Improved Oil Recovery Based On Optimal Waterflood Pressure

Abstract

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.

A Novel Water Injectivity Model and Experimental Validation using CT Scanned Core-floods

“…A large fraction of daily crude-oil production in the world is recovered either by waterflooding or from reservoirs with an active aquifer, as a result of water influx. Waterdrive increases oil recovery from 5 to 15% of oil initially in place (OIIP) (e.g., Kolbikov et al 2000), for primary recovery by simple natural-pressure depletion, to 25-45% of OIIP (e.g., Yee et al 2007). It does so at the cost of production of large amounts of water along with oil.…”

“…Several analytical predictive models were developed earlier to predict the decline in injectivity/permeability caused by clogging of the porous medium by retained particles. Almost all the models focused exclusively on either internal or external filtration, neglecting the fact that both effects could take place concomitantly (Herzig et al 1970;Eylander 1988;Vitthal et al 1988;Tien et al 1997;Kuhnen et al 2000). Pang and Sharma (1997) proposed distinct analytical models for internal and external filtration and then coupled them with the concept of transition time for predicting the overall decline in injectivity.…”

“…With the application of computed-tomography (CT) scanning in the area of particulate transport in porous media, Al-Abduwani et al (2005a) showed that the filtration coefficient can be obtained from the in-situ deposition profiles obtained along the length of the core at different timesteps. Although appreciable attempts were made to numerically model internal filtration, the validation of these models with in-situ deposition profiles obtained with dynamic CT-scan measurements was limited (Kuhnen et al 2000). Al-Abduwani et al (2005b) first proposed the method of post-mortem quantification of in-situ deposition profiles from image and chemical analyses by breaking the core samples into different segments.…”