The risks in unconventional field development are numerous, especially in the current economic climate. The biggest hindrance to resourceful field development is time. It takes time to wait for IP data to indicate which was the most successful and efficient completion planning strategy. And during that wait time, new wells are being planned and completed based merely on hypotheses about how much production to expect from the recently completed wells.
Advanced completions evaluation services help evaluate a treated reservoir’s permeability enhancement and reservoir drainage progression and eliminate the wait time for calibrated production forecasts. Operators in North America are currently using these advanced techniques to predict production for wells that have been completed but not yet produced. The production forecast provides production estimates two to three weeks after completion and without using well intervention methods such as production logging.
Operators use these advanced completions evaluation services to map future reservoir drainage patterns around each completed well and control depletion timing among wells with competing drainage pressures. No matter the current industry circumstances, E&P companies are challenged to drain a given area of reservoir with the minimum number of wells necessary or, if the need for resources was urgent, in the shortest time possible.
These drainage maps (Figure 1) are being used to determine when and how much reservoir will be drained by each well, offering a means to control the financial expenditure based on the determined ideal timing to deplete a given area of reservoir.
The proprietary workflow for determining a well’s future reservoir drainage pattern and production profile is based on the information gathered during microseismic monitoring. Using enhanced analysis of the microseismic data, the hydraulic fracturing results can be translated into deterministic rankings showing how much the treatment improved the reservoir’s permeability (Figure 2).
Instead of using the typical statistical modeling techniques, the permeability ratings are extrapolated from the observed microseismic data, inherently capturing the unique effects the treatment had on the reservoir, including proppant distribution throughout the fracture network.
The deterministic calculations of the reservoir’s permeability enhancement enable a reservoir simulation to accurately predict the productivity of the treated well on a detailed level, ranking future productivity for each stage within a few weeks of completion. Operators are using these productivity rankings for quick evaluation of their completion strategies, eliminating the typical time gathering of six to 12 months of actual production data before being able to confidently evaluate completion success.
These techniques have advanced microseismic completions evaluation beyond a simple picture of a well’s stimulated reservoir volume by translating the data into detailed production results.
The typical statistical modeling approach to production forecasting fails to offer reliable predictions of detailed, specific production. Conversely, the predictions that use advanced completions evaluation techniques are calculated from the deterministic results of the proprietary permeability workflow.
Therefore, unlike most reservoir characterization techniques currently in use, these forecasts of production and reservoir depletion timing are not based on statistical models. The forecasts are developed from in situ microseismic data that represent the treated state of the reservoir, unique to each well.
Used in multiple basins across North America, these advanced completions evaluation techniques deterministically predict production for wells that have been completed but not yet produced. Figure 3 shows the results from a case study in the Woodford Shale where these advanced techniques were used to predict the production volumes for a well (Well B) using only microseismic data and another nearby well’s historical production data for calibration.
The prediction results matched closely with Well B’s actual production. The process requires microseismic and production data from one well, which are used to accurately predict future production and reservoir drainage for multiple nearby monitored wells. The results return absolute volumes for short- and long-term production and show the reservoir drainage pattern each well is expected to create over the entire time it is produced.
Based on the proven success of the production predictions, the operator now plans to employ the same enhanced analysis techniques in planning the remainder of the unconventional field. Productivity rankings will be used to evaluate and refine completion strategies, reservoir drainage maps will enable control of reservoir depletion, and drainage interference timing and production forecasts will allow the operator to control field planning based on financial goals and production demands.
E&P companies using these advanced completion evaluation services have been able to use the results to reduce their wait time for completion evaluation information by at least six months. They are able to obtain an accurate estimate of multiple wells’ expected reservoir drainage and production volumes before the wells have actually been put on production. This information allows asset teams to evaluate the success of their wells before production even begins.
With this advance information, additional wells can be planned using proven effective treatment methods. Optimal spacing can be determined based on the expected short- or long-term drainage patterns, depending upon the operator’s desired production timeline or economic thresholds. Plus, the immediate availability of production information enables completion optimization planning without waiting for all of the wells’ production data or expending resources on well intervention techniques.
Having an estimate of expected reservoir drainage and production volumes so early on in a field development project makes the difference between blind field planning and data-driven field planning. With these advanced techniques, an operator can decide whether to drill a new well to immediately access a particular reservoir area or wait for existing wells’ drainage patterns to eventually reach that same reservoir area in the long term, depending upon current commodity pricing and the urgency of producing the reserves. This confidence and flexibility helps operators develop profitable wells despite lower oil and natural gas prices.
How hydraulic fracturing and the case for driving carbon capture utilization and sequestration forward on the basis of EOR can help achieve a feasible energy transition.
Declining returns and growing demand for cleaner energy and sustainable products are impacting stakeholder trust in oil and gas companies.
Talos Energy, one of the U.S. Gulf of Mexico’s largest public independent producers, established plans for a 30% further reduction of its GHG emissions intensity by 2025 from the baseline levels established in 2020.