The success of the drilling campaign including drilling efficiency, service quality, personnel safety and cost is critically dependent on robust solutions developed during the design phase of the overall well construction process.
One of the most critical stages of the overall well construction process is the well design phase. The drilling project service quality, personnel safety, drilling efficiency and cost directly depend on the robust solutions elaborated at the design phase.
This paper describes the advanced technical engagement between an operator and an integrated services company to generate a basis of design for drilling and completing development wells in the Filanovskogo offshore field, in the north of Caspian Sea. The basis of design is a document that describes well design principles, engineering solutions and technologies required to drill and complete the wells. The paper explains the design approach selected by the project team, project design stages, foreseen challenges and technical solutions to deliver efficient well designs that could meet operator requirements and comply with Russian regulatory rules.
The key technical challenges of the Filanovskogo field are that the reservoir zone is located at shallow true vertical depth (TVD); the high formation collapse gradients and low mud loss gradients create a narrow mud weight window environment, along with complicated well profiles involving – multilateral horizontals and extended reach (ER) wells. This paper illustrates the development of a basis of design to ensure cost-effective access to reserves. It covers the operator and the service company experience in the drilling of ERD wells, applying advanced technologies for windows milling, completion options screening process and designing a multilateral junction. It also provides an understanding of the importance of operator and service company departments integration processes in order to achieve well objectives. To support the basis of design development, a comprehensive risk register was generated to minimize drilling risks.
The process of technical integration between the operator and the service company in the early stages of operational planning by developing drilling and completion design is unique for Russian O&G operators and was done by assuming that it would be very efficient through providing technical integrity and minimizing the project risks. The drilling and completion design consideration processes described in this paper can be used to provide valuable insight for future projects where up-front complex technical study is key to success.
Permanent downhole monitoring gages (PDMG) are significantly improving. Gages reliability and accuracy are increasing. At the same time there are still many in Russia believe that the organization of continuous monitoring - is branding costs that do not bring profits.
The paper presents an example of one of the Western Siberia fields, where the effect of PDMG wide implementation is easy to see. Based on the analysis results of the monitoring of downhole parameters using PDMG, which are installed in all the wells in 2012, large-scale optimization of production enhancement operations have been done to improve oil recovery to 0.09 relative percent.
The subject field in Western Siberia is terrigenous and has complex geology. This is due to layers pinch-out, complex deposits configuration and significant lateral heterogeneity. Reservoir depth is more than 2.5 km. In all wells hydraulic fracturing operation has been performed (fracturing).
The pdf file of this paper is in Russian.
The ventricular formation structure, hydrodynamic isolation interlayers, low porosity do not allow to develop the field by traditional methods. Creating of new field development, methods requires a lot of analytical work, a comprehensive laboratory analysis and mathematical modeling, taking into account features of the Achimov deposits.
In this paper the of complex experimental research results on cores of Achimov deposits for anisotropic porous media is given and theoretical model is described for correct interpretation of the results. Due to new laboratory technique, authors showed that Achimov deposit characterized by anisotropy of reservoir properties
Laboratory measurements were made with using four specially oriented samples which was cut from full-size core of standard size. Two samples were oriented in the direction of the stratification along the principal directions of the coefficients of permeability tensor one - perpendicular to bedding, and another - at an angle of 45 degree to the bedding plane. The last fourth core was a control sample. It was used for testing of theoretical model and proof of tensor nature of mathematical objects for describing of real anisotropic deposit. In addition this fourth core was used for evaluation of the measurement error.
The experiment showed that the layers deposits Asimov have pronounced anisotropy. In addition to porosity, absolute permeability there were also constructed distribution function of pore radius and capillary curves. The experimental results have allowed defining the characteristic linear dimensions of capillaries (effective diameter), luminal values. Measurements on the fourth sample showed that the permeability characteristic linear dimensions of capillaries, luminal, capillary pressure jumps define by the symmetric tensor of the second rank.
The experimental results were processed using theoretically derived formulas. Established a good agreement between theoretical and experimental results that allows us to recommend for engineering calculations, as proposed formula and co to conduct laboratory methods of reservoir properties investigation for anisotropic reservoirs having orthotropic filtration properties, including the definition of the functions of relative permeability, limiting pressure gradients nonlinear filtration laws, etc.
