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Collaborating Authors
Results
Assessment of Depth of Mud-Filtrate Invasion and Water Saturation Using Formation-Tester Measurements: Application to Deeply Invaded Tight-Gas Sandstones
Bennis, Mohamed (The University of Texas at Austin) | Mohamed, Tarek S. (The University of Texas at Austin) | Torres-Verdín, Carlos (The University of Texas at Austin) | Merletti, German (bp) | Gelvez, Camilo (bp)
Abstract Formation pressure/fluid measurements are impacted by mud-filtrate invasion, which may require long fluid pumpout durations to acquire hydrocarbon samples with minimal mud-filtrate contamination. However, unlike other well-logging instruments, formation testers do not have a fixed depth of investigation that limits their ability to pump out mud filtrate until acquiring original formation fluids (i.e., sensing the uninvaded zone). We use an in-house petrophysical and fluid-flow simulator to perform numerical simulations of mud-filtrate invasion, well logs, and formation-tester measurements to estimate the radial distance of invasion and the corresponding radial profile of water saturation. Numerical simulations are initialized with the construction of a multilayer petrophysical model. Initial guesses of volumetric concentration of shale, porosity, water saturation, irreducible water saturation, and residual hydrocarbon saturation are obtained from conventional petrophysical interpretation. Fluid-flow-dependent petrophysical properties (permeability, capillary pressure, and relative permeability), mud properties, rock mineral composition, and in-situ fluid properties are obtained from laboratory measurements. The process of mud-filtrate invasion and the corresponding resistivity and nuclear logs are numerically simulated to iteratively match the available well logs and estimate layer-by-layer formation water saturation. Next, using our multiphase formation testing simulator, we numerically simulate actual fluid sampling operations performed with a dual-packer formation tester. Finally, we estimate irreducible water saturation by minimizing the difference between the hydrocarbon breakthrough time numerically simulated and measured with formation-tester measurements. The examined sandstone reservoir is characterized by low porosity (up to 0.14), low-to-medium permeability (up to 40 md), and high residual gas saturation (between 0.4 and 0.5). The deep mud-filtrate invasion resulted from extended overbalanced exposure to high-salinity water-based mud (17 days of invasion and 1,800 psi overbalance pressure) coupled with the low mud-filtrate storage capacity of tight sandstones. Therefore, the uninvaded formation is located far beyond the depth of investigation of resistivity tools, whereby deep-sensing resistivities are lower than those of uninvaded formation resistivity. Through the numerical simulation of mud-filtrate invasion, well logs, and formation-tester measurements, we estimated radial and vertical distributions of water saturation around the borehole. Likewise, we quantified the hydrocarbon breakthrough time, which matched field measurements of 6.5 hours. The estimated radius of invasion was approximately 2.5 m, while the difference between estimated water saturation in the uninvaded zone and water saturation estimated from the deep-sensing resistivity log was approximately 0.13, therefore improving the estimation of the original gas in place.
