Reservoir characterization

Tactics for Use of Diagnostic Fracture Injection Tests in Unconventional Reservoirs

To achieve optimal production from unconventional reservoirs, it is useful to determine the permeability, pore pressure, and state of stress of rock strata.

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Fig. 1—Typical DFIT pressure response.

To achieve optimal production from unconventional reservoirs, it is useful to determine the permeability, pore pressure, and state of stress of rock strata. An effective way to derive this information is to conduct in-situ pressure-transient tests. Because injecting fluid into or withdrawing fluid from the pore network of tight rock is difficult, diagnostic fracture injection tests (DFITs) have been used to create an analyzable pressure-decline response and to derive the minimum horizontal stress through fracture-closure identification.

Introduction

Well testing is the technique of establishing fluid flow in the reservoir by either producing from or injecting into a well and then changing or terminating the flow rate to create a transient event, usually by shutting in the well at the surface. The resulting wellbore-pressure response is then evaluated to derive reservoir properties, such as transmissibility and initial reservoir pressure.

Creating a hydraulic fracture bypasses wellbore damage and near-wellbore stress concentrations and connects the wellbore to a significant portion of the reservoir-layer thickness, enabling a representative investigation of reservoir properties.

A typical DFIT sequence is shown in Fig. 1 above.

Initially, the well is filled with water, with care taken to purge the fluid column of entrained air and gas.

  • A surface pump establishes an injection rate with water, and the wellbore fluid is compressed. The time of compression is a function of wellbore volume, injection rate, and breakdown pressure. In low-permeability reservoirs, little if any of the injected fluid flows into the reservoir during this time.
  • Eventually, formation-breakdown, or breakover, pressure is reached, signifying that a hydraulic fracture is being propagated into the reservoir rock.
  • Water injection at the surface is continued until wellhead pressure stabilizes.
  • Then, surface injection is stopped, resulting in an instantaneous shut-in pressure, which is the net of wellbore and near-wellbore friction pressures, from which net pressure at shut-in can eventually be determined.
  • The shut-in well pressure is then monitored for signs of fracture closure.
  • The after-closure period is evaluated for pseudolinear- and pseudoradial-flow signatures. Radial-flow solution methods are used to derive transmissibility and initial reservoir pressure. Linear flow also can be evaluated for reservoir pressure.

Test Planning and Strategies

Selecting Injection Rates and Volumes. For DFITs in low-permeability rock, minimizing fracture length is important to shorten the time to fracture closure and then to pseudoradial flow, the flow regime required to derive transmissibility and pore pressure.

Tactic. Minimizing the injection volume and rate will hasten fracture closure, reduce fracture length, and minimize residual fracture width at the onset of closure, also speeding the arrival of pseudoradial flow.

Shut-In Methods for Hastening Fracture Closure and Radial-Flow-Regime Development. The two primary shut-in techniques are surface shut-in and downhole shut-in.

With surface shut-in, the wellhead is isolated by closing the valve connecting it to the injection-pump lines; the entire wellbore volume is in communication with the perforations and formation. There are two methods to collect data: either through a surface/wellhead gauge or through a downhole (typically wireline-conveyed) gauge. The surface-gauge data will be valid only if pressure at the top of the wellhead or wireline lubricator (if applicable) is greater than zero. If the reservoir is subpressured, meaning that the pore pressure is less than the fluid pressure exerted by the wellbore hydrostatic column, the use of a surface gauge will be limited. Eventually the wellhead pressure will reduce to zero; in this case, a downhole gauge is useful in obtaining accurate bottomhole-pressure information.

For downhole shut-in, the well is isolated downhole with a bridge plug or other device. In comparing the two shut-in methods, the downhole shut-in will have a smaller wellbore volume than the surface shut-in. With subpressured reservoirs, downhole is the preferred shut-in method. As long as the downhole shut-in device is placed at a depth where the hydrostatic head is less than the reservoir pressure, then the only pressure-falloff mechanism will be depressurization, resulting in a much smaller wellbore-storage coefficient and afterflow contribution. The smaller the wellbore volume, the more rapidly depressurization will occur.

Tactic. Downhole shut-in is advantageous for all reservoirs. It is often a requirement in applications with subpressured reservoirs.

Vertical vs. Horizontal Wells. For many unconventional plays, reservoir development is based on multistage-fracture-stimulated horizontal wells. This presents an opportunity to perform a DFIT on the first-stage perforations/ports before fracture stimulation. It is possible to acquire additional information on the reservoir from these horizontal-well DFITs; however, they must be set up properly to acquire useful data results. In addition, there are advantages to planning vertical-well DFITs in these same reservoirs.

The following are horizontal-well considerations:

  • Usually, there is a limitation of one test interval per well.
  • There is little to no control in lithology selection.
  • With multiple perforation clusters, questions arise on the variability of the lithologies being tested and number of fractures being propagated. It is beneficial to conduct the DFIT through a single perforation cluster.
  • There is test-height uncertainty because of the inability to measure fracture-height growth.
  • Fracture-plane orientation is uncertain.
  • DFITs in horizontal wells are prone to complex hydraulic-fracture initiation, with longitudinal and transverse components. Consequently, the pressure-falloff response can be complicated.
  • Maintaining an overbalance pressure during the time between perforating and conducting the DFIT may be difficult.
  • Using pressure-activated toe valves can facilitate the DFIT.
  • Annular isolation may be lacking, sometimes by design (e.g., openhole completions with sleeves).
  • In openhole/sleeve applications, DFIT results are generally improved by restricting the potential flow area in the annulus. This is achieved by installing and activating openhole packers on each side and within several feet of the sleeve ports.