Grachevskoe oil field, Republic of Bashkortostan, has a unique development history with the application of an EOR technique which involves injecting a mixture of natural gas and associated petroleum gas into the reservoir. The injection fluid is sourced from this field and a cluster of nearby fields united in a single gathering and processing system. A production stimulation technique applied to the reservoir also included a series of subsurface explosions to create a network of induced fractures. A slug of natural gas liquids was pumped into the reservoir to improve the displacement efficiency prior to gas injection. The paper presents a comprehensive analysis of the production field data and core analysis data and describes a static and compositional dynamic model of the reservoir. The project was elaborated by a multidisciplinary team of specialists and their close cooperation resulted in a dynamic simulation of a fracture network within the reservoir, improved understanding of complex mechanisms driving oil-gas displacement, the effect produced by the changes in the type of the injection fluid or injection pattern and current in-situ oil and gas distribution. The next step in the project involved an integrated compositional model which also included the surface facilities and well-scale models. The combined model was calibrated against the limitations of the surface infrastructure. The integrated model was used to optimize the field development plan subject to the current conditions in the reservoir and the availability and capacity of the gathering and processing system to which the field is connected.
The pdf file of this paper is in Russian.
Nowadays petrophysical uncertainty is taken into account by major western companies for the field evaluation alongside with existing geological uncertainties. Several published papers review and generalize the main theoretical aspects. However, for Russian companies this idea of stochastic well log interpretation is rather innovative. Thus, the main objective of this paper is to represent the Monte-Carlo simulation method, frequently used in Total for the petrophysical interpretation, on the example of Termokarstovoye field. The stochastic interpretation was performed on two cored wells (providing the uncertainty reduction by the presence of core measurements), logged with wireline PEX tool.
Basically the stochastic interpretation follows the deterministic one and tells how much results vary around the deterministic result. Furthermore, the proposed methodology allows the interpreter to determine the most relevant uncertain parameters on which additional measurements or justifications are required to reduce the petrophysical uncertainty.
Following the described methodology it was identified that the main uncertainty on Termokarstovoye field is saturation. Its influence on the final HCPV (cumulative hydrocarbon pore volume) distribution can be decreased by providing the additional analysis on formation water salinity and by resistivity log inversion, which are the two main impacting parameters.
Thus, experience while running the Termokarstovoye practical case highlighted that, firstly, the final petrophysical uncertainty can be explained and justified. Secondly, further recommendations can be made on new acquisitions to later decrease the uncertainty.
The pdf file of this paper is in Russian.
This paper provides a compelling review about the world largest nitrogen IOR project in the supergiant field Cantarell, an oil field offshore Gulf of Mexico. Cantarell is Mexico’s largest resource being operated by Pemex. The very successful IOR project includes the daily injection of up to 1.5 bn scf (50.000 tons) per day of nitrogen for pressure maintenance since year 2000.
The basic reservoir characteristic and production history will be discussed, including the very positive field response of more than doubling the oil production from 1.0 million to 2.2 million bblpd. Alternative EOR technologies are techno-commercially assessed. The supply of the required nitrogen volumes by air separation plants and the associated infrastructure will be explained in detail.
The conclusion is that nitrogen for pressure maintenance (IOR) including the use of nitrogen for gas lift is a state-of-the-art technology with proven success in offshore fields.
The pdf file of this paper is in Russian.
Kharyaga Object 2 is an oil bearing reservoir with a gross thickness of 160-250m deposited on a rimmed shelf system. Two domains can be distinguished: the platform margin (the barrier domain), highly fractured and karstified, and the platform interior (the back-barrier domain), almost fault and fracture-free, non-karstified, and which shows a matricial behavior. Both domains are developed.
As per current vision, flow behavior in the barrier part is mainly controlled by different dissolution features and a complex secondary porosity network. Field development started in 1999 and significant amounts of data were acquired (extensive use of down-hole gauges – MDT – PLT, well tests, interference tests, etc.). Integration of new data into the dynamic model required a rigorous history match process and an efficient workflow with a permanent link to the geological vision. A progressive match by steps (conductivity à static pressure à watercut à vertical inflow performance à well interference) helped to avoid being overwhelmed by the amount of data to be matched.
This elaborated matching scheme permitted, as a result, to distinguish and reveal the impact of all types of heterogeneities on the matching process (matrix, karst or fracture dominated) and calibrate a complex representation with a dual medium (matrix and secondary media, the latter merging various types of karst, faults and fractures).
Representing properly the field complexity required a significant number of cells, as well as the use of specific mechanisms (imbibition with hysteresis and gravity drainage). To simulate such sophisticated representations in a reasonable time, a new powerful software and high computational power were required.
