Formation Testing While Drilling (FTWD) has a broad interest in all the different disciplines involved in drilling and evaluating the well. For the drilling engineer and the geologist, a number of different approaches to the problem of acquiring formation-pressure data while drilling have been tried. Real-time formation-pressure data will, at a minimum, allow more-frequent calibration of pressure models. For the reservoir engineer, it opens the possibility of "barosteering"; where there is doubt in mature fields about whether a compartment has been drained, immediate measurements can be taken, and a decision can be reached about whether to geostop or geosteer for a more-promising compartment. It allows immediate testing to verify whether geological barriers are sealing, and it opens the possibility of pressure profiling to identify (from gradient information) types of fluids present and contact points.
Selecting the best tool for a specific type of reservoir condition is a crucial part of a fluid sampling job. Moreover, uncertainty in sample quality increases when the fluid phases are miscible. On a recent logging job, a formation tester was used to acquire water samples across a zone drilled with water-base mud (WBM). We examine the performance of several probe configurations (both existing and prototype) under equivalent reservoir conditions to quantify and optimize filtrate cleanup efficiency. The study is carried out using a compositional simulator for a water-saturated reservoir invaded with blue-dye tracer included in WBM filtrate.
History matching of field measurements allows the calibration of the model for further modification to account for a variety of reservoir conditions. Complex tracer dynamics of a blue-dye WBM invading a water-saturated formation and fluid pumpout are accurately and expediently modeled using a flexible numerical algorithm to account for different probe types and tool configurations. Under normal operating conditions, the chosen formation tester would have taken around one hour to clean the filtrate contamination to a target value of 5%. On the other hand, the best choice was the Focused Elliptical Probe, for which fluid cleanup would take less than 40 minutes. Additionally, a different tool configuration with a combination of multiple probe geometries spaced radially around the tool would provide faster cleanup times of only 32 minutes, thereby saving rig time.
We rank eight formation testing tools designs under equivalent reservoir conditions. The examples highlight the importance of probe geometry and configurations together with reliable and expedient numerical modeling during the pre-job phase to reduce cleanup time in anticipation of complex reservoir conditions. Furthermore, numerical simulations compare the fluid cleanup efficiency for various commercial formation-testing probes together with innovative probe designs that could potentially lead to a new tool or probe development. Perfecting both probe geometry and fluid pumping schedule is the most important output of our study.
This course is designed for petro physics and reservoir engineers who are involved in formation sampling and testing. To learn about reservoir characterisation using formation testers, to be able to interpret pressure and fluid properties, and to design a successful sampling and testing operation. This class is designed for geophysicists, reservoir engineers and any engineers involved or interested in wireline formation sampling and testing including petro physical engineers, production engineers and testing engineers. There are no special requirements for this course. It is recommended for participants to bring their own examples to contribute to course discussions.
This paper presents a novel methodology to successfully maximize sampling and scanning of formation fluids using formation mapping-while-drilling (FMWD) technology in real time when drilling poorly consolidated formations. The methodology, based on a solid workflow built on experience garnered and captured in various operations and geomechanical studies performed around the world, can be applied in a wide range of wellbore geometries and formation types.
The methodology is based on four processes: 1. Predict, assess, and confirm potential fines migration and formation collapse during FMWD operations. The analysis is based on processing and interpreting existing geomechanical properties from offset wells and real-time newly acquired sonic and/or density data. 2. Design FMWD operations such that formation sanding is prevented, and formation integrity is maintained. 3. Prevent mobilized fines from entering the FMWD tool if partial formation collapsing occurs. 4. Focus the workflow on reducing the negative impact solids will have on the flowline, pump out, and optical analyzers if fines enter the tool.
The paper contains two case studies in which the methodology workflow resulted in successful sampling and real-time downhole fluid analysis of formations with very limited diagenesis and a history of sanding and collapsing during formation testing-while-drilling operations. These two case studies show how assessing offset wells during the planning phase and applying this workflow while evaluating logging while drilling (LWD) petrophysical data in real-time provide a quick insight into how a formation will respond during pump out. The results define station depth selection, timing of the operation with respect to wellbore exposure time, and pump out rate strategy. The application of fixed-rate pump out or intelligent pump out with a fixed differential can then be applied based on the real-time indicators. Specific screen sizes are selected in advance, which limit ingress of fines into the sampling tool. In both case studies, the operating company's objectives were met. An additional case study is presented in which the risk of sanding was not perceived, and no qualification of un-consolidation had taken place, ultimately resulting in formation breakdown in the sampling phase, mobilization of fines, and plugging of the tool; thus, highlighting the value of the novel methodology.
