Drive indices for oil reservoirs indicate the relative magnitude of the various energy sources acting in the reservoir. A simple description of a drive index is the ratio of a particular expansion term to the net withdrawal (hydrocarbon voidage). These drive indices are cumulative and will change as the reservoir is produced. A plot of drive indices and the details of specific drive indices are shown below.
Typically, waterflooding commences after a period of primary production. The purpose of waterflooding is to enhance recovery by maintaining reservoir pressure, or when necessary, increasing reservoir pressure so that it approaches the bubble point pressure to maintain solution gas. Consequently, instantaneous voidage replacement ratio often commences at values greater than one, and then declines gradually to one as the target reservoir pressure is achieved.
Voidage replacement calculations are often conducted on the entire reservoir. Since reservoirs are more heterogenous than homogenous, even though the voidage replacement may be unity for the reservoir, some areas may be greater than unity, and others much less than unity. Most analysts consequently perform voidage replacement calculations on a pattern basis, matching each injector with a group of nearby producing wells. In this way, areas not receiving enough water to replace voidage can be revised by adding more injectors, or by shutting in producers. Likewise, areas receiving too much water can have the injection rates reduced.
Seidle (1999) suggested using a similar material balance as that developed by King, but with the simplifying assumption that the water saturation is constant. This simplification is justified by the assumption that the water saturation in CBM reservoirs have little impact on the calculations as the term in which it appears is small in comparison to the one in which it is added to. For much of the producing life a well, the expression for Z* is dominated by the ratio of sorbed to free gas in the denominator. Formation and water compressibilities are also assumed to be negligible. These assumptions result in the following expression for Z*:
A strong water drive provides very good pressure support from the aquifer (100% voidage replacement) with minimal pressure drop at the wellbore. The aquifer water expands slightly, displacing the oil or gas from the reservoir toward the borehole as pressure drops around the borehole. This mechanism exists only where the aquifer is of equal or better quality than the reservoir and has a much larger volume than the reservoir (about 10 times) or is in communication with surface recharge. A strong water drive is more effective in oil reservoirs than in gas reservoirs. On a semi-log plot of production decline, the curve tends to be flat.
In the oil industry, waterflooding or water injection is where water is injected into the oil reservoir, to maintain the pressure (also known as voidage replacement), or to drive oil towards the wells, and thereby increase production. Water injection wells may be located on- and offshore, to increase oil recovery from an existing reservoir.
If free crossflow can occur between adjacent layers, we recognize that gravity and/or capillary forces can influence the displacement, in addition to viscous effects . If the high-permeability layer is on the bottom, the greater density of water (over oil) could diminish polymer displacement into the upper oil zone, while capillary effects could enhance water/polymer penetration into the oil zones (if the oil zones have a significant water-wet character). However, other considerations tend to mitigate the impact of gravity and capillary effects. In particular, capillary forces are thought to be minimal for most viscous oil reservoirs . Also, the high viscosity of polymer solutions will diminish the rate of gravity segregation, in direct proportion to the polymer viscosity value.
In summary, for the case of free crossflow, a polymer/oil mobility ratio near one will give the optimum injectivity and pressure gradient within the oil bank. This is in spite of the fact that a greater sweep efficiency will result from injecting a more viscous polymer bank. Thus, for all three cases of (1) a single layer, (2) multiple layers with no crossflow, or (3) multiple layers with free crossflow, a polymer/oil mobility ratio of one should provide the optimum injectivity and pressure gradient within the oil bank.
Despite injection volumes exceeding produced volumes for several years (i.e. a voidage replacement ratio >1 for approximately one-third of the duration of the water-flood) the reservoir pressure remained in decline. Based on the geological maps (created primarily from log data) used to plan the water-injection pattern, there was no indication that the primary injection well was not connected to the main reservoir. The reservoir characterization and simulation study presented herein was initiated to improve understanding of the reservoir and to provide recommendations regarding flood optimization and infill drilling.
