Thin oil rims associated with gas-condensate field development have one common problem – low oil recovery. The main reasons are fast gas and water conning of the producers resulted in sharp oil rate decline and low cumulative oil production per well. One of the main reasons of low recovery efficiency is that with oil saturated thickness less than 10 m most of oil in place volumes allocated to transition zones. Thin oil rim development was studied based on the 3D numerical simulation of one of the pay zones in Low Cretaceous formation of Western Siberian gas-condensate field. Several development scenarios (on depletion, with water injection, with and without simultaneous gas production from cap, different well completion) were analyzed. Thin oil rim development was studied based on hydrodynamic modeling of West Siberian gas-condensate fields with oil rims at Low Cretaceous sands. Analysis of several scenarios of oil rim development with different well completion, and gas cap development at different timing are given. Several factors were estimated with strong impact on the effectiveness of oil rim development (oil rates decline, water cut and gas-oil ratio growth, cumulative oil production per well): capillary pressure definition, well completion (horizontal vs. deviated), gas production from cap. Derived several conclusions: cumulative oil production from thin rims is very sensitive to the capillary pressure value, horizontal completion is most effective for rim development; limited production from the gas cap simultaneously with oil production could lead to a higher oil recovery at certain geological conditions.

The paper reviews oil recovery improvement for black oil fields with low bubble point pressure, which are developed under waterflood. The Kogalym field, located in Western Siberia, is approximately 2,400 meters true vertical depth, and produces from Cretaceous and Jurassic sand deposits. The black oil system has a bubble point pressure of 8.5 Mpa, less than 35 % of the initial reservoir pressure of 123.7 MPa. The optimal development strategy of such reservoir depends on selecting water flood elements, well pattern and flood pressure. The focus of this work is to justify an optimal waterflood pressure. In 1997–98 numerical simulation was performed on a separate waterflood pattern. A representative geological model of the pattern was constructed on the basis of comprehensive core analysis data from the well # 1037. Several development strategies were tested on the ECLIPSE model for various waterflood pressures: 24, 19 and 15 MPa. The maximum oil recovery factor (ORF) was obtained with a waterflood pressure of 15 MPa. The most economic case was with a waterflood pressure of 19 MPa. This pressure of 19 MPa is the optimal value of waterflood pressure, which is 75% of the initial reservoir pressure and exceeds the bubble point by more than 10 MPa. The analysis of the Kogalym field development for the last four years confirms these conclusions. Introduction The main method of oil production in Western Siberia is secondary recovery via waterflooding. Typical area reservoir development plans commence waterflood operations at initial conditions (Ref.1). This has been justified experimentally because of the increase of oil displacement factor with pressure. Early and intensive waterflooding provides high oil rates. This boost in production is favorable for cash flow and quicker payout. In the longer term, oil recovery losses due to low primary recovery and low sweep efficiency while waterflooding affects overall economics. The Kogalym field is being developed differently. The effective development strategy of the reservoir with low bubble point pressure depends on the selecting an optimal flood pressure. The focus of the work is to determine an effective strategy for the field, justified it by means of numerical stimulation and analyse practical results. Geological Prerequisite The Kogalym field produces from Cretaceous and Jurassic sand deposits. The main Cretaceous zone, BC11–2b, makes about 90% of the field total production and is the focus of this study. The pool has an impermeable boundary on the west due to a facies change from sandstone to shale, and is bounded by a limited aquifer on the east (See the Fig.1 and 2). The reservoir had a normal pressure gradient at the initial conditions. The vertical and horizontal heterogeneity averages a permeability of 50 mD and a porosity of 19%. The pay zone consists of up to five main sands subdivided with shale layers, which have an areal extent from several hundred meters to several kilometers in length (Ref.2). The vertical heterogeneity is presented in the geological cross section on Fig.2. Lithologically, the sands vary from highly permeable (up to 800 mD) to low permeability (less than 5 mD). The low permeable sands have a high content of sub capillary porous channels filled with connate water (Ref.3). This results in specific phase permeability for water given on the Fig. 4. The waterflood sweep efficiency of such reservoir should be low. The BC11–2b oil has a low bubble point pressure of 8.5 Mpa, (35% of the initial reservoir pressure) as determined from representative PVT analysis and confirmed by the field data. This low bubble point should allow pressure depletion to play a role in the overall recovery factor.