- South America (0.93)
- Europe > Norway (0.66)
- North America > United States > Texas > Travis County > Austin (0.30)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (1.00)
- Geology > Mineral (1.00)
- North America > United States > Wyoming > Powder River Basin (0.99)
- North America > United States > Montana > Powder River Basin (0.99)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Formation test analysis (e.g., wireline, LWD) (1.00)
Abstract Breidablikk is a green field on the Norwegian Continental Shelf that just started the preproduction drilling of 23 wells in two structures. We have two reservoir fluid samples from exploration wells in each structure with relatively high viscosity of 4 and 8 cP, respectively. Our dynamic reservoir simulations on the Breidablikk Field indicate that any change in the viscosity in each direction can lead to a 20 to 30% difference in oil recovery. Therefore, updating our reservoir models with the viscosity distribution in the field along with the drilling activities is important. Currently, our models assume homogeneous reservoir oil viscosities across each structure. In this study, our primary aim is to conduct a holistic evaluation of the reservoir oil viscosity, using multiple methods to determine the most effective approach for qualitatively mapping the oil viscosity across the field, distinguishing between the low- and high-viscosity regions. The technologies chosen for this assessment are standard mud gas data, advanced mud gas data, and analysis of oil extracts from cuttings, given they have previously demonstrated their capability to estimate fluid properties while drilling or within a limited time frame, as evidenced by the work of Cutler et al. (2022). The methods were compared using pressure/volume/temperature (PVT) measurements as a benchmark. As of today, this method is considered the most reliable to obtain reservoir fluid properties, and in consequence, these measurements serve as the reference viscosity values in the study. The results of our analysis in Breidablikk show that an approach based on advanced mud gas data provide an oil quality classification that distinguishes between high- and low-viscosity reservoir oils, using the ethane/n-pentane ratio as the best parameter correlated to reservoir oil viscosity in Breidablikk. The threshold for the two viscosity regions is identified from a reservoir fluid database from the Breidablikk-Grane area, and the oil viscosity region estimated from advanced mud gas data agrees well with the PVT measurements. The viscosity estimation using a standard mud gas approach based on methane to propane compositions indicates that this technology cannot correctly differentiate between low- and high-viscosity region wells in the Breidablikk Field. Hence, it is not recommended. Further findings from our analysis indicate that the utilization of oil-based mud, combined with a high drilling speed, significantly affects the quality of the cuttings in Breidablikk. Consequently, the application of traditional geochemical analysis methods on cutting extracts is challenging. Therefore, this method is not recommended for the qualitative identification of the viscosity region of a given well. Benchmarking all available technologies allows us to select a real-time, reliable, and cost-efficient method to qualitatively estimate reservoir oil viscosity in Breidablikk. The selected method is field-specific and not general for other heavy oil fields. In summary, providing an accurate reservoir oil viscosity mapping at an early stage in field development plays a crucial role in the further optimization of drilling targets and ultimately leads to improved oil recovery (Halvorsen et al., 2016; Maraj et al., 2021).
- Geology > Geological Subdiscipline > Geochemistry (1.00)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (0.87)
- Europe > Norway > North Sea > PL 169 > Block 25/8 > Breidablikk Field > Tor Formation (0.99)
- Europe > Norway > North Sea > PL 169 > Block 25/8 > Breidablikk Field > Hod Formation (0.99)
- Europe > Norway > North Sea > PL 169 > Block 25/8 > Breidablikk Field > Heimdal Formation (0.99)
- (14 more...)
Abstract It is challenging to reliably identify fluid components and estimate their saturations in formations with complex lithology, complex pore structure, or varying wettability conditions. Common practices for assessing fluid saturations rely on the interpretation of resistivity measurements. These techniques require model calibration, which is time consuming/expensive and can only differentiate conductive and nonconductive fluids. Interpretation of 2D NMR maps provides a viable alternative for identifying fluid components and fluid volumes. However, conventional techniques for the interpretation of 2D NMR rely on cutoffs in the T1-T2 or D-T2 maps. The application of cutoffs is prone to inaccuracies when fluid-component relaxation responses overlap. To address these shortcomings, we introduce a new workflow for identifying/tracking fluid components and estimating their volumes from the interpretation of 2D NMR measurements. We developed a workflow that approximates 2D NMR maps with a superposition of 2D Gaussian distributions. The algorithm automatically determines the optimum number of Gaussian distributions and their corresponding properties (i.e., amplitudes, variances, and means). Next, a clustering technique is implemented to the dataspace containing the Gaussian distribution parameters obtained for the entire logged interval. Each Gaussian is assigned to a cluster corresponding to different pore/fluid components. We then calculate the volumes under the Gaussian distributions corresponding to each cluster at each depth. The volumes associated with each cluster translate directly into the pore volumes corresponding to the different fluid components (e.g., heavy/light hydrocarbon, bound/free water) at each depth. A highlighted contribution of this work is that, in contrast to the alternative petrophysical interpretation techniques for fluid characterization, the introduced workflow does not require calibration efforts, user-defined cutoffs, or proprietary data sets. Furthermore, approximating 2D NMR data with a superposition of Gaussian distributions improves the accuracy of estimated pore volumes of fluid components with overlapping NMR responses. The clustering using the Gaussian distribution parameters as inputs enables depth tracking of different fluid components without making use of user-defined 2D cutoffs. Finally, the multidimensional nature of the introduced clustering provides the unique capability of identifying different fluid components with 2D NMR response located in the same range of coordinates in a T1-T2 map. We successfully verified the reliability and robustness of the new workflow for enhancing petrophysical interpretation in two organic-rich mudrock formations with complex mineralogy and pore structure.