The successful history match illustrated in Figure 12, achieved after several iterations between static and dynamic modelling, provides confidence in the accuracy of the geological model to mimic fluid flow within the field. The primary conclusion drawn from the reservoir modelling was the confirmation of a discontinuity in the reservoir that was interpreted in seismic amplitude and attribute data. This discontinuity is of critical importance as it is located between the primary water injector (Well A) and the producing wells. This explains why, despite the cumulative voidage replacement ratio being greater than 1, the pressure within the reservoir continued to decline. Injection to the nonconnected well was ceased and all injection volume diverted to two within unit injectors with sufficient capacity to handle increased injection.
During the waterflood, there are likely to be opportunities to gather additional data away from the injection and production wellbores. These data can take several forms.Infill wells are likely to be drilled in locations where oil should not have been displaced by the injected water. Consequently, these locations are not good locations for determining how effectively the various portions of the reservoir intervals are being swept by injected water. After drilling, the hydrocarbon distribution actually present at an infill-well location is evaluated using openhole or cased-hole logging. Where formation waters have a sufficiently high salinity, pulsed-neutron thermal-decay time and resistivity logging may be used to evaluate the residual oil saturations. In lower-water-salinity conditions, carbon/oxygen and resistivity logging are used. Using these techniques, the locations of fully flooded, partly flooded, and unflooded reservoir intervals can be determined in new wells and in existing producing wells. Multiple logging runs over time in a producing well allow the monitoring and management of a waterflood. If wells are drilled later during the waterflood, then the residual-oil-saturation distribution can be obtained by use of special coring procedures or special tracer tests, as described elsewhere in this volume of the Handbook.Special observation wells sometimes are drilled at a location in the oil reservoir where the water/oil flood front should be detectable as it passes. Historically, most of these wells were cored but had steel casing, such that standard logging methods could not be used; however, before the development of through-steel-casing resistivity logging, fiberglass casing together with induction-resistivity logging occasionally were used to observe the water/oil displacement process over time.Recently, the 4D-seismic technique has been developed to determine in what directions the water is moving from the injection wells. The 4D-seismic technique compares 3D-seismic data that were obtained before the start of waterflooding to a second or third 3D survey that was conducted some years later. This allows an areal visualization of where there are high-pressure areas caused by water injection and where there are low-pressure areas caused by production (typically from the presence of some free-gas saturation near the production wellbores). Also, the 4D picture might show which portions of the reservoir pay intervals are well connected and which are not.
Surface subsidence was a major issue at Ekofisk. By 1984, the seabed had subsided approximately 10 ft, prompting a major project to jack up the offshore platforms. A major field study in 1992 concluded that using water-injection pressure maintenance to arrest the reservoir pressure decline could minimize future seabed subsidence. Voidage replacement was achieved in 1993. Additional laboratory studies found that water injection had induced shear in the chalk. Shear failure and water-weakening of the rock matrix causes additional deformation of the chalk, even under conditions of constant or decreasing stress levels. Despite the use of voidage-replacement waterflooding, seabed subsidence continued until 1998, when the subsidence rates slowed dramatically because the water-weakening effect was expended and the reservoir pressure had increased.In 1997, production began from the 50-slot production platform 2/4 X, and in 1998 full processing of the Ekofisk fluids was handled by the 2/4 J processing platform. These new "Ekofisk II" facilities replaced the aging original facilities and were designed to increase operational efficiency and to allow safe and economical production until at least 2028, the end of the current license period. The current best estimate of the ultimate recovery factor from the start of production through waterflooding is 44% of OOIP.During the past 20 years of waterflooding, many operational changes have been made at Ekofisk. The changes were a logical progression that was based on laboratory studies, field pilot tests, and engineering analyses of field production and pressure data. All of this has led to a very successful waterflood project, but with a few unexpected complications that the engineers had to handle in the course of the waterflood project. 2b1af7f3a8