Hadibeik, Hamid (Halliburton) | Azari, Mehdi (Halliburton) | Kalawina, Mahmoud (Halliburton) | Ramakrishna, Sandeep (Halliburton) | Eyuboglu, Sami (Halliburton) | Khan, Waqar (Halliburton) | Al-Rushaid, Mona (Kuwait Oil Company) | Al-Rashidi, Hamad (Kuwait Oil Company) | Ahmad, Munir (Kuwait Oil Company)
Reservoir relative permeability as a function of saturation is critical for assessing reservoir hydrocarbon recovery, selecting the well-completion method, and determining the production strategy. It is a key input to reservoir simulation for predicting lifetime production of a well. Estimation of relative permeability curves at reservoir conditions is also a crucial task for successful reservoir modeling and history matching of production data. The relative permeability data estimated from core analysis may cause concern regarding representativeness, and adjustments are typically necessary for successful production forecasting. This paper proposes a new method to obtain relative permeability curves with downhole pressure-transient analysis of mini-drillstem tests (mini-DSTs) and well-log-derived saturations.
The new approach was based on performing mini-DSTs in the free water, oil, and oil-water transition zones. Analyses of the mini-DST buildup tests provided absolute formation permeability, endpoints of relative permeability to both oil and water, and curvature of the relative permeability data. Additionally, porosity and resistivity logs were used to determine irreducible water, residual oil, and transition zone saturations. Combining all of these downhole measurements provided the relative permeability curves.
When multiphase fluids flow in a reservoir, the flow rate of each phase depends on the effective permeability of that phase (Alkafeef et al., 2016). Effective permeability is obtained from absolute permeability of a reservoir multiplied by the relative permeability. Although absolute permeability is a function of reservoir pore geometry and does not change with fluid type, relative permeability is a fluid-dependent parameter and mainly depends on fluid saturation, pore geometry, viscosity, and surface tension (Goda and Behrenbruch, 2004).
Azari, Mehdi (Halliburton) | Hadibeik, Hamid (Halliburton) | Eyuboglu, Sami (Halliburton) | Jambunathan, Venkat (Halliburton) | Khan, Waqar (Halliburton) | Ramakrishna, Sandeep (Halliburton) | Haack, Joshua (Halliburton) | Bargas, Connie (Cobalt International Energy) | Khan, Mashiur (Cobalt International Energy)
Deepwater turbidite reservoirs have always presented several reservoir characterization challenges. Determining the complex architecture of the sand bodies, correlating them across multiple wells in the structure, and defining the sedimentological facies to determine the reservoir vertical communication and boundaries are some challenges in these Gulf of Mexico (GOM) turbidites. Other formation-related challenges of turbidite reservoir exploration and development include understanding reservoir rock quality and compartmentalization, as well as the identification of fluids. Deepwater exploration and development require innovative, cost effective evaluation technologies—technologies that help manage ultradeep and high-pressure environments. Having a detailed description of reservoir properties, fluids characterization, and a determination of the reservoir connectivity are crucial for understanding the reservoir and optimizing the field development plan.
This study describes the wireline formation tester (WFT) operations performed in a harsh environment [ultradeepwater subsalt formation (> 32,000 ft) and high pressure (> 25,000 psi)] to obtain pressure data, establish gradients, evaluate vertical connectivity using vertical interference tests (VITs), check for compositional variation in different oil columns, and obtain clean formation fluid samples. Downhole fluid analysis was performed to help ensure the quality of formation samples and determine the fluid compositional analysis in real time during pumpout. To obtain high quality fluid samples while minimizing costs, an innovative technology—namely, a focused sampling probe—was used, eliminating the need for long pumpouts. Representative formation fluid samples were captured from three sample depths in approximately two hours per sample depth with minimum oil-based mud (OBM) contamination (< 5%).
