the system and should confirm the ability of testing in field conditions.
Suchok, Sergey (LUKOIL International Upstream East) | Obsharov, Pavel (LUKOIL International Upstream East) | Ermilov, Andrey (LUKOIL Uzbekistan Operating Company) | Volnov, Ignatiy (LUKOIL Uzbekistan Operating Company) | Zhukov, Aleksandr (LUKOIL Uzbekistan Operating Company) | Yalalova, Venera (LUKOIL Uzbekistan Operating Company)
Nowadays there is observed a global trend of ever-increasing complexity and heterogeneity of hydrocarbon reservoirs. More challenging time makes companies take high-risk decisions based on long-term production prediction. As deterministic approach always gives a single result, it loses its relevance when we deal with risks. Generally probabilistic assessment methodology is coming to the forefront.
A new approach called RE-Status (Reservoir evaluation status) has been developed in this study. The methodology is based on probabilistic assessment and along with normal uncertainty technique it includes lithofacies modeling. RE-Status is based on six key parameters that allow us to understand reservoir complexity and level of project definition in terms of reservoir engineering.
Geological models were created by combining all geological and geophysical data in order to provide the highest-quality 3D representation of heterogeneous carbonate reservoirs. Evaluation of micro-macro heterogeneities and complex analysis of all core studies were used to derive lithofacies. Systematization of stratigraphic analysis, core descriptions and well logging data allowed us to locate facies in reservoir cross-section. It gave us better understanding of the reservoir and nature of filtration processes.
The new approach was applied to two gas fields. Impact of reservoir parameters and lithofacies variability on the dynamics of gas production was described. In the first case RE-Status helped to improve history matching by using facies and uncertainty analysis. In the second case (green field) production prediction based on the results of heterogeneity analysis and facies modeling allowed to locate sweet zones, optimize drilling strategy, increase reliability of forecasting and reduce the uncertainty range.
Novelty of the described approach is application of facies modeling to reduce key uncertainties, match the reservoir model to historical data and provide the most accurate forecast of production.
Malshakov, A. V. (Tyumen Petroleum Research Center) | Oshnyakov, I. O. (Tyumen Petroleum Research Center) | Zhadaeva, E. A. (ITERA) | Weinheber, P. (Schlumberger) | Ezersky, D. M. (Schlumberger) | Filimonov, A. Y. (Schlumberger) | Novikov, S. V. (Schlumberger)
The pdf file of this paper is in Russian.
Commercial production from the thinly-laminated Turonian deposits of North West Siberia has been proven in many wells. But despite the fact that we see these layers in many fields and they are in fact the primary development target, the reservoir properties are not well studied and thus their ultimate potential is unclear. To date, the obstacle has been the sand shale laminations that we encounter are on the order of a few millimeters to even fractions of a millimeter thick.
Standard log interpretation method have proven to be inadequate, including the application of the latest deconvolution techniques of using a high resolution measurement such as a microimager to inform the layering of standard resolution devices. Even core analysis is ambiguous due to the heterogeneous and anisotropic nature of the reservoirs.
In this paper we discuss a complete method of analyzing these thinly-laminated layers with a view to resolving a fuller petrophysical understanding.
The studied object is a part of a large field of the Uvat region (Western Siberia). The development process of the oil formation is conducted applying the waterflooding system. It is complicated by naturally fractured carbonate member and generation of auto-fractures at injection wells. The advancing rated of watercut and premature water breakthrough toward the production wells are observed. The studied reservoir has a complex geology, lithological intersection consists of clastic and carbonate members. Waterflooding system is not optimized: reservoir pressure falls and auto-fracs occur due to high repressions, that causes increase of watercut at production wells. Great amount of oil reserves is not withdrawn according to prevailing proceses. In this case, it was necessary to determine the reasons of noneffective development strategy and to optimize waterflooding system.
The algorithm for searching of a decision for optimization of reservoir development in case of auto-fracs generation is formed in this paper. The sequence of analysis and valid analytical methods for reasons determination of advancing watercut are defined during the work.
Complex analysis of geology, reservoir engineering, well testing and reservoir simulation forms the basis of the applied algorithm:
Analytical methods of advancing watercut determination are used during reservoir development analysis. As a result, the reasons of premature water breakthrough toward the production wells and volume of undrained oil reserves became obvious.
