Layer | Fill | Outline |
---|
Map layers
Theme | Visible | Selectable | Appearance | Zoom Range (now: 0) |
---|
Fill | Stroke |
---|---|
Collaborating Authors
Improvements in Downhole Fluid Identification by Combining High Resolution Fluid Density Sensor Measurements and a New Processing Method: Cases from a Saudi Aramco Field
Palmer, Richard (Saudi Aramco) | Silva, Andre (Saudi Aramco) | Saghiyyah, George (Saudi Aramco) | Rourke, Marvin (Halliburton ) | Engelman, Bob (Halliburton) | van Zuilekom, Tony (Halliburton) | Proett, Mark (Halliburton)
Abstract Accurate chemical and physical properties of hydrocarbon and formation water are required for efficient reservoir and production management. During exploration and field development, a sample of formation fluids is frequently required. One method to obtain reservoir fluid samples is with a pumpout wireline formation tester (PWFT) in which the objective of sampling is to collect a representative fluid sample with minimum rig time. Sampling mixed phases or immiscible fluids has been a long standing challenge for fluid identification using PWFTs. The mixing of fluids that are flowing inside the tool increases sensor noise, making the interpretation of fluid type and amount of contamination difficult, if not impossible. Consequently, these noisy sensor readings are often ignored and attributed to fluid transitions during of sampling. This erratic behavior has been observed with most sensors, including resistivity and optical sensors. With the introduction of a new high resolution fluid density sensor and improved data handling techniques, it is now possible to identify these mixed fluid flow regimes of hydrocarbon and water more precisely. The new fluid density sensor monitors the frequency change of a vibrating tube that is filled with the fluid sample quickly and reliably. The high accuracy of this technique enables the determination of additional fluid properties, such as density, water salinity, and fluid compressibility. Furthermore, the new processing methods provide a clearer understanding of the flow behavior, enabling more accurate estimates of fluid contamination. Data from the tool can also be used to observe changes in fluid properties over depth intervals and to aid in the identification of fluid interfaces and compartments. Introduction The traditional method for fluid identification before the advent of PWFT with downhole fluid sensors used gradient analysis of pressure surveys. Although gradient analysis of PWFT pressure surveys is a well established method to evaluate in-situ fluid density, this method presents accuracy challenges. In addition to the accuracy of the pressure measurement, the depth accuracy must be considered and, when the producing layers are less than 20 ft, accurate gradients may not be possible (Phelps et al., 1984; Kabir and Pop, 2006). Also, when a layer contains more than one fluid type (i.e., oil and water transitions), capillary effects can influence the pressures and gradients. Another main factor that limits the accuracy of gradient analysis is formations with low permeabilities or mobilities (i.e., < 10 mD/cP).
- North America > United States (1.00)
- Europe (1.00)
- Asia > Middle East > Saudi Arabia (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > Asia Government > Middle East Government > Saudi Arabia Government (0.88)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Fluid modeling, equations of state (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Downhole and wellsite flow metering (1.00)
Advances in Sampling Methods Using a New Dual Port Straddle Packer Pumpout Tester in One of Saudi Aramco's Oil Fields
Silva, Andre (Saudi Aramco) | Palmer, Richard (Saudi Aramco) | Hajari, A.A. (Saudi Aramco) | van Zuilekom, Tony (Halliburton) | Engelman, Bob (Halliburton) | Rabbat, Ashraf (Halliburton)
Abstract Collecting high quality fluid samples with a pumpout wireline formation tester (PWFT) configured with a conventional probe in carbonate reservoirs is often a challenging operation. Straddle packers are far more suitable than probes for sampling low permeability, heterogeneous carbonate reservoirs. A large volume of whole mud is trapped between the packers when they are initially inflated. The mud must be partially voided before formation fluid begins entering the packed-off interval. Before pumping begins, the near borehole region is occupied with contamination as a result of drilling overbalance and mud filtrate invasion. Uncontaminated reservoir fluid begins entering the packed-off interval after an adequate volume of contaminated fluid has been removed. Water-based mud filtrate (WBMF) and crude oil tend to separate in the packed-off interval as a result of fluid density difference and immiscibility. Moreover, a water oil interface forms at some level within the packed-off interval. As pumping continues, this oil/water fluid contact levels off at the inlet port, and both water and oil will continue to flow through the inlet throughout the sampling process. This complicates fluid identification and makes obtaining a low contamination single phase sample problematic. By taking advantage of a dual inlet port straddle packer and a new fluid density sensor, it is possible to verify the occurrence of fluid segregation within the packed-off interval. The new dual port straddle packer design enables independent opening and closing of the top and bottom ports to observe fluid segregation. By sequencing these port valves and sample chamber valves, we demonstrate how low contamination samples are obtained faster than with a single port system. This paper provides a description of the new sampling techniques based on samples collected in a Saudi Aramco oil field, as well as examples that show the fluid segregation effect between the packers. It compares the pumping times of a straddle packer vs. an oval pad pumping in similar reservoir conditions. This paper also describes the process used to collect both water and oil samples and the challenges associated with sampling at the oil/water contact (OWC). It also presents the lab results that verify the low contamination level samples obtained by using the new methods.
