It is more effective to capture clean reservoir fluids as early as possible during drilling operations, and with the realization of formation-sampling-while-drilling (FSWD), this goal is fast becoming a reality. This paper summarizes one example from Saudi Aramco and shows the benefits of this evaluation procedure. Our experience in sampling oil bearing formations drilled with water-based mud, has seen that the data from these instruments, which are now able to withstand the rigors of the drilling environment, can be used in real-time to control the sampling process, capture high quality samples, and also place the well where required. In this case study, a tight carbonate reservoir was the objective with the oil column being near saturation pressure. Under these circumstances, the challenges presented to us while sampling, included maintaining low flow rates and potential three-phase conditions, due to unavoidable drawdown while minimizing the time on the wall. During sampling, pump efficiency was consistent with low-mobility formations, even with the various multiphase flow regimes encountered. Hydrocarbon breakthrough was significantly faster than historical wireline sampling performed in the same reservoir. FSWD greatly improves our costs by saving rig time. Also, FSWD was utilized to evaluate low-resistivity-pay zones and observe if they hold a movable water fraction. We see this as crucial for geosteering wells to prevent drilling through the zones with movable water, which will enhance the productivity index of the wells. As a first time experience of FSWD in tight zones, a valuable lesson came to light where additional real-time monitoring improvements can be made, including the need to improve real time data quality, to accurately determine clean-up fractions while sampling. Based on this experience, we have formulated operational guidelines for improving real-time data analysis and determining the most opportune time to sample during the drilling process.

Petrophysical workflows are primarily designed to process static data for traditional openhole logs (i.e., triple & quad combo) which can provide estimates of porosity, saturation, lithology and mineralogy. Dynamic data from core analysis can help to extend the log analysis for estimates of the rock’s dynamic properties such as permeability. However, there is normally a high degree of uncertainty in these estimates and formation testing and sampling (FTS) data is often required for reservoir condition calibration. The workflow for analyzing FTS data is highly specialized, and normally not performed by an operating petrophysicist, but by a specialist whose expertise covers FTS tools and applications, openhole logs, and reservoir dynamics. This paper bridges the gap between operational petrophysicists and FTS specialists by documenting standardized methods of FTS measurements and introducing an automated workflow for petrophysicists to conduct FTS jobs. This workflow begins with job planning, to data processing, decision making and recommendations. Unique characteristics and capabilities of this workflow are summarized below. The job planning methodologies are based on fundamental principles to determine how different tool technologies will perform in specific reservoir conditions. It will ensure that the most optimized selection of tools and modules are made for FTS operations. Measurement uncertainties and data qualification criteria are critical parts of the workflow. Expected uncertainties are compared to measured uncertainties to assess the results’ reliability. With test uncertainties, error bars are established for each measurement which are then incorporated into data processing such as gradient estimates. A quality grading algorithm is used to objectively provide a rating for each test based on the measurements. Exceptions for test anomalies are also handled and interpreted automatically. In real-time testing operations, automatic methods for objectively quantifying data quality and uncertainty are used for pressure, mobility, and fluid gradient analyses. Real-time decisions can then be made to either adjust pressure points or take fluid samples at critical locations to reduce uncertainty. Preliminary results of applying this workflow to automatically process test data and determine data quality more objectively, consistently, and efficiently are demonstrated using field examples.

Traditional approach relys on reservoir pressures to assess reservoir connectivity in low permeability formations. This paper will present a new approach of applying Reservoir Fluid Geodynamics (RFG) through Flory Huggins-Zuo (FHZ) equation of state (EOS) for asphaltene distributions to determine reservoir connectivity and fluid typing in undrilled locations. FHZ-EOS asphaltene gradient was constructed with data from downhole fluid samples in different wells covering two zones (A and B). The downhole fluid analysis (DFA) results were validated with laboratory analysis. The structural continuity of both zones across the study area in the field was validated using a wide range of geological data including conventional open-hole logs. The resulting FHZ-EOS model formed the basis for fluid typing, correlation and connectivity across layers. The DFA data was used in real time at different stages of formation fluid sampling cleanup to correlate the samples quality with the existing model. The DFA data used in real time in conjunction with the pre-built FHZ-EOS model, improved the sampling quality check process and confidence in the sample quality, especially in the presence of low gas oil ratio (GOR) fluids. This improvement in real time data quality helped to optimize the pumping time and reduce the number of samples in each reservoir since the confidence in the sample quality was high. The constructed asphaltene gradient from the FHZ-EOS model also confirm the hydrocarbon continuity both vertically and laterally in undrilled locations with the study area of the field. For each of the zones, the data analysis shows a clear and distinct asphaltene gradient with different asphaltene molecule sizes. This supports the presence of heavy oil / tar towards the deeper sections of the area of interest within the field. It also predicted the depths / location of the heavy oil / tar, which will assist in the field development plan and flow assurance.