During the geology analysis main facies and features of the occurrence and spread are defined; created a distribution map of "superpermeable" facies. As a result, the map of wells interference is generated, in which zones of noneffective waterflooding and degree of reserves involvement in production are determined.
The presence of auto-fracs at injection wells is identified according to the well test analysis. As a result, dependency of auto-fracture generation pressure from injection rates and reservoir pressure is determine. Understanding of this dependency allowed to optimize technological regims of injection wells. Also, dual-porosity parameters of naturally fractured member are determined from these tests, after that simulation reservoir model was adjusted.
Because of the comprehensive analysis and understanding of all processes the large number of scenarios for reservoir development optimization appeared. To reduce the labor-intensive calculations and culling options the analytical model and the algorithm for choosing the best solution was formed. According to the algorithm several options were selected for more detailed calculation with reservoir simulation model.
Oil reservoirs are characterized by varying degrees of heterogeneity filtration-capacitive properties and the distribution of oil reserves in the area. In such conditions, with sufficient certainty in the geological properties of reservoir, production of oil may be more efficient with using of irregular well placement, taking into account the heterogeneity of the reservoir. Placing well in manual mode ("by eyes") with using some maps (effective oil saturated thickness, oil deposit density and rarely others) does not guarantee that the optimal solution will be found, taking into account all important reservoir parameters and already drilled wells. The purpose of this work is the development and testing an automated approach to finding the optimal well placement.
Finding of optimum well placement was implemented as a computer program.
We used a physical analogy in which the production and injection wells are charged point particles of two types in the plane. Stratum is represented as a two-dimensional map of the potential, and for each of its cells numerical value (potential) of the feasibility of placing well in it is calculated. This potential depends on the properties of the reservoir and the distance to other wells. An objective function is used to evaluate the optimality of a particular arrangement. It has a maximum at a maximum distance of each well from all others, a uniform distribution of production and injection wells, placing production wells in the area of influence of injection wells, and placing wells at most favorable location of the reservoir.
Search of a well placement which gives the maximum value of the objective function is performed using a genetic algorithm. To this some random initial well placements are generated. Each initial placement creates a number of descendants. The descendants are created by random changes (mutations) of coordinate of random number of wells, and random exchanges of wells type (from production to injetion and from injection to production). A descendant with the maximum value of the objective function creates new offspring. Evolution can last a specified number of generations.
The effectiveness of the proposed approach for placing of wells was evaluated in several test cases. In each case we considered two variant of placement the same number of wells: regular and irregular placement by the genetic algorithm.
Dynamic of oil production for considered variants were calculated by 3D numerical simulation. The calculation results showed that the proposed approach for getting of optimal well placement can give more values of oil rates and cumulative oil production. However, the evaluation of the objective function requires setting of weighs of parameters through which it is expressed. The correct choice of these weights substantially defines development effectiveness of given irregular grid.
The paper developed an approach for the automatic irregular placing of of wells, allowing to take into account complex of basic geological and technological parameters affecting the efficiency of the development. The proposed approach has been implemented in a computer program and can be used in the presence of geological and hydrodynamic models of the reservoir. Using of the proposed approach can achieve, with an appropriate choice of input settings, higher oil recovery and higher oil rates in comparison with the development based on regular placing of wells.
Well completion and commissioning operations offshore present a variety of technical and operational challenges in the quest to maximize well productivity and optimize the economic value together with focus on safety. This is very relevant to the perforation operations performed in hostile and high-pressure reservoir conditions encountered in a complex development project in the Caspian basin. We provide description of the project and the innovative solution applied, including challenges faced, experience gained, and lessons learned.
To overcome challenges, we selected electric-line-enabled (e-line-enabled) coiled tubing (CT) for precise depth control, and the latest advanced gun deployment system for conveyance of long gun strings under pressure. Innovative solutions implemented throughout the project included the perforation-shock-resistant bottomhole assembly (BHA), two independent emergency disconnects, and tuned software to predict and evaluate shock load and dynamic underbalance. Some of the unique technical solutions were designed specifically for this project: high-pressure and H2S-rated connectors; specialized tool deployment stack; 15,000-psi working pressure 5.12-in. ID H2S-rated rounded scallop guns; shock-resistant electrical disconnect; and high-tensile CT logging head disconnect weak points.