- North America > United States (1.00)
- Asia > Middle East > Saudi Arabia (1.00)
- Government > Regional Government > Asia Government > Middle East Government > Saudi Arabia Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)
Abstract Timely and detailed evaluation of in-situ hydrocarbon flow properties such as oil density and viscosity is critical for successful development of heavy oil reservoirs. The prediction of fluid properties requires comprehensive integration of advanced downhole measurements such as nuclear magnetic resonance (NMR) logging, formation pressure, and mobility measurements, as well as fluid sampling. The reservoir rock presented in this paper is an unconsolidated Miocene formation comprising complex lithologies including clastics and carbonates. The reservoir fluids are hydrocarbons with significant spatial variations in viscosity ranging from (60-300 cP) to fully solid (tar). Well testing and downhole fluid sampling in this formation are hindered by low oil mobility, unconsolidated formation that generates sand production, emulsion generation, and very low formation pressure. We present a two-pronged log evaluation workflow to identify sweet spots and to predict fluid properties within the zones of interest. First, the presence of "missing NMR porosity" and "excess bound fluid" is estimated by comparing the NMR total and bound fluid porosity with the conventional total porosity and uninvaded water-filled porosity logs, respectively. Secondly, two-dimensional NMR diffusivity vs. T2 NMR analysis is performed in prospective zones where lighter and, possibly, producible hydrocarbons are detected. The separation of oil and water signals provides a resistivity-independent estimation of the shallow water saturation. Additionally, we correlated the position of the NMR oil signal with oil-sample viscosity values. The readily available log-based viscosity greatly improves the efficiency of the formation and well-testing job. We successfully sampled high viscosity hydrocarbon fluids by utilizing either oval pad or straddle packer. The customized tool designed for sampling aided gravitational segregation of clean hydrocarbons from the water-based mud filtrate and emulsion; and therefore providing representative reservoir fluid samples based on downhole fluid analyzers.