The innovation of this workflow is its holistic approach to sampling while drilling in unconsolidated formations, extensively covering both job planning and execution phases. Additionally, the workflow allows for optimizing tool configuration, and by risk identification, suggests a variety of measures to eliminate or mitigate the impact of partial formation collapse. This workflow extends the application of fluid mapping and sampling while drilling into operational environments, which were previously considered highly unsuitable for this technology.
Padhy, Girija Shankar (Kuwait Oil Company) | Kasaraneni, Pruthvi Raj (Kuwait Oil Company) | Al-Rashidi, Tahani (Kuwait Oil Company) | Tagarieva, Larisa (Weatherford Oil Tool Middle East Ltd) | Abba, Abdessalem (Weatherford Oil Tool Middle East Ltd)
Carbonate Reservoir characteristics and fluid properties can vary among multiple layers within the same stratigraphic unit. The objective of this case study is to emphasize the added values of integrating the data from a newly introduced formation testing technology along with open hole logs and core data to enhance the understanding of the Minagish Ooilte reservoir permeability distribution and fluid typing.
The methodology implies the first time application of the newly introduced formation testing techology external mounted quartz pressure gauge and fluid typing sensors (density, viscosity, resistivity, capacitance, pressure and temperature), which could minimize reservoir fluid samples contamination and later validated by comparison to laboratory analysis results. The fluid sampling operation was conducted in different reservoir units with varying mobility values where the tested zones were selected based on the pressure pretests done prior to the sampling deployment. The success criteria to evaluate the pressure measurements capability of the new techgnology was met as set by the operator to have accuracy within 0.1psi range for two build-up in pretest at the same point. The data was integrated with open hole logs and laboratory measurements to provide a comprehensive formation evaluation and conclusive reservoir characterization after validation of the permeability.
Heterogeniety in permeability measured/captured through RFT-tool was helpful to understand the reservoir flow capacity at the well location and subsequently select the right perforation intervals. Multiple fluid samples collected during this job aided in understanding the compositional variation with depth in the reservoir. Conjoining fluid variation with flow capacity of the reservoir was immensely useful to understand the true oil potential of the well and eventually select right production allowables. Production performance and productivity of the resulting well obtained after completing in the appropriate interval is better than other wells in the near vicinity.
The high well performance and productivity reflect the value of the information provided by the novel formation testing technology sonde helped, as it achieve the well objectives, design the appropriate completion and most importantly resolve many Minagish Oolite reservoir characterization uncertainties in a timely efficient operation.
Over the past two decades, formation testing has emerged as one of the most critical reservoir evaluation activities in petroleum exploration and production. As a result of increased drilling and testing costs in deep water, high-pressure, high-temperature, environmentally sensitive and other frontier areas, modern formation testing has become the primary—often only—source of information on fluid properties. Additionally it has provided insights into reservoir architecture issues that were previously the sole territory of conventional well testing. Attendees of this course will gain a good understanding of the state-of-the-art in formation testing and its changing role, vis-à-vis other disciplines. The fundamental applications and interpretations of formation testing and highlights of the advances made over the last decade will be reviewed.
Acquisition of fluid samples using wireline-formation testers (WFTs) is an integral part of reservoir evaluation and fluid characterization. Recent developments in formation-tester hardware have enabled wireline-based fluid sampling in a wide range of downhole conditions. However, accurate quantification of oil-based-mud (OBM) filtrate contamination using data from downhole-fluid-analysis (DFA) sensors alone remains challenging, especially in difficult sampling environments and for advanced sampling tools that have complex inflow geometries and active guarding of filtrate flows. Such tools and conditions lead to contamination behaviors that do not follow simple power-law models that are commonly assumed in OBM-contamination-monitoring (OCM) algorithms.
In this paper, we introduce a new OCM algorithm derived from an inversion of DFA data using a full 3D numerical flow model of the contamination-cleanup process. Using formation and fluid properties and operational tool settings, the model predicts the evolution of filtrate contamination as a function of time and pumped volume, and can thus be used to forward model the DFA sensor responses. Sensor data are then inverted in real time to provide contamination predictions. Real-time computation is enabled through fast, high-fidelity proxy models for the cleanup process. The proxy models are trained on and thoroughly vetted against a large number of full-scale numerical simulations. Compared with existing algorithms, the new OCM method is now applicable for all types of sampling hardware and a wider set of operating conditions. By directly relying on a model of the cleanup process, the physical properties of the formation and fluids (such as porosity, permeability, viscosity, and depth of filtrate invasion) are estimated during the inversion, thus providing additional valuable information for formation evaluation.
The new method is demonstrated by practical application in both synthetic and field examples of oil sampling in OBM. The synthetic examples demonstrate the robustness of the algorithm and show that the true formation and fluid properties can be recovered from noise-corrupted sensor data. The field example presented demonstrates that contamination predictions are in good agreement with results from laboratory analysis, and the inverted formation properties are consistent with estimates derived from openhole logs and pressure measurements.