To date, more than 10 well commissioning operations were successfully completed with this innovative method—e-line-enabled CT perforation under high pressure. This perforation technique proved to effectively minimize operational time, associated risks, improper equipment use, and footprint on location. Such approach allowed safe and efficient perforation in a controlled well environment that resulted in accurate depth control and managed detonation shock load and overbalanced conditions, which avoided any well fluid influx or H2S release. The developed solution required seamless integration of innovative techniques and hardware, including e-line enabled CT, the CT logging head, the gun deployment system for pressurized well conditions, wireline tools and specialized perforation equipment. The design was optimized to perforate the well in three or four runs at overbalanced condition (squeeze mode) in a single rig-up job instead of more than 20 wireline runs. Additionally, the use of CT granted flexibility and increased operational safety to perform pumping operations for well displacement and well control, injection of H2S scavenger, and stimulation, as per Operator's plan, without or with only partial rig-down.
This is the first time that the described CT perforation operation using such techniques has been performed in the Caspian region. The experience demonstrates a method to safely and efficiently facilitate perforation jobs under challenging conditions in the future.
Gilmanov, Y. I. (LLC, Tyumen Petroleum Research Center) | Fadeyev, A. M. (LLC, Tyumen Petroleum Research Center) | Salomatin, E. N. (LLC, Tyumen Petroleum Research Center) | Borodin, D. A. (LLC, Tyumen Petroleum Research Center)
Saturation evaluation and reserves estimation by well logs requires laboratory determination of capillary and electric properties including evaluation of cementation exponent (m) and saturation exponent (n). Crucial task is to improve reliability of modeling reservoir-rock residual water saturation based on laboratory methods. One of the solutions is to conduct studies under conditions simulating in-situ conditions which will allow more accurate determination of oil saturation when estimating reserves in the accumulation, and more correct prediction of field performance. Capillary pressure curves behaviour in PT conditions is critical for understanding the mechanism of water-oil saturation distribution throughout the hydrocarbon column height.
The problem was solved with using special laboratory equipment on which capillary pressure curves were produced for sand samples based on porous plate method in individual coreholder with simultaneous measurement of electric resistivity.
Main objective of the study was to find out the difference between capillary and electric properties produced in ambient and PT conditions.
Yao, Shanshan (University of Regina) | Wang, Xiangzeng (Shaanxi Yanchang Petroleum (Group) Corp. Ltd.) | Zeng, Fanhua (University of Regina) | Li, Min (Shaanxi Yanchang Petroleum (Group) Corp. Ltd.) | Ju, Ning (University of Regina)
The pdf file of this paper is in Russian.
Analytical multi-linear models are popular in the well testing analysis of multi-stage fractured horizontal wells (MFHWs). But such models are challenged now. In high density network of hydraulic fractures, the fluid flow around fracture tips no longer behaves like linear flow. Moreover, the production behaviors of hydraulic fractures are different at different stages in heterogeneous reservoirs. To overcome the two challenges, this study develops a semi-analytical composite model for MFHWs in heterogeneous reservoirs.
The stimulated reservoir is regarded as a combination of several closed sub-systems with hydraulic fractures centered or uncentered. Each sub-system is further divided into several regions based on reservoir heterogeneity and flow characteristics. Reservoir and hydraulic fracture properties can be different in those regions. The production from each region is modeled by the solutions of linear flow equations or radial flow equations or source/sink functions. The production from a sub-system is modeled by coupling the solutions of regions in the sub-system. The production from the whole reservoir is then modeled by coupling the solutions of all sub-systems. The composite model was validated by analytical solutions in homogeneous reservoirs and numerical solutions in heterogeneous reservoirs. Calculations of production pressure and rates with this composite model generate type curves for the pressure and rate transient analysis of MFHWs. Two field cases are further analyzed with the type curves.
One novelty of this model is to consider the non-linear flow around hydraulic fracture tips. Therefore, our model is better prepared for incorporating pressure-dependent heterogeneous reservoir properties in the future. The other novelty of this study is the ability to model the different production behavior at different fracture stages in complex heterogeneous reservoirs.