- North America > United States > Texas (1.00)
- Europe (0.93)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock (0.67)
- Geology > Geological Subdiscipline > Mineralogy (0.61)
- South America > Argentina > Patagonia > Neuquén > Neuquen Basin > Vaca Muerta Shale Formation (0.99)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.99)
- (25 more...)
Development and Baseline Comparison of a New Pulsed-Neutron Spectroscopy Tool for Carbon- Oxygen Analysis and Three-Phase Saturation Monitoring
McGlynn, Ian (Baker Hughes) | Anniyev, Toyli (Baker Hughes) | Inanc, Feyzi (Baker Hughes) | Chace, David (Baker Hughes) | Kotov, Alexandr (Baker Hughes) | Soans, Emmannuel (Baker Hughes) | Batubara, Ardi (Baker Hughes)
Abstract A new slim multidetector pulsed-neutron wireline-logging tool has been developed for openhole or casedhole formation evaluation saturation analysis and time-lapse monitoring. With a greater neutron source output and high-spectral resolution gamma ray detectors, the tool can be operated with reduced uncertainty or faster logging speeds. New, fully programable digital electronics provide a range of acquisition modes optimized for specific formation evaluation objectives. Neutrons are generated from a high-output pulsed-neutron generator, which propagates radially outward, passing through the borehole, completion material, and into the formation. Energy is lost through scattering, and neutrons are absorbed by the surrounding material. Gamma rays are emitted from scattering and absorption interactions at discrete energies, which can be measured by one of three spectral gamma scintillation detectors. The energy distribution of these incident gamma rays by inelastic and capture interactions is affected by the elemental composition of the material. A salinity-independent oil-water saturation assessment begins with the deconvolution of neutron-induced gamma ray inelastic spectra into constituent elemental components. Carbon-oxygen ratios (C/O) of elemental yields are then compared to a reference model to determine the relative saturation and porosity-filled volume of oil and water. In PNC (pulsed-neutron capture) acquisition mode, a salinity-dependent oil-water saturation assessment is determined from neutron capture cross section (sigma) measurements, which are compared to formation and porosity fluids using a mass balance approach. Gas saturation assessment is determined from gas-sensitive inelastic (RIN13) and capture (RATO13) ratios. Gas ratios are compared to a reference model to assess the relative saturation of fluids, typically distinguishing gas from water or gas from oil. Gas saturation is not limited to hydrocarbon components and can also be used for saturation analysis of H2, He, CO2, N2, and other non-hydrocarbon-bearing components. A new Omni-mode acquisition combining simultaneous PNC and C/O measurements was also developed. This acquisition mode provides advantages in reducing multipass logging typically required from separate PNC and C/O acquisitions. By including PNC neutron capture sigma, gas-sensitive neutron capture and inelastic measurements, and C/O inelastic measurements, the simultaneous Omni-mode (PNC+C/O) acquisition is specifically optimized for three-phase saturation analysis applications, including baseline CO2 sequestration evaluation for carbon capture, utilization, and storage (CCUS) CO2 and steamflood time-lapse monitoring. Results from a field example are presented to demonstrate the new technology with spectral C/O saturation analysis compared to traditional windows C/O analysis and to compare the performance of the next-generation tool to the legacy tool. Multiphase saturations from C/O and RIN13 measurements and compatibility with legacy interpretations for time-lapse saturation monitoring are also presented.