The following are vertical-well considerations:

  • Multiple potential pay targets can be evaluated to compare stress and permeability characteristics.
  • Specific layers/lithologies can be targeted.
  • Bounding rock layers can be evaluated to assess fracture-height-growth potential throughout the gross interval.
  • Fracture geometry is less complex and more certain compared with that of horizontal wells, with a lengthier wellbore-to-primary-fracture connection and less near-wellbore flow-path tortuosity.
  • Fracture-height determination is possible, though difficult.

Tactic. For horizontal-well DFITs, understand and plan to deal with the issues. Do not limit well selection to horizontal wells only. The significant advantages of DFITs in vertical wells mean they should be considered as part of the well-planning and data-collection process.

Multiple-Interval Projects. In vertical wells, multiple intervals can be tested to evaluate a variety of pay zones and the overburden/underburden. The DFITs can be conducted in series or simultaneously.

Tactic. Multi-interval tests with retrievable bridge plugs significantly reduce the time required for acquiring results from multiple low-permeability intervals that require long shut-in times for achieving pseudoradial flow and sometimes even fracture closure.

Understanding Test Height. The height of the test interval is often uncertain. The following are methods to obtain a better understanding of the thickness of the interval under investigation.

Fracture Modeling. Fracture modeling can be used to estimate fracture-height growth and as an aid in selecting test height for improved characterization of reservoir permeability.

Radioactive Tracers. Adding radioactive tracers to the DFIT injection water, and then performing a gamma ray spectroscopy survey by use of slickline or wireline at the conclusion of the testing, has been used to estimate test height and confirm fracture-modeling results.

Temperature Surveys. Temperature surveys performed in conjunction with DFITs can be useful for estimating test height and confirming fracture-modeling results.

Hydraulic-Fracture Modeling

Hydraulic-fracture modeling is applied primarily in planning and optimizing large-scale hydraulic-fracture treatments. It is rarely considered as an aid in designing small-scale injection treatments such as DFITs. However, this philosophy has changed recently. Because DFIT results have had an effect on well-development planning in several unconventional plays, hydraulic-fracture modeling of the DFIT process is now being used to provide insight into fracture-propagation characteristics of reservoir, overburden, and underburden intervals before, during, and after test execution.

Hydraulic-fracture modeling first starts with the evaluation of openhole and cased-hole logs. Analyzing log data will lead to characterization of rock properties and fluid saturations of the reservoir and bounding lithologic intervals, leading to the development of a geologic/stress model for the hydraulic-fracture model.

When the formations of interest are identified, then preliminary perforation height, injection rate, and injection volumes can be selected.

Procedure/Execution

There are operational considerations to address to ensure that the well is properly set up and conditioned for a DFIT.

Evaluating Cement-Bond Quality. Final perforation location should be contingent on cement-bond quality. It will be necessary to plan for alternative perforation intervals as a contingency in case the selected interval does not have adequate cement-bond quality.

Preparation for Low Ambient Temperature. Frigid weather can result in ice in wellhead and injection lines and inaccurate surface-pressure-gauge readings.

Well Circulation. Before the DFIT, it is common for the well to be circulated with water as part of hole-cleanout and well-conditioning operations. In these cases, it is best to wait at least 24 hours before starting DFIT injection to ensure that temperatures in the well return to the geothermal gradient.

Air/Gas Purging. All air or gas needs to be purged to ensure that the wellbore and peripherals, such as the wireline lubricator, are completely filled with water/test liquid.

Pressure Testing. Generally, the pressure test for the maximum operating pressure for the wellbore and wellhead doubles for the pressure test of the DFIT. It is advisable to conduct a second pressure test at a reduced pressure, if applicable, for evaluation of the rate of pressure falloff at the expected DFIT shut-in pressure condition.

Wellhead Management. For DFITs, separate pressure gauges are used for the wellhead and the injection pump. Both data sets should be available in order to evaluate the validity of the test data.

Overbalanced Perforating. Overbalanced perforating is recommended for preventing gas influx into the wellbore before the DFIT injection.

Dynamic Downhole Shut-In. A best practice usually is to shut in the well dynamically to avoid changing the wellbore-storage coefficient during the shut-in period.

DFIT Termination, Surface Shut-In. After shutting in the well for the required time, each surface shut-in test should be concluded with a short bleedback of wellbore fluid to check the fluid content and check for the presence of gas at the top of the wellhead.

Spotting Hydrochloric Acid To Facilitate Breakdown. Occasionally, the maximum allowable surface pressure is reached during DFIT injection without achieving breakdown and a stable injection rate. Hydrochloric acid is effective in lowering breakdown pressure.

Conclusion

The guiding principles for implementing DFIT tactics are

  • Understanding the fundamentals of project planning
  • Understanding the fundamentals of test concepts
  • Having available the necessary reference points/data
  • Preparing and executing with attention to detail
  • Organizing data and recognizing patterns/anomalies through multiple tests
  • Letting the data lead the analysis

With continued tests and analysis, the data may corroborate past findings or put into question prior conclusions. With an open mind, DFIT tactics in unconventional reservoirs can be open to revision and modification; thus, understanding of various phenomena and anomalies continues to be refined.
This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 163863, “Diagnostic-Fracture-Injection-Testing Tactics in Unconventional Reservoirs,” by D.D. Cramer, SPE, and D.H. Nguyen, SPE, ConocoPhillips, prepared for the 2013 SPE Hydraulic Fracturing Technology Conference, The Woodlands, Texas, USA, 4–6 February. The paper has not been peer reviewed.