As a result of the smart use of acquired data for the calibration of the dynamic model, a powerful tool for reliable production forecast and business management was developed.
Golovanev, A.S. (LLC Lukoil) | Potryasov, A.A. (LLC Lukoil) | Kovalev, V.N. (LLC Lukoil) | Yunusov, R.R. (LLC Lukoil) | Burdin, K.V. (Schlumberger) | Mazitov, R.N. (Schlumberger) | Bravkov, P.V. (Schlumberger) | Serikov, D.A. (Schlumberger) | Klimenko, V.N. (Schlumberger)
The pdf file of this paper is in Russian.
The widespread application of multi-stage fracturing technology in Russia is already known not only due to increase of production rates and increase of recoverable reserves but also due to premature water flooding of some intervals. Several reasons could lead to that result, while, perhaps, the main one is a breakthrough in the aquifers in the process of the fracturing.
Objective of the job given by the client was to isolate water producing interval in a horizontal well completed with 8-stage MSF completion. To determine position of water-flooded zone, coiled tubing production logging tool (PLT) was used. Based on CT logging data 6th frac port of 8-stage MSF completion was found to be water flooded. Moreover, while total production rate of the well was equal to 500 m3/day (data was received during nitrogen lift while logging) with 95% WC, 68% of total production came from 6th frac port.
This article includes detailed study of planning process, complex and unambiguous decision-making aimed at technical and practical challenges, risk assessment and methods to reduce them, the stages of the work and planning in different situations that arise in the process of water shut-off and received lessons learned.
Volokitin, Y.E. (Salym Petroleum Development N.V.) | Koltsov, I.N. (Salym Petroleum Development N.V.) | Evseeva, M.Ya. (Salym Petroleum Development N.V.) | Nurieva, O.A. (Gazpromenft NTC) | Akhatov, I.S. (Skolkovo Institute of Science and Technology) | Kovaleva, L.A. (Bashkortostan State University) | Zinnatullin, R.R. (Bashkortostan State University) | Mavletov, M.V. (Bashkortostan State University) | Kudasheva, F.H. (Bashkortostan State University)
To minimize risks related to ASP flooding at West Salym field, experiments have to be carried out to study surfactant adsorption in the formation. Initially one should develop a necessary and sufficient list of experiments, as well as their conditions and interpretation of results. Therefore, two objectives were set: 1) determine the adsorption of anionic surfactant blend in static conditions adding NaCl, Na2CO3, and polymer within the working range of concentrations; 2) determine the adsorption rate of an ASP formulation in coreflood experiments for water- and oil-saturated cores under formation temperatrue.
The main reliability criterion for the results was the reproducibility of the surfactants adsorption experiments and achieving adsorption values within confidence interval. That is why, development of the methods that allow both to achive reproducibility of the results, and to identify sensitivity factors, is a critical aspect of the experiments.
The work presents an interpretation of the experiments for subsequent modeling of processes using mathematic simulators with the view to evaluate surfactant losses in formation during ASP flooding. The achieved results allow further optimization of the ASP cocktail and return a realistic value for surfactant losses in the course of its filtration, as well as ascertain the economic risks inherent to the project.
Length and profile shape of horizontal section of the production well is one of the main issues in the justification of horizontal well completion. Justified choice of horizontal well completion and profile design is based on the main objectives: provide high initial rate, maximize the cumulated gas and condensate production, reduce the risk of well drilling and completion, extend a period with water free production, hence resulted in the maximum NPV. The main factors that influence the choice of horizontal well profile are the geological structure of the productive formation, its reservoir properties, the location of formation fluid contacts, formation anisotropy, the ratio of vertical and horizontal heterogeneity.
In this paper we investigate the influence of mentioned geological factors on the choice of horizontal well profile. Various profiles of horizontal wells- directional, horizontal and U-shaped have been considered for gas condensate reservoirs. The analysis was conducted on the basis of hydrodynamic modeling Eclipse 300 using a function of multi-segment well.
After choice of the optimal length for the horizontal section of the well, a simulation was performed. Also there was a comparison of the performance for directional and U-shaped horizontal wells with the same length. During comparing the well performance well productivity, cumulative gas and condensate production, inflow profiles, the conditions of liquid removing from well bottom of were evaluated. Sensitivity evaluation of the optimal profile selecting to the reservoir permeability and its anisotropy was performed. It helps to take into account the effect of uncertainty on the performance of the well.