Reservoir simulation

Understanding Waterflood Response in Tight Oil Formations: A Saskatchewan Case Study

An 18-well numerical-simulation model was built to represent an operator’s Lower Shaunavon waterflood-pilot area. Numerical simulation was used, and a history match on the pilot area was performed.

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An 18-well numerical-simulation model was built to represent an operator’s Lower Shaunavon waterflood-pilot area. Numerical simulation was used, and a history match on the pilot area was performed. By use of parameters obtained from the history match, a representative model was built and a sensitivity study was performed on hydraulic-fracture spacing and well spacing in both primary-depletion and waterflood scenarios.

Modeling-Work-Flow Description

The Shaunavon is partitioned into lower and upper members. The lower member is an authigenic carbonate shelf, while the upper member has a strong clastic influence from the west. Oil is trapped hydrodynamically; the oil fairway crosses both stratigraphic and structural trends.

The Lower Shaunavon is divided into four intervals in the study area. The lowest interval is a calcareous cryptocrystalline mudstone. Sitting above this interval is the B Marker, which is a slightly more energetic environment. The A Marker marks a regressive lag as a result of a sea-level drop. It consists of wackestone to some packstone rock and is bounded above and below by mudstones. The uppermost interval represents a high-­energy environment.

A geological model was developed for the lower Shaunavon pilot area on the basis of well logs, petrophysical data, and surface maps. The model was developed further into a dynamic simulation model by incorporating pressure/volume/temperature data, relative permeability, well trajectory, well completion, and historical well-production and -injection information for all wells located within the pilot area.

A history match was performed on a single-well submodel to obtain improved values of reservoir hydraulic-fracture properties in the surrounding region. These values were applied to the full pilot area, and the model was simulated in an attempt to achieve a history match. Once the pilot area was history matched, forecast runs of an additional 50 years were performed to gauge future production along with future drilling scenarios. By use of the properties obtained through history matching, a new generalized model was built and different forecast scenarios were run to determine well spacing under both primary depletion and waterflood. For a discussion of reservoir-parameter selection and ­simulation-model setup, please see the complete paper.

History-Matching Work Flow

A single-well submodel was extracted from the pilot area to determine fracture properties better. The chosen well was picked on the basis of the distance to adjacent wells and potentially limited effects from the water-injection well. It was also observed that microseismic activity had been detected in all 10 vertical layers (approximately 20 m) the model incorporates. Therefore, it was assumed that the hydraulic fractures break through all 10 layers and connect all layers of the model from the top of the model to the bottom where fractures are located.

Hydraulic-fracture placement was provided by the operator, and biwing hydraulic fractures were entered into the model. History matching concentrated on matching withdrawals of oil and water, and the gas-production profiles held limited weighting to the effectiveness of the history match.

Once the fracture properties were found from the submodel, the results and information were transferred to the full pilot area. A range of the most-­sensitive parameters was adjusted during the history match to reduce the error between historical production and the simulation results.

History-Matching Results

All wells were able to achieve a match on liquid, oil, and water production within a reasonable degree of accuracy, with the exception of oil production on one well (Prod 12). A reasonable match on the gas-production trend was achieved; however, gas production may not have been recorded at certain times throughout the simulation time period. An oil match was difficult to achieve on Well Prod 12 at late times. Similar to Well Prod 2, because of the proximity of the INJ 1 injector, late-time oil production was difficult to match because injected water proved to have preferential flow over reservoir oil. Unlike Prod 2, if the well is not connected to the high-permeability streak by hydraulic fractures, water demand cannot be met. Therefore, it appears that Prod 12 is receiving pressure support from the neighboring injector, and that injection water is most likely present in the historical liquid-production data. Because the match of the late-time production cannot be achieved, it is believed there is a geological event or there is a wellbore-­related issue that is unknown at the time of simulation and that prevents a good history match from being achieved.

On the basis of the simulation model and input data, it was observed that the flood front caused by waterflooding in the Lower Shaunavon reservoir is extremely slow and considered negligible with respect to the simulated time frame. Pressure maintenance is observed in wells surrounding the injector, but this support is not sufficient to supply the demand of production, especially related to water production. Once there is a connection between the high-permeability layers, historical injectivity is observed. Water injection was tracked separately from reservoir water in the model and was used extensively in the history-matching process to investigate the movement of injected water throughout the reservoir. The simulation indicates that the majority of the injected water travels through the hydraulic-­fracture network and into the high-permeability streak. The benefits of the waterflood are evident when comparing the full-height fracture case with the nonconnected case. While not in the conventional displacement model of water injection, the current oil-­production rates would be unattainable without this secondary scheme.

Forecast Setup

By use of the history-matched data, nine different forecast scenarios were simulated for 50 years.

  1. By use of the history-matched pilot area, a model was run for an additional 50 years with well-operating constraints provided by the operator.
  2. Primary depletion of a four-well-per-section (wps) model.
  3. Waterflooding of a four-wps model.
  4. Primary depletion of an eight-wps model.
  5. Waterflooding of an eight-wps model.
  6. Primary depletion of a 10-wps model.
  7. Waterflooding of a 10-wps model.
  8. Primary depletion of a 16-wps model.
  9. Waterflooding of a 16-wps model.

Forecast results are discussed in the complete paper.

Conclusions

In this study, a work flow is provided for completing a history match on the Lower Shaunavon pilot area. The following conclusions are reached for the pilot area:

  • An acceptable overall history match was achieved for the Lower Shaunavon pilot area, consisting of 18 producing wells and with one well converting to a water injector.
  • Full historical injectivity could not be achieved unless the hydraulic-fracture stimulation broke through the shale layer separating the high-permeability streak from the Lower Shaunavon formation.
  • Because of the nature of the reservoir and proximity to the high-permeability layer, the primary benefit of the waterflooding scheme appears to be pressure maintenance.
  • Within the confines of this model, most of the injected water travels through the hydraulic fractures of the injection well into the high-permeability layer above the shale barrier because of preferential flow. The injected water propagates to surrounding production-well hydraulic fractures through the high-permeability layer while sweeping the layer.
  • The pilot area was forecast for 50 years after the history-matched time frame. The simulated pilot-area oil-recovery factor at the end of the history match is approximately 1.4%; the simulated pilot-area oil-recovery factor after 50 additional years of production is approximately 5.1%.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 171671, “Understanding Waterflood Response in Tight Oil Formations: A Case Study of the Lower Shaunavon,” by Adrian Thomas, SPE, Anjani Kumar, SPE, and Kenny Rodrigues, SPE, Computer Modelling Group, and Ryan Sinclair, SPE, Colin Lackie, Angela Galipeault, and Mike Blair, Crescent Point Energy, prepared for the 2014 SPE/CSUR Unconventional Resources Conference—Canada, Calgary, 30 September–2 October. The paper has not been peer reviewed.