Wireline formation testers (WFTs) are a major component of providing quantitative geomechanical information obtained through induced hydraulic fractures, commonly called (Micro-Frac). This type of information is used to infer critical data such as borehole stability studies, field stress mapping, stimulation planning, seal integrity tests, and other applications. Likewise, vertical interference testing (VIT) conducted with WFTs provides valuable information about flow barriers, zone connectivity, and quantitatively determine localized horizontal and vertical permeabilities. Both techniques are used over separate stations and different depths as it may involve different hardware in different trips in the wellbore. In this paper, a novel technique to combine both tests simultaneously using an optimized hardware configuration and interpretation will be demonstrated. Pressure tests data in low permeability reservoirs is commonly affected by "super-charging" fluid that leaks into the invaded zone from hydrostatic pressure and cannot quickly dissipate, thereby making it difficult to accurately obtain true formation pressure measurements. This, in turn, affects the VIT tests where the pressure response at the observation point is influenced by the supercharged pressure resulting in erroneous calculation of vertical permeability. By initiating a micro-fracture while monitoring its response, this provides a better estimate to reservoir pressure and improves VIT success in low permeability formation. The combination of a Micro-Frac and VIT test at the same depth provides unique information about the reservoir and may enhance the data quality on these stations. Not only the safety and cost are positively impacted in improving the operational efficiency. New methods and techniques can emerge from the utilization of this methodology and improve reservoir understanding and characterization. In fact, a feasibility test using this unique approach was conducted and validated in a carbonate reservoir. The results indicate that the created micro-fractures provide a means of dissipating the "super-charging" effect masking the true formation pressure and reduce the uncertainty in the calculated reservoir properties using the VIT data. This technique may be further developed to include, for future implementation, other sensors at different places and positions in the downhole modular tools in order to acquire more information that will bring novel insight on the tested reservoir zones.

Drillstem tests (DSTs) and mini-DSTs are established reservoir dynamic evaluation techniques used to gather pressure transient data. A DST is still the preferred option for field-scale evaluation because the depth of investigation (ri) in a mini-DST is generally limited to tens of feet. Based on recent technology advancements being deployed, a review of the parameters affecting ri analytically and numerically is essential as these values have significance on operational efficiency. The most recent analytical models have shown that the production rate has a major effect on ri estimates, and this paper will focus on the most recent innovations in both hardware and analytical models that can extend the mini-DST data. Specifically, in-depth comparisons of new analytical models with van Poolen and Kuchuk’s equations will be presented. The discussion will extend to key hardware components with focus on pumping rate and gauge resolution. Finally, the new approach will be validated using data from restricted locations, from a thick high-permeability sandstone, and from a thick low-permeability carbonate. The van Poolen equation shows that for a fixed buildup time, a formation tester rate of 10 bbl/d compared to a DST rate of 1,000 bbl/d would result in the same radius of investigation, given that the equation does not account for flow rate. Kuchuk’s equation and the new analytical models show that flow rate has a direct impact on detectable ri—the higher the flow rate, the higher the detectable ri. Pressure transient analysis (PTA) was used to illustrate the impact of flow rate and gauge resolution on data quality, particularly on the portion of the flow regime relevant for detectable boundaries. In addition, a PTA plot superimposing flow rates from measured downhole data is combined with an idealized gauge to help to determine the magnitude of the apparent gauge resolution and its impact on the detectable ri. Both the new and traditional radius of investigation equations show that data acquired with the new formation tester tool obtains a deeper depth of investigation due to excellent data quality. The results are compared to conventional formation testers with limited flow rate and lower gauge resolution. This paper presents a new approach with a rate-dependent radius of investigation, compared to traditional approaches of van Poolen and Kuchuk. The superior data quality from the new formation tool leads to a substantial improvement in estimated ri.