All the available openhole log data were integrated to understand the reservoir before running the WFT. Optimizing pressure and sampling depths (most representative intervals) can help reduce uncertainty when determining the number of pressure and sample points in the reservoir. Formation mobility, near-wellbore skin damage, reservoir pressure, downhole compositional fluid analysis, and reservoir connectivity were evaluated in a unique and challenging environment. Reservoir connectivity results from formation testing show good alignment with the presence of fractures and other sedimentary features from borehole image data. A similar methodology can be extended to other deepwater turbidite reservoirs in the GOM.
Al-Rushaid, Mona (Kuwait Oil Company) | Al-Rashidi, Hamad (Kuwait Oil Company) | Ahmad, Munir (Kuwait Oil Company) | Hadibeik, Hamid (Halliburton) | Azari, Mehdi (Halliburton) | Khan, Waqar (Halliburton) | Eyuboglu, Sami (Halliburton) | Kalawina, Mahmoud (Halliburton) | Ramakrishna, Sandeep (Halliburton) | Quintero, Luis (Halliburton) | Vasquez, Rafael (Halliburton) | Angulo, Reinaldo (Halliburton)
Relative permeability curves were estimated with downhole pressure-transient analysis of mini-drillstem tests (mini-DSTs) and well-log-derived saturations. The relative permeability values in this sandstone reservoir were validated through history matching of production data in the oil-producing interval.
The new approach was based on performing mini- DSTs in the free-water, oil, and oil/water transition zones. Analyses of the mini-DST buildup tests provided absolute formation permeability, end point of relative permeability to both oil and water, and curvature of the relative permeability data. Additionally, resistivity, dielectric, and nuclear magnetic resonance (NMR) logs were used to determine irreducible water, residual oil, and transition zone saturations. Combining all of these downhole measurements provided the relative permeability curves.
The method was applied in a well with a 35-ft oil column. Because of high porosity (~33%) and permeability (> 1 Darcy), the transition zone was short (approximately 5 ft). Four mini-DSTs were performed successfully. First, a pressure buildup (PBU) test was analyzed in a free-water zone. This analysis provided the absolute formation permeability of 6.8 Darcy. The second PBU test was performed in the oil zone, with the oil permeability evaluated to be 4.4 Darcy. From openhole logs, the irreducible water saturation (Sw) was estimated to be 7%. The third mini-DST point was in the transition zone. A weighted average density approach was used to calculate the individual phase rates from the total measured rate during pumping out. Permeability to oil was determined to be 1.6 Darcy; whereas, the permeability to water was 60 millidarcy (md). The final point above the oil-water contact (OWC) provides oil and water permeability value estimates of 170 and 440 md, respectively. Based on the saturation and pressure measurement ranges, an uncertainty envelope was generated for the relative permeability curves. Finally, history matching of production data was performed with a multiphase flow simulation to validate the relative permeability results.
Relative permeability curves estimation at reservoir conditions is a key task for successful reservoir modeling and production data history matching. The relative permeability data estimated from core analysis might cause concern regarding representativeness, and adjustments are typically necessary for successful production forecasting. Therefore, this new method can be a step forward in terms of overcoming such challenges and estimating relative permeabilities.
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.
Physical fluid samples collected in situ provide evidence for verification of exploration prospects, optimization of formation evaluation and reservoir production. Downhole fluid analyzers (DFA) are developed essentially to ensure the quality of formation samples. Advanced DFA are emerging for more advanced fluid compositional analyses in situ, as well as for studying the effect of pressure on fluid physical and chemical properties, those typically determined in the laboratories. Laboratory tests such as PVT (pressure-volume-temperature) analysis are still used as reference in reservoir engineering, provided the sample tested is representative of formation fluid and also differences among different laboratories are minimized.
