Abstract
To improve economics in stacked unconventional formations, operators need measurements of downhole fluid properties and mechanical stress. The fluid properties are usually acquired at the surface by collecting samples (oil and gas) at the primary separator. However, collecting a representative sample is a challenge in multi-frac wells landed on several reservoir zones. Rock and geomechanical properties are usually inferred from uncalibrated log data, core experimental work, or a single diagnostic fracture injection test (DFIT). Without this information, operators can make suboptimal decisions. This paper discusses a case study wherein a microfracture was created at a preselected point in the wellbore, which enabled downhole fluid sampling in an unconventional formation.
Combining reservoir, stimulation, and petrophysical expertise enabled the deployment of a new microfracturing and fluid sampling service from a wireline-conveyed tool. The industry-first combined downhole microfracture and pressurized fluid sampling in an unconventional reservoir was performed. This process enabled the acquisition of quality DFIT, depth-specific mechanical properties, and in-situ formation fluid samples.
Using conventional logging tools a predefined target was identified, the wireline conveyed formation tester was used to isolate a 3’ interval to create a microfracture. Accurate pumping fluid volumes and pressures were measured when performing the microfrature, then flowback was monitored to identify invaded from formation fluids minimizing the risk of collecting a contaminated sample.
Results confirmed that this new service can break down unconventional formations and drawdown on the formation to acquire in-situ fluid samples. Valuable completion information, including fracture initiation and extension pressure, fluid leakoff character, and estimates of kh/μ were also obtained.
Fluid samples from these ultra-tight formations were previously unobtainable from a formation tester. Using the tool to generate a microfracture makes it possible to collect in-situ fluid samples in a cost-effective timeframe. This capability leads to better drilling programs, surface facility design, reserve estimation, and stimulation decisions.
This technology represents a new integration of formation evaluation and engineering. It requires planning between drilling, stimulation, reservoir engineering, and formation evaluation staff. The tool provides fluid composition and micro-DFITs at multiple depths selected by engineers and geoscientists. Information at specific depths provides new opportunities for reservoir and stimulation modeling, petrophysical calibration, and reservoir mechanics. Because this information was previously largely unobtainable downhole, new opportunities are now available to better understand the interplay between geomechanics and fluid properties.
