Openhole Multistage Completion Evaluation Incorporating Deployment of Downhole Shut-in Tool Application in Sour Carbonate Gas Wells, Field Application

This paper highlights the first successful application of a field deployment of a high-temperature (HT) downhole shut-in tool (DHSIT) in multistage fracturing completions (MSF) producing retrograde gas condensate and from sour carbonate reservoirs. Many gas operators and service providers have made various attempts in the past to evaluate the long-term benefit of MSF completions while deploying DHSIT devices but have achieved only limited success (Ref. 1 and 2). During such deployments, many challenges and difficulties were faced in the attempt to deploy and retrieve those tools as well as to complete sound data interpretation to successfully identify both reservoir, stimulation, and downhole productivity parameters, and especially when having a combination of both heterogeneous rocks having retrograde gas pressure-volume-temperature (PVT) complexities. Therefore, a robust design of a DHSIT was needed to accurately shut-in the well, hold differential pressure, capture downhole pressure transient data, and thereby identify acid fracture design/conductivity, evaluate total KH, reduce wellbore storage effects, properly evaluate transient pressure effects, and then obtain a better understanding of frac geometry, reservoir parameters, and geologic uncertainties. Several aspects were taken into consideration for overcoming those challenges when preparing the DHSIT tool design including but not limited to proper metallurgy selection, enough gas flow area, impact on well drawdown, tool differential pressure, proper elastomer selection, shut-in time programming, internal completion diameter, and battery operation life and temperature. This paper is based on the first successful deployment and retrieval of the DHSIT in a 4-½" MSF sour carbonate gas well. The trial proved that all design considerations were important and took into consideration all well parameters. This project confirmed that DHSIT devices can successfully withstand the challenges of operating in sour carbonate MSF gas wells as well as minimize operational risk. This successful trial demonstrates the value of utilizing the DHSIT, and confirms more tangible values for wellbore conductivity post stimulation. All this was achieved by the proper metallurgy selection, maximizing gas flow area, minimizing the impact on well drawdown, and reducing well shut-in time and deferred gas production. Proper battery selection and elastomer design also enabled the tool to be operated at temperatures as high as 350 °F. The case study includes the detailed analysis of deployment and retrieval lessons learned, and includes equalization procedures, which added to the complexity of the operation. The paper captures all engineering concepts, tool design, setting packer mechanism, deployment procedures, and tool equalization and retrieval along with data evaluation and interpretation. In addition to lessons learned based on the field trial, various recommendations will be presented to minimize operational risk, optimize shut-in time and maximize data quality and interpretation. Utilizing the lessons learned and the developed procedures presented in this paper will allow for the expansion of this technology to different gas well types and formations as well as standardize use to proper evaluate the value of future MSF completions and stimulation designs.

Advanced NMR methodologies in rock core analysis

<p>¹H NMR techniques have gained extensive acceptance in petrophysics for the evaluation of fluid-saturating reservoir rocks. This thesis presents the development of new NMR methods regarding the reserves (determination of pore length scales and surface relaxivities), productivity (estimates of permeability) and recovery of fluids (resolves of saturation evolution) in rocks. Traditionally, pore lengths are evaluated from the ground relaxation eigenmodes of spin-bearing molecules in pore space. This evaluation is not straightforward since it is affected by surface relaxivity. Here, we use an approach to determine pore length from detecting the high relaxation eigenmodes, in which way the eigenvalue spectrum directly scales to the pore size distribution. Based on this, we extend this approach for the use with low-field NMR spectrometers and 2D NMR eigenmode correlation methods. Surface relaxivity can be further extracted from these 2D correlation maps, which is in agreement with an independent NMR measurement. Permeability is generally estimated from surface relaxation via empirical pore-network models. However, for heterogeneous rocks a single (or averaged) permeability value may not be adequate. Therefore, we measure surface relaxation in conjunction with MRI techniques. Permeability profiles can then be obtained from spatially resolved relaxation maps yielding local connectedness between adjacent slices. The results are confirmed by the comparison of brine-permeability measurements. MRI experiments of fluids in rocks at reservoir-like conditions may yield optimized recovery strategies of reservoir fluids. In this context we combine MRI with diffusion-relaxation correlation measurements during flooding intervals. The results provide substantial information, such as flooding front and saturation profiles of immiscible fluids discriminated by fluid type.</p>