- North America > United States > Texas (1.00)
- Europe (1.00)
- Asia > Middle East (1.00)
- Africa (0.67)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.70)
- Geology > Geological Subdiscipline (0.68)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (21 more...)
Abstract We study the impact of signal-to-noise ratio (SNR) on nuclear magnetic resonance (NMR) T1-T2 maps across data sets acquired in multiple wells of an unconventional field under various logging and processing conditions. The mean and standard deviation of NMR porosity error between continuous moving-pass and stationary measurements are used to obtain insights into the impact of SNR on accuracy and precision. In a proof-of-concept experiment, we introduce a novel semi-analytical smeared-peak (SASP) technique that compensates for the over-regularized smearing due to poor SNR, of T1-T2 relaxation responses of different fluids. The SASP approximation to de-smear volumes of different fluid types is validated with field measurements from multiple wells. The uplift of the SASP technique in improving fluid volume interpretations is apparent in the in-situ calibration of low-SNR moving-pass NMR measurements with high-quality stationary measurements. The learnings show that logging protocols that are designed to increase SNR by combining specific acquisition parameters with processing strategies, within acceptable compromises, are mandatory for reliable NMR characterization of unconventional reservoirs.
Abstract The complexity of the microstructure and fluids in unconventional reservoirs presents challenges to the traditional approaches to the evaluation of geological formations and petrophysical properties due to the low porosity, ultralow permeability, complex lithology, and fluid composition. Nuclear magnetic resonance (NMR) techniques have been playing major roles in unconventional shale characterization in the last decades as NMR can provide critical information about the reservoirs for quantifying their petrophysical parameters and fluid properties and estimating productivity. Laboratory NMR techniques at higher frequency (HF), e.g., 23 MHz, especially two-dimensional (2D) T1-T2 mapping, and their applications have been essential for the noninvasive characterization of tight rock samples for identifying kerogen, bitumen, heavy or light hydrocarbons, and bound or capillary water. Traditional T2 cutoffs, established with low frequency (LF) NMR, no longer apply and need new definitions to reflect the inferences from water and hydrocarbons separately. The crushed rock analysis method, as applied to unconventional formations, has been successful in evaluating total porosity and water saturation but also suffers from inconsistency in results due to desiccation and solvent effects. In the past decade, the oil and gas industry has witnessed significant development of HF NMR techniques that couple advances in petrophysics, petroleum engineering, and geochemistry with a broad range of applications. It is necessary to review such technological advances and draw conclusions to benefit unconventional core analysis programs. This article will summarize key advances in laboratory NMR applications in unconventional shale characterization, including monitoring processes of liquids equilibrium, desiccation, and imbibition in fresh shale samples, determination of activation energy of hydrocarbons in shales, monitoring changes in a shale sample during liquid flooding experiments, and direct measurements on kerogen.
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.48)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Maverick Basin > Eagle Ford Shale Formation (0.99)
- (24 more...)