- North America > United States (1.00)
- Asia > Middle East > Saudi Arabia (0.69)
Abstract In wireline formation testing and sampling, a difficult and long standing challenge is the differentiation between mud filtrate and formation fluids, especially in oil-based mud (OBM) (diesel/water mixture) and multiphase formation fluids (oil/formation water) environments. This challenge can cause ambiguities during the interpretation of downhole fluid properties and determination of the contamination levels before sampling. Often, during the sampling process, fluid mixing increases fluid property sensor noise and causes difficulties with accurate fluid identification and contamination levels. Consequently, noisy sensor readings are attributed to the transitional phase of sampling and pertinent information is ignored. This paper presents several examples where fluid mixing has occurred. A high-resolution volumetric densitometer is used to accurately identify fluid properties. It monitors the change of frequency of a vibrating tube immersed in the fluid sample. Because of the high accuracy of this technique, it is also possible to determine additional fluid properties, such as density, water salinity, and fluid compressibility. Furthermore, new processing methods are illustrated, which provide a clearer understanding of flow behavior and allow more accurate estimates of fluid contamination. The examples are verified using fluid volumetrically maintained at the reservoir pressure and temperature (PVT) lab results comparing the downhole real-time fluid property measurements and interpretation with the actual fluid samples recovered. Introduction In many cases, when sampling with a pumpout wireline formation testing (PWFT), multiphase flow conditions are encountered and are very difficult to interpret. This normally occurs in most cases when sampling oil in water-based mud (WBM) or water in OBM; yet, the most challenging case involves sampling in a transition zone (formation oil/water) in an OBM environment where the invading mud filtrate fluid varies in mixture between the diesel base and water base ratio in the OBM system used. Depending on the fluid identification sensor type of measurement and other parameters such as sensor sensitivity, nature of the measurement, sensor sampling rate, and the volume of fluid that the sensor detects, multi-phase fluid flow can be characterized from the beginning of the cleanout process till clean representative formation fluid samples can be captured. Fluid identification sensors by themselves cannot solve the complexity of multiphase formation fluid in OBM environments. Invasion modeling and contamination prediction models must be used along the downhole fluid identification (ID) sensors to assess the process of the cleanout from the filtrate to the clean native formation fluids (Eyuboglu et al. 2011). Moreover, the probe type to be used during sampling also has great implication regarding the nature of the flow regime and can be used for solving fluid typing during the pumpout process, knowing the flow regime it follows and or using phase segregation to identify clean fluids and ratios.
- Asia > Middle East > Saudi Arabia (1.00)
- North America > United States (0.95)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Multiphase flow (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
- (2 more...)
Abstract Water sampling in Saudi Arabia has been a priority due to the importance it can play in reserve estimates and completion decisions. To accurately estimate the oil and water saturations in a producing zone it is essential to know the water chemistry and accurately estimate the water conductivity. What can make this particularly challenging is when a well is drilled with water-based mud (WBM). In this case the filtrate is miscible with the formation water making it difficult to determine when to sample with a pumpout wireline formation tester (PWFT). Traditionally, a resistivity sensor is used but in cases where the salt or calcium chloride concentrations are high the resistivity can be relatively insensitive to the difference between WBM filtrate and formation water. Other methods, such as optical, have limitations as well. Furthermore, it is desirable to obtain the formation sample near the transition zone which can cause oil and water to be mixed while sampling. To meet these challenges new methods for sampling and fluid identification are employed. Using a new dual-inflatable Straddle Packer Section (SPS) it is possible to separate the oil and water phases while sampling. Gravity can separate the oil and water phases within the SPS sealed interval, and by using two spaced inlet ports it is possible to obtain distinct segregated water and oil samples. In the sampling process the fluid phases can be mixed which can complicate the fluid identification. By using a new high resolution density sensor this mixing process can be more clearly understood. Fluid segregation within the straddle packer interval and PWFT pump can be verified and methods of obtaining separate oil and water samples are shown using field case studies. The new density sensor is based on a vibrating tube where the fluid passing the tube changes the natural frequency of vibration. Because of its high accuracy it is possible to determine additional fluid properties such as salinity and the difference between the WBM filtrate and the formation water. Introduction Identifying the transition zone interval is critical for estimating reserves, effective completion design and reducing water production. In a transition zone oil and water can be produced from the interval simultaneously. This occurs when there is movable oil and water in the pore spaces. A transition zone is believed to be created by capillary forces which can account for the fluid distribution in a homogeneous zone. Transition zones dominated by capillary forces normally occur in low permeability reservoirs (Elshahawi H., et al 1999). In higher permeability zones the oil-water transition can be very abrupt. In complex, highly laminated and heterogeneous zones water can be trapped as the oil and water migrate through an interval over geologic time. In these conditions it can be very difficult to locate the fluid transition from logs or pressure surveys. Sampling from selected intervals has been used to identify and measure fluid properties in a transition zone.
- Asia > Middle East > Saudi Arabia (0.49)
- North America > United States > Texas (0.46)