Understanding reservoir geometry helps optimize your waterflood

Geologist and engineers have always been faced with the challenge of trying to define, develop and optimize gas/oil fields. This is difficult enough when dealing with primary production in conventional pools but it can be even more difficult when applying EOR strategies. It is our experience that most of the waterfloods in the Western Canadian Sedimentary Basin (WCSB) are under-performing and a closer look at the geology of the reservoir is essential to understand why.

The objective of the project was to characterize and visualize the Lloydminster reservoir, give our client the reasons why, under waterflood, their production rates were declining and how to effectively increase the outcome. The critical first step is reservoir characterization and understanding the reservoir geometry based on detailed core analyses, regional geology and log petrophyisics. When done properly, subsequent integration with engineering data can greatly enhance reservoir performance prediction and facilitate greater hydrocarbon recovery through optimal flood designs.

This procedure helped to identify the sedimentology, deposition environment and variations of reservoir quality in the Lloydminster pool. The reservoir consists of clean homogeneous sand with a blocky signature and is commonly capped by a coal seam, (see Figure 1). It is a coarsening upward sequence with a mired mudstone base that progresses upward through more silt and wave or current-rippled fine-grained sandstone. It is interpreted to be a mired to marginal marine (shoreface) environment (wave dominated, tidally-influenced coastal plain). The model suggests sand that is both vertically and laterally consistent.

Isopach maps for gross formation thickness, gross sand thickness and net porosity thickness all reflect the relative consistency of the linear shorefaced depositional model. The sand is showing trending in a northwest to southeast direction, with the seaward direction likely to the northeast. The development of three thick areas that ultimately become the three oil bearing pods within the Lloydminster pool can be observed in the net porosity map. Core analysis data shows that porosity ranges from 24 to 32% with a permeability range of 80 to 400mD.

The Lloydminster pool is situated on a local structural high. While the gross sand thickness is consistent across the high, two post-depositional "sags" create three thick oil pods that are the production areas of the pool (see figure 2). The pods are interconnected by continuous oil play through the "sags" that are less than 2m thick. The entire oil accumulation is underlain by water.

The Lloydminster pool consist of five production wells that are located in the three oil pods, five observation wells that were unsuccessful in producing from areas with less than 2m of pay, and four water injection wells. The flood is operating as a vertical displacement flood, with water being injected directly into the water leg that underlies the oil accumulation.

The original oil-in-place was volumetrically estimated for the total pool and for each of the three pods within the pool. The pool estimate includes all pay contours to the oil-water contact, while the estimates for each pod extends only to the 2m pay contour. The pods were treated in this fashion based on the lack of success to date in producing wells that were placed in location with low pay.

The geological model presented above was realized only after careful review of all the data. Only when this reservoir model was described and understood could the pressure and production data be analysed properly.

Well production performance trends, along with an understanding of the reservoir geometry, are the primary indicators of waterflood performance, because the producing GOR is directly related to reservoir pressure, and because production data is the most continuous and most reliable data available. A relatively thin play, coupled with an adverse mobility ratio, severely hampers the effectiveness of conventional horizontal waterflooding. However, the presence of a continuous water leg underlying the Lloydminster oil, and the absence of vertical permeability barriers has been used to advantage, by injecting directly into the underlying water, thus creating a vertical sweep.

From the production profiles, a major issue for the Lloydminster pool is the efficiency of the well completions and the high water cuts. The structure map and the net oil pay map illustrate that the shut in wells are structurally low and have less oil pay than the wells that remain in production. The production plots for the five shut-in wells show that initial water cuts were in the order of 75%-90%, the wells had elevated producing GOR's and lower oil production rates despite initial fluid production rates that are similar to the wells with greater pay thickness.

Initial fluid and oil production rates were divided by the net oil pay to yield a "productivity per unit of pay comparison". The data shows that structurally low wells actually had higher total (oil + water) fluid production rates per unit of oil pay than did the structurally high wells. A low oil production rate per unit of oil pay is partly due to the higher water saturation in the perforated interval of the structurally low wells. It may also indicate that relatively more water is channelling past the cements in the structurally low wells which contacted the waterleg.

The initial reservoir pressure is estimated to be between 4860 and 5206 kPa. Reservoir pressure has been maintained at or above the original value in pods #1 and #2 but has decreased to between 4137 and 4391 kPa in pod #3. Wells with low producing GOR have recovered or will recover significantly more oil than wells with high GOR. The oil pay map illustrates that the two high GOR wells, 100/16-25 and 102/01-36 are both in pod #3. The pressure history corroborates well GOR performance and offers the first clue that only one injection well is in effective communication with Pod #3.

Pool bubble maps showing the highest GOR and lowest oil production visually illustrate that the wells in the southern and western portions of the pool are receiving adequate water from the waterflood while the eastern portion of the pool is under-injected.

Voidage Replacement Ratio (VRR) calculations for the pool indicate that, on average, the total water volume is adequate. However, recognizing the reservoir geometry and assigning the injection accordingly, it is evident that pod #3 is seriously under injected, as can be seen in Figure 3, which shows a cumulative VRR of 0.53 and the continuously increasing shortfall in injectivity. Changes in monthly VRR generate a rapid response in the producing GOR for wells in pod #3, and the monthly VRR correlates with the declining pressure trend. Calculations for pods #1 and #2 show adequate water injection volumes, with a cumulative VRR in excess of 1.0

An estimate for the remaining recoverable oil from each pod under existing operations was obtained by extrapolation of the exponential decline trend for each producing well to an assumed economic limit to obtain the remaining producible oil. Pod #1 exceeds the expectation of 40% recovery as an upper limit and sets the performance standard that should be realized from the other two pods.

Incremental reserves can be realized from pods #2 and #3 by increasing the cumulative VRR in pod #3 to at least 1.0 and by drilling an additional well in the norther portion of pod #2 to improve sweep efficiency. These actions are expected to increase oil recovery by about 24,000 m3, in pod #3 and 34,000 m3, in pod #2.

Further incremental recovery might be achieved with additional drilling, but this requires knowledge of the current fluid saturation profiles through the oil pay column. Should logging the wells show that the saturation profiles around the perimeter of the pods has not changed, this would indicated that the drainage area of the current producing wells is limited, thereby justifying the additional drilling. Conversely, if the saturation profile has changed, it would imply that the existing producers are draining more than their volumetrically assigned drainage. This direct evidence of effective drainage areas is valuable in developing the optimum depletion strategy.

Conclusion

The first critical step in optimizing your waterflood is to understand the pool geometry. As the reservoir characterization of the example pool evolved, the engineering analysis of pressure and production data became clear. It was not until the three pod version of the geological model was adequately described that the waterflood performance could be understood and recommendations made. IHS' advantage is the integration of geology with engineering and their interaction to come up with the best, most reasonable model that will facilitate greater hydrocarbon recovery in your waterflood.

Lisa Dean, Norbert Alwast and Ray Mireault, IHS Fekete Reservoir Engineering
Posted 9 September 2015

This article was published by S&P Global Commodity Insights and not by S&P Global Ratings, which is a separately managed division of S&P Global.