Advanced NMR methodologies in rock core analysis

<p>¹H NMR techniques have gained extensive acceptance in petrophysics for the evaluation of fluid-saturating reservoir rocks. This thesis presents the development of new NMR methods regarding the reserves (determination of pore length scales and surface relaxivities), productivity (estimates of permeability) and recovery of fluids (resolves of saturation evolution) in rocks. Traditionally, pore lengths are evaluated from the ground relaxation eigenmodes of spin-bearing molecules in pore space. This evaluation is not straightforward since it is affected by surface relaxivity. Here, we use an approach to determine pore length from detecting the high relaxation eigenmodes, in which way the eigenvalue spectrum directly scales to the pore size distribution. Based on this, we extend this approach for the use with low-field NMR spectrometers and 2D NMR eigenmode correlation methods. Surface relaxivity can be further extracted from these 2D correlation maps, which is in agreement with an independent NMR measurement. Permeability is generally estimated from surface relaxation via empirical pore-network models. However, for heterogeneous rocks a single (or averaged) permeability value may not be adequate. Therefore, we measure surface relaxation in conjunction with MRI techniques. Permeability profiles can then be obtained from spatially resolved relaxation maps yielding local connectedness between adjacent slices. The results are confirmed by the comparison of brine-permeability measurements. MRI experiments of fluids in rocks at reservoir-like conditions may yield optimized recovery strategies of reservoir fluids. In this context we combine MRI with diffusion-relaxation correlation measurements during flooding intervals. The results provide substantial information, such as flooding front and saturation profiles of immiscible fluids discriminated by fluid type.</p>

Experimental Investigation of Two-Phase Flow Properties of Heterogeneous Rocks for Advanced Formation Evaluation

An uncommon facet of Formation Evaluation is the assessment of flow-related in situ properties of rocks. Most of the models used to describe two-phase flow properties of porous rocks assume homogeneous and/or isotropic media, which is hardly the case with actual reservoir rocks, regardless of scale; carbonates and grain-laminated sandstones are but two common examples of this situation. The degree of spatial complexity of rocks and its effect on the mobility of hydrocarbons are of paramount importance for the description of multiphase fluid flow in most contemporary reservoirs. There is thus a need for experimental and numerical methods that integrate all salient details about fluid-fluid and rock-fluid interactions. Such hybrid, laboratory-simulation projects are necessary to develop realistic models of fractional flow, i.e., saturation-dependent capillary pressure and relative permeability. We document a new high-resolution visualization technique that provides experimental insight to quantify fluid saturation patterns in heterogeneous rocks and allows for the evaluation of effective two-phase flow properties. The experimental apparatus consists of an X-ray microfocus scanner and an automated syringe pump. Rather than using traditional cylindrical cores, thin rectangular rock samples are examined, their thickness being one order of magnitude smaller than the remaining two dimensions. During the experiment, the core is scanned quasi-continuously while the fluids are being injected, allowing for time-lapse visualization of the flood front. Numerical simulations are then conducted to match the experimental data and quantify effective saturation-dependent relative permeability and capillary pressure. Experimental results indicate that flow patterns and in situ saturations are highly dependent on the nature of the heterogeneity and bedding-plane orientation during both imbibition and drainage cycles. In homogeneous rocks, fluid displacement is piston-like, as predicted by the Buckley-Leverett theory of fractional flow. Assessment of capillary pressure and relative permeability is performed by examining the time-lapse water saturation profiles. In spatially complex rocks, high-resolution time-lapse images reveal preferential flow paths along high permeability sections and a lowered sweep efficiency. Our experimental procedure emphasizes that capillary pressure and transmissibility differences play an important role in fluid-saturation distribution and sweep efficiency at late times. The method is fast and reliable to assess mixing laws for fluid-transport properties of rocks in spatially complex formations.

