Formation-Fluid Microsampling While Drilling Enables Complete Reservoir Characterization
The complete paper presents a technical discussion of a new microsampling technique for LWD and a corresponding wellsite technique to provide compositional interpretation, contamination assessment, reservoir-fluid compositional grading, and reservoir compartmentalization assessment.
Pressure/volume/temperature (PVT) phase behavior characterization and geochemical compositional analysis of petroleum samples play a crucial role in the determination of producible reserves and the best production strategy. Openhole samples are the most-valuable types of samples for PVT and geochemical analysis but are costly and limited to 10 to 20 samples. The complete paper presents a technical discussion of a new microsampling technique for logging while drilling (LWD) and a corresponding wellsite technique to provide compositional interpretation, contamination assessment, reservoir-fluid compositional grading, and reservoir compartmentalization assessment. This microscale approach enables fast analysis by using field or near-field deployment of the analytical tool. The results inform planning for wireline sample retrieval, if necessary.
The microsampler used in the downhole tool can collect reservoir fluid in small quantities suitable for compositional analysis. Because of its small size, the microsampler can gather multiple fluids at various reservoir depths, while PVT sampling requires larger volumes and has more constraints. However, when used in combination with conventional PVT-grade samples, the microsamples can provide significant chemical profiling. The 40-ml quantity provides the ability to collect many more samples than the conventional PVT sample size of 200 to 1,000 ml. Additionally, 40 ml provides more than enough of a sample for a complete chemical analysis using a liquid chromatograph or gas chromatograph coupled with either a mass spectrometer for biomarker analysis or a flame-ionization detector (FID) for a complete assay. Isotope analysis is also possible.
Recovery to surface of fluid samples collected at reservoir temperature and pressure allows for analysis with an automated gas chromatograph (GC) deployed in the field, providing reduced labor and rapid analysis. The unique injection chamber of the GC is designed with the injection port and valve configured to withstand pressure up to 5,000 psi, a tolerance approximately five times higher than that of standard GC injection valves. This allows for injection of the microsample with a solvent carrier as a single-phase fluid so that analysis can provide composition and fluid properties such as gas/oil ratio without a flash. The GC has two detectors, including an FID for hydrocarbon components and a thermal conductivity detector for inorganic gas components such as carbon dioxide, nitrogen, and hydrogen sulfide. The system can quantify hydrocarbon components from C1 to C36 and perform contamination studies of oil samples with drilling fluids.
According to the authors, the technique enables reservoir engineers to characterize a reservoir completely without limit to the number of acquired samples. They write that, in combination with conventional PVT samples, it is possible to extrapolate PVT properties to all pump-out stations and conduct a complete geochemical profile of the reservoir.
The complete paper presents detailed technical discussions of PVT phase behavior, geochemistry, and drilling fluid, and their role in fluid microsampling. The paper also addresses formation testing and sampling—including where, when, and how to sample—and sampling and analytical techniques.
Wellsite gas-chromatography discussion includes a detailed description, photo, and schematic of the customized, portable GC injection system used in the authors’ study (Fig. 1).
To determine the capability of the microsampling and GC system and to test the contamination deconvolution method, a detailed simulation mimicked a formation-tester sampling job with an LWD formation sampler. A typical LWD formation sampler can acquire approximately 10 samples from an openhole section. The mud system during a single section usually is relatively constant in liquid-portion composition. Therefore, filtrate invasion from the top of the section to the bottom of the section should conform to a single profile. The fluids within a single section will probably be of the same family, related through a common source rock, similar generation history, and similar migration history. However, the fluids accumulate over time within the reservoir compartments, and therefore, although of a similar base, will have distinct compositional features. To mimic this profile, a base oil was mixed with unrelated, trace petroleum-fluid samples from zero to 10 weight %.
Eleven dead oils with API gravity varying from 22° to 38° and one drilling fluid (filtrate) with hydrocarbon components ranging from C15 to C20 were chosen from the database for this purpose. Before mixing the experiment, gas-chromatography compositional analysis for all individual dead oils and filtrate was performed using the wellsite micro-GC with a standard injection system. A medium oil with API gravity of 30.6° (Fluid ID A1‑77) was selected as the base fluid for the experiment. Ten trace fluids (prefix B1-B10) were mixed with A1-77 with the targeted concentration range of 90 to 99% of Oil A and 1 to 10% of Oil B. The resultant family of oils is designed to mimic the variation of concentration that can be encountered in a typical formation-sampling run.
Fluids AB1 through AB10 ideally reproduce potential oil/oil mixing from different zones within the reservoir and represent reservoir fluid compositional and API variations observed in actual reservoir fluids, because of reservoir filling and compartmentalization. Filtrate C, representing drilling fluid, was added to each of the AB reservoir fluids targeting 5 to 15% contamination, with the actuals presented in a table. The level of contamination was chosen to evaluate how effectively low contamination can be determined with the proposed method.
After the ABC mixtures were created, compositional analysis was conducted using the wellsite micro-GC. The fluids were loaded into the microsampler injection system and injected at a pressure close to, but not exceeding, the valve injection limit of 5,000 psi. A backing pressure at the injection valve prevented flashing in the valuing lines before introduction into the injection port. The raw chromatograms were recorded for analysis.
The remainder of the technical discussion in the complete paper is devoted to multivariate curve resolution (MCR), end-member properties from equation of state and MCR, and reservoir continuity from MCR.
The primary purpose of microsampling in an LWD formation tester is to determine the quality of associated PVT samples, and whether a subsequent wireline sampling run is necessary. Another goal is determination of physical properties of the clean formation fluid to plan subsequent samples. If the microsample is acquired close in time to the PVT sample from the same flow line, the contamination levels in the microsample are assumed to be representative of the contamination levels in the PVT sample. Ruggedized gas chromatogram field equipment may be used with the MCR algorithm both to compute contamination in the associated PVT sample and to provide a cleaned chromatogram from which formation-fluid properties may be calculated by equation of state (EOS). These EOS calculated fluid properties may then be used for subsequent sample job planning. If the microsamples are not fit-for-purpose, it can be assumed that the PVT samples are not fit-for-purpose.
A tertiary purpose of LWD microsampling is to help ensure success of the subsequent wireline-sampling operation by determining when, where, and how to sample. Using the EOS and a subsequent analysis of a similarity-matching algorithm called k-nearest neighbor (KNN), recommendations for wireline sampling to accomplish this goal can be achieved. The sample properties derived by the EOS technique to the MCR-derived chromatogram are sufficient to calculate the properties of the formation fluid and identify any sampling concerns with respect to how best to sample. The KNN compartmentalization analysis shows where best to sample.
The current microsampling platform prototype has been validated. The sampler size can allow up to 100 microsamples to be acquired in a single sampling run. Because most geochemical techniques collectively can be analyzed with the entire contents of a single microsample, a larger set of microsamplers can be used to gather a dense representation of formation fluid from along the wellbore. This study provides a new technique for reservoir engineers to characterize a reservoir completely, without limit to the number of acquired samples.
This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 195806, “Formation-Fluid Microsampling While Drilling: A New PVT and Geomechanical Formation-Evaluation Technique,” by Julia Golovko, Christopher Jones, SPE, and Bin Dai, Halliburton, et al., prepared for the 2019 SPE Annual Technical Conference and Exhibition, Calgary, 30 September–2 October. The paper has not been peer reviewed.