This study focuses on crude oil compositional analyses during pumpout with a wireline formation tester. It summarizes experience with the in-situ measurement of methane, ethane, propane, saturates, aromatics and GOR based on multivariate optical computing (MOC) conducted at over 200 pumpout stations in a total of 37 wells drilled with a variety of inclinations, bit sizes, drilling fluids in several oil and gas fields. The results and lessons learnt enhanced technology development including hardware improvements, capability expansion for new components, processing software upgrades and the foundation of a local center of excellence for operations and study support.
Examples of individual pumpout stations within the context of an integrated petrophysical analysis of wireline logs are presented to demonstrate data quality control and basic interpretation in oil and gas wells in the presence of water- and oil-based muds. The data are cross-validated by correlations with laboratory and other sensor data. Fine but consistent field-wide compositional variations suggest the possibility of new geological understanding and advanced reservoir fluid modeling from the newly acquired DFA data base.
This study demonstrates methods for automatically processing formation test data and integration with the open hole log data which enables improved job planning for the sampling stage. The results can be higher efficiencies with reduced rig time for very complex logging and sampling operations. The logging operation in this case study was challenging in that 11 different formations were penetrated in two 6-1/8” wellbores. Multiple objectives included the determination of formation fluids, establishing gradients, fluid contact points and capturing representative fluid samples. An additional factor increasing the complexity of these operations was the length of the investigation area, which was over 4000ft of measured depth long with 20° to 47° deviation. These borehole conditions presented operational concerns with the prospect of differential sticking due to extended pumpout times where straddle packers were required for high quality samples in low permeability sections. The formation evaluation process for both wells was divided into three runs: open hole logs, pressure testing and sampling. The first two runs were conveyed on wireline with the pressure testing run utilizing a dual probe module of the formation tester which established 142 pressure points without operational difficulties. The third run was drill pipe conveyed successfully with 36 pumpouts performed, 10 samples captured and 6 mini drill stem tests (DSTs) performed in the two wells. In one well the straddle packer was used 17 times in formations with a high degree of permeability variation. Normally straddle packers are limited to 10 sets, however, the case study shown in this paper was considered to be the most performed in the Middle East region which was unexpected considering the difficult conditions encountered.
Using a new method to objectively quantify the quality of the pressure data, point selection was optimized for generating gradients and fluid contacts. This qualitycontrolled data can then be used to select sample points, estimate the pumpout time for each point and optimize the tool configuration for sampling. The choice between an oval probe or straddle packer for each point can then be made, which can ultimately reduce the overall sampling operation time.
In this case study, the real-time logging operation data acquired was used to establish gradients, fluid contact points and sample points. This preliminary analysis was compared to quality-controlled data analysis. From this comparison of the real-time versus quality-controlled results, improvements could be identified. The lessons learned and quality process controls are documented in the paper along with recently developed real-time methods for evaluating test quality which enabled the data to be analyzed quickly and with confidence, enabling improved pumpout and sampling operation planning.
Proett, Mark (Aramco Services Company) | Musharfi, Nedhal (Halliburton Energy Services) | Mantilla, Andrés (ECOPETROL S.A.) | Meridji, Yacine (Halliburton Energy Services) | Gill, Harmohan (Halliburton Energy Services) | Aramco, Saudi (Halliburton Energy Services) | Eyuboglu, Sami (Halliburton Energy Services)
In the literature regarding wireline (WL) and logging-while-drilling (LWD) pressure testing analysis, theoretical transient models are promoted to evaluate the quality of pressure test points. However, in practice, other criteria are normally used to judge the test quality. Some are ad hoc, but there is a growing consensus that several convenient, simple, and effective real-time measurements are needed to evaluate the quality of the test points.