Abstract The industry is continuously challenged to improve the efficiency and safety of operations. This is evident over the last 30 years in the development and improvement of measurements acquired while drilling. However, this has, in general, until now not been applied to well integrity measurements such as casing integrity and cement evaluation, which have traditionally been acquired utilizing wireline deployment. This paper will show the results of a new drillpipe-deployed tool that can be run in parallel with existing well operations. The results from two differing North Sea wells will be compared to traditionally acquired wireline-deployed tools and will demonstrate that these measurements and the resultant interpretation can successfully be acquired on drillpipe. This allows for much improved efficiency of operations and, in fact, the ability to acquire this important data in well conditions and environments where it is difficult or, in some cases, impossible to log with conventional wireline techniques. Two wells were selected with different degrees of difficulty in terms of measurement acquisition and showing different well trajectories and mud types. Both wells were logged with both the new drillpipe-deployed technology and traditional wireline technology, allowing a direct comparison of the techniques and tools and paving the way for acceptance of the new drillpipe-conveyed technology. The new drillpipe-conveyed tool can be run anytime drillpipe is utilized in the well. A radial distribution of ultrasonic transducers arranged on the circumference of a drill collar allows for full azimuthal interpretation of the casing and cement while rotating the drillpipe. Analysis of the acquired data allows for the interpretation of caliper thickness and an evaluation of the material in the annular space behind the casing. In addition, the tool can provide casing collar location in real time and has the ability to orient downhole devices such as whipstocks, perforating guns, and oriented cutters. The two well examples conclusively demonstrate that the tool can be run in parallel with existing operations to minimize rig time and eliminate the need for a dedicated, standalone wireline operation. Also, the cement evaluation interpretation was comparable to the equivalent wireline technology. We will investigate which measurements and applications the new tool can be used for and where there may be further room for improvement.
- North America > United States > Texas (0.28)
- Europe > United Kingdom > North Sea (0.24)
- Europe > Norway > North Sea (0.24)
- (2 more...)
Abstract Dissolution of CO2 in saline waters is considered one of three main CO2 trapping mechanisms, along with structural/stratigraphic trapping and mineralization. CO2 can dissolve in fresh/saline water under typical reservoir pressure and temperatures. Its solubility is dependent on pressure, temperature, and salinity. CO2 solubility studies typically consider saline water or fresh water as a liquid without any predissolved gases. The reality is formation water may contain appreciable dissolved gases for all pressure and temperature conditions. An example of gas-water ratio (GWR) can be ~1 scf/stb for formation water in an oil reservoir and ~5 to 6 scf/stb for a deep saline aquifer. Therefore, it is essential to quantify the effect of brine salinity on CO2 solubility in “live” saline waters. Just as “live” oil denotes reservoir oil that contains solution gas, we define “live” brine as saline water that includes dissolved gases. Conversely, “dead” brine refers to saline water devoid of any dissolved gas content. Two sets of experiments were conducted under typical reservoir conditions. The first set of experiments evaluated the CO2 solubility in live formation water. The second set of experiments evaluated how variation in the live brine salinity affected CO2 solubility. These experiments involved 1) synthesis of the brine, 2) synthesis of natural gas mixture, 3) recombination of live formation water with a natural gas mixture and transfer into a high-pressure and high-temperature pressure-volume-temperature (PVT) visual cell, 4) CO2 addition to the PVT cell, and 5) bubblepoint pressure determination within the PVT cell. The results showed that CO2 solubility in live formation water is significantly less than that in “dead” water under reservoir conditions. In addition, the brine salinity affects CO2 solubility in live formation water by further reducing CO2 solubility with increasing live brine salinity. As the brine salinity increases, very little CO2 can be dissolved in the live brine once it reaches a certain solubility. An understanding of CO2 dissolution in live saline water is essential for future CCUS evaluation and execution.