Profitability of investment projects for oil fields development is dropping drastically in the period of low oil prices especially if production drilling is in progress (so called "green fields"). Decision that is usually made in order to keep a positive annual profit during such period often leads to drilling suspension as the most capital-intensive process. Influence assessment of the investment project indicators in terms of fluctuating oil prices and long period of time has not been extended yet.The analysis of factors affecting the oil price and its trend building are brought in the paper. The evaluation of the investment project on the production drilling in the low oil price period is performed in two scenarios: high oil price volatility trend and current price. It was shown that in order to avoid loses in short term period the company and the government miss the benefits in the long term perspective. The case study is based on the 2008 economic crises. The methodology of project estimation by using high oil price volatility trend within its range of uncertainty is suggested in the paper.

In the practice of hydrodynamic modeling the anisotropy parameter (the ratio of vertical permeability to horizontal – kv/kh) is usually determined by experts as a fixed value varying in the range of 0.1-0.01, for the formation or for the field as a whole, and it is specified in the adaptation process of the model to the development history. This approach is applicable and is successfully used for deposits characterized by low degree of lateral heterogeneity. However, at the present time, a significant number of deposits are in development, the productive layers of which were formed in continental and coastal-marine environment, and therefore are distinguished by a complex geological structure due to high lateral and vertical anisotropy. For such objects the use of the conventional approach with a fixed value of kv/kh leads to an incorrect consideration of the influence of the heterogeneity on effective vertical permeability. Thus, the necessity of an alternative method for constructing the kv/kh cube, recommended for use in the complex structure of reservoirs, is obvious. The paper proposes a method for calculation the anisotropy parameter in 3D model cells intersected by wells as the multiplication result of the true anisotropy coefficient by the coefficient of pseudoanisotropy, which is modeled in the interwell space differentially for the facies zones by the method of cosimulation with NTG, reproducing the heterogeneity of the formation structure. The coefficient of true anisotropy is defined as the arithmetic average value from the results of core studies. The pseudoanisotropy coefficient characterizes the vertical heterogeneity of the formation within a single cell of a 3D grid. It is calculated for cells intersected by wells as a ratio of vertical permeability, which is the result of the geometric averaging of well log interpretation values, to lateral permeability, determined as the result of the arithmetic averaging [1]. For other cells of the 3D grid the anisotropy parameter is modeled by the method of cosimulation with NTG, which correlates with pseudoanisotropy coefficient. The use of the proposed method for modeling of anisotropy cube in process of hydrodynamic calculations allows to take into account the influence of heterogeneity on the effective vertical permeability differentially for facies zones and sedimentological units within facies zones.

The paper reflects problems of gas-condensate recovery for the low permeable sands based on laboratory and analytical PVT analysis and 3D modeling approaches.Gas-condensate recovery factor (CRF) for the gas-condensate fields depends a lot on initial CGR, filtration properties of the reservoir, well spacing and completion, development plan, economical indexes and final (abandoned) reservoir pressure. High CGR content specific for deep and low permeable zones already determine low gas-condensate recovery factor. On other hand, low permeability leads to deep pressure drawdowns and uneven pressure distribution and trigger earlier and bigger condensate losses in the formation.CRF official approval according to the current Russian regulations is based on the PVT laboratory or analytical data for 100% gas recovery or 1 bar abandoning formation pressure without taking into account reservoir parameters and system of development. At such pressure conditions and without reservoir properties the ultimate approved condensate recovery factors is too high (over 60%) due to evaporation of liquid condensate below the cricondenbara pressure and neglecting condensate drop out around well bore and in the low pressure formation areas. Due to mentioned above factors the actual ultimate CRF is much less than the approved ones that leads to the losses of economical effectiveness of field development.The paper reflects the problems of gas-condensate recovery for the low permeable reservoirs and the way how to improve it by implementing a gas cycling process for one of the Western Siberian fields with high initial CGR. The main conclusion is made to use 3D modeling for the correct forecast of the ultimate condensate recovery factors and justification of optimal methods to enhance it.