The primary measurements made now include the drawdown mobility (md/cp) and buildup stability (psi/min). Although these measurements can be effective independently, they are also a source of information that can be expanded upon to further analyze the data. For example, how does the pressure stability compare to what is expected considering the drawdown mobility? Rather than using an arbitrary cutoff stability of less than a given psi/min, the measured value could be compared to the spherical or radial buildup trends expected using the measured mobility. If the stability is greater or less than expected, that implies some irregularity in the testing. Noise in the pressure data caused by mud flow is particularly evident in LWD pressure testing and the standard deviation of the pressure data during the buildup is another consideration for test quality. The radius of investigation is another estimate that can be made using the drawdown/buildup times with the mobility estimate to quantify the testing effectiveness. Supercharging is a concern for pressure measurements when the pressure measured is influenced by mud filtrate invasion that has elevated the pressure at and near the wellbore. By including the amount of time that has elapsed since the interval was drilled, the supercharge potential can be determined to further evaluate the data points. These calculations can be made by using basic principles and will guide the analyst monitoring the test to determine the relative quality of the test points. In this way, the best quality test points are used in the analysis of fluid gradients or for integration into the petrophysical analysis.
With the recent advancement of directional drilling technology and the use of rotary steerable systems, more deviated and horizontal wells are being drilled and evaluated around the world and especially in Saudi Arabia. In these complex reservoirs, logging while drilling (LWD) wave propagation technology allows accurate geosteering and well placement. Such a technology often exhibits boundary related artifacts (horns) at formation boundaries between beds having different resistivities, particularly where the borehole penetrates formations at an angle. This makes resistivity interpretation difficult and creates a challenge for determining true formation resistivity that is essential for determining hydrocarbon saturation.
This paper presents a processing methodology for the elimination and reduction of horns and shoulder bed effects. Logs processed using this method are more accurate and easier to interpret. This new technique solves the forward and inverse problems using a simplified approach. The forward problem is solved using a fast analytical technique that generates synthetic logs. The inverse problem is solved using the forward problem solution iteratively and minimizing a cost function that measures the discrepancy between the generated synthetic logs and the field data in a Gauss-Newton fashion.
Data processing and inversion of examples from fields in Saudi Arabia are presented to illustrate the usefulness of this methodology. For the examples, the values of formation resistivity and distances to bed boundaries are obtained. These results indicate that the processing method provides a reliable technique for evaluating the true formation resistivity of LWD logs in deviated and in horizontal wells for both well placement and formation evaluation.
Geosteering is used to optimize the placement of wells in target formations; and accurate geosteering and well placement have been shown to enable dramatic increases in production. Among the variety of well placement techniques that are available, wave propagation resistivity is the one with the deepest sensitivity that also allows monitoring of the formation profile around the borehole.
Hadibeik, Hamid (UT Austin) | Proett, Mark (Halliburton) | Chen, Dingding (Halliburton) | Eyuboglu, Sami (Halliburton) | Torres-Verdin, Carlos (UT Austin) | Sepehrnoori, Kamy (University of Texas at Austin)
Testing in tight formations and unconventional reservoirs poses significant challenges when determining reservoir pressure. The primary difficulty in testing a low mobility formation is that a conventional pressure transient test cannot be applied because the buildup time required for pressure stability after a typical drawdown is excessively long. To reduce testing time, a new automated pulse test method has been developed.
The new pulse test method consists of a drawdown or injection followed by a short stabilization period. Then depending on the buildup response, a new drawdown or injection is performed followed by a short buildup. This sequence is repeated until the desired buildup stabilization is achieved and then a final extended shut-in period is used for analysis of formation properties such as pressure and mobility. The pressure stabilization time can be further reduced by implementing an adaptive pressure feedback in the system.
This new method uses sequential pressure responses and automated pressure pulses. The analysis of the final pressure yields a measurement in 0.5% range of the initial formation pressure while decreasing the wait time by a factor of 10 for a packer-type formation tester. Furthermore, the pressure measurements are analyzed to obtain reservoir permeability and storage.
The new method was tested on synthetic reservoir models and a field study. These demonstrated that the method permits a rapid appraisal of pressure measurement in comparison with conventional testing. Moreover, the implemented feedback system mitigates the supercharge effect.