- North America > United States > Texas (0.28)
- Europe > Norway > Norwegian Sea (0.24)
- Reservoir Description and Dynamics > Storage Reservoir Engineering > CO2 capture and sequestration (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (1.00)
- Health, Safety, Environment & Sustainability > Environment > Climate change (1.00)
Abstract In the current scenario of project management, where the agility and optimization of operations have been prioritized, the practice of logging while drilling (LWD) has gained space compared to traditional wireline logging. In theory, acquiring quality petrophysical properties during drilling brings greater agility in decision making about completion and optimizes operation costs. However, regarding borehole image logs, due to limitations in transmission capacity, the actual available data in real time contain about 50% (for resistivity images) of the full azimuth information, being insufficient for the identification of critical geological structures capable of impacting the communication between production or injection zones or the quality of cementation, such as fractures, caves, and geomechanical collapse zones. The tool’s memory data with the full information may take a few days after the end of drilling to be delivered by the service company, which in some cases is not enough for fast decision making regarding completion. In this work, we tested models based on generative adversarial neural networks (GANs) to reconstruct the complete memory data based on real-time input. As in conventional GAN schemes, a generator is trained to receive a real-time input and create a “memory-like” image, while a discriminator is trained to tell real and fake images apart. To regularize the convergence of training, we used an architecture known in the literature as CycleGAN, where another generator-discriminator pair is trained simultaneously to do the reverse process, recreating the real-time data. Variations of the training process and data sets were used to generate different CycleGAN models. They were trained using logs of presalt reservoirs in Buzios Field, and performance was assessed on logging intervals not seen by the algorithms during training. The results achieved so far have been very promising, as in certain intervals, resultant models were able to capture the presence of fractures and caves. This methodology represents a way of circumventing telemetry limitations, where missing information is added indirectly to the real-time data as the artificial intelligence (AI) algorithm learns the main characteristics of a field/reservoir. Therefore, previous knowledge from the field can be used to continuously optimize future operations, efficiently incorporating the available database into the workflow of petrophysicists for the recognition of geological and geomechanical structures in time to support decision making in completion operations.
- North America > United States (1.00)
- South America > Brazil > Rio de Janeiro > South Atlantic Ocean (0.24)
- Geology > Rock Type > Sedimentary Rock (0.93)
- Geology > Geological Subdiscipline (0.69)
- Geology > Structural Geology > Tectonics > Salt Tectonics (0.35)
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Seismic Surveying > Borehole Seismic Surveying (0.35)
Abstract Salt is an elastoviscoplastic material that exhibits time-dependent deformation (creep). Experimental measurements of salt creep behavior help predict underground gas repositories’ long-term geomechanical behavior. Previous time-scaling creep experiments have focused on the axial strain of unconsolidated sands. i.e., time-scaling creep effects under zero lateral strain conditions without describing the creep behavior of the radial strain. In addition, the time-scaling creep of the radial and axial strain has not been investigated in salts. A comparative testing procedure and analysis method was conducted on Spindletop salt plugs using triaxial tests for multistage triaxial tests (MST) and different holding time durations and stress regimes, resulting in time-dependent strain responses (creep tests). The MST showed evolving deformational mechanisms under the mapped yield surface based on the irrecoverable to recoverable strain ratio beginning with crack closure or conformance, plasticity, and ending at early crystal surface failure. Unlike unconsolidated sands, salts showed both time and strain amplitude scaling. The axial and radial strain data show scaling behavior under low and high levels of deviatoric stress separated by a transitional period. The salt showed only an axial creep response at low deviatoric stress distally from the yield surface (one-dimesional (1D) response or zero lateral strain), which indicates negative dilatant deformation or uniaxial compaction. In contrast, the salts showed equal strain amplitude scaling factors both axially and radially at high deviatoric stress proximal to the yield surface (two-dimensional (2D) response or unconstrained boundary condition), which suggests positive dilatant deformation. Microstructural images showed accumulated creep damage under high deviatoric stress associated with parallel planes of dislocation-intergranular slip, microcracking, and compaction-induced dilational strains. The period of scaling is interpreted as regions where a single mechanism is dominating. Strain amplitude scaling for both low and high deviatoric creep stress tests provides inputs for a constitutive model of creep response in understanding the magnitude of mechanical damage associated with time-independent stress-strain curves in salts for the structural integrity of salt caverns during cyclic fluid injection and depletion.
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Mineral > Halide > Halite (0.48)
- North America > United States > Texas (0.89)
- North America > United States > Louisiana (0.89)