Free or Bound? Thomeer and NMR Porosity Partitioning in Carbonate Reservoirs, Alta Discovery, Southwestern Barents Sea

The main etrophysical challenges in carbonate reservoirs are often to define meaningful rock types, then to establish robust permeability and saturation models for these rock types, as well as to develop a realistic estimation of irreducible water saturation (Swirr). Realistic Swirr estimation is important for predicting production behavior (expected development of water cut) and thus ultimately for planning the future development scheme of a discovery. In this study, we present the 2014 Alta discovery, located in the southwestern Barents Sea. More than 50% of the expected hydrocarbon resources reside within complex carbonate reservoirs of Permo-Carboniferous age that display highly variable rock properties. The initial screening revealed that primary rock textures and pore geometries were, for a large part, overprinted by diagenetic processes. Hence, better control on the reservoir’s diagenetic evolution will be needed to apply a full-scale rock typing workflow. In the meantime, it was decided to proceed with a simplified reservoir characterization approach based on the main stratigraphic building blocks. Sufficient core coverage allowed for using permeability measurements on core samples as direct input to a 3D reservoir model. A customized core analysis program, using whole-core samples, was designed to characterize the effect of large-scale vuggy pores. For modeling water saturation, a workflow based on the Thomeer hyperbola was developed that describes mercury injection capillary pressure (MICP) curves. The results adequately specify the saturation in all the stratigraphic building blocks. However, saturation uncertainty in the reservoir is high due to a highly variable cementation factor (m), unknown wettability, and the presence of residual oil below the current free-water level (FWL). The Alta structure has been and still is leaking gas, causing the FWL to rise over time. To address the otherwise underestimated volumes in the transition zone above the current FWL, a deeper pseudo-FWL was created and used as input to the saturation height function. Despite log-based water saturation (Archie) and core measurements (Dean-Stark) indicating more than 80% water saturation for less permeable reservoir rocks within the oil leg, production tests did not produce water at normal rates. This clearly demonstrated the need to distinguish “nonproductive” pore systems (with capillary-bound fluids; in this case, water) from pore systems contributing to production (“free” fluids). A large MICP data set confirmed that most reservoir rocks exhibit a mix of different pore types and pore-throat diameters. To model this accurately, porosity partitioning in nonproductive microporosity and movable porosity using the NMR logs was performed. Calibrating appropriate T2 cutoffs by matching core MICP to NMR logs in these heterogeneous rocks is seriously hampered by the large difference in sample size. Applying both MICP and NMR measurements to a subset of core plugs helped to resolve this challenge. Comparing the corresponding movable (“free”) porosity to total porosity revealed near-linear relationships for different reservoir rocks. For irreducible water saturation (Swirr), Swimmobile is calculated using the NMR-based movable porosity. Swimmobile is considered to be a close approximation of Swirr. The resulting full-field simulation showed a significantly improved match between model output and recorded well test data.

Extended Gassmann Equation with Dynamic Volumetric Strain: Modeling Wave Dispersion and Attenuation of Heterogenous Porous Rocks

Sedimentary rocks are often heterogeneous porous media inherently containing complex distributions of heterogeneities (e.g., fluid patches, cracks). Understanding and modeling their frequency-dependent elastic and adsorption behaviors is of great interest for subsurface rock characterization from multi-scale geophysical measurements. The physical parameter of dynamic volumetric strain (DVS) associated with wave-induced fluid flow is proposed to understand the common physics and connections behind known poroelastic models for modeling dispersion behaviors of heterogeneous rocks. We derive the theoretical formulations of DVS for patchy saturated rock at mesoscopic scale and cracked porous rock at microscopic grain scales, essentially embodying the wave-induced fluid pressure relaxation process. By incorporating the DVS into the classical Gassmann equation, a simple but practical “dynamic equivalent” modeling approach, extended Gassmann equation, is developed to characterize the dispersion and attenuation of complex heterogeneous rocks at non-zero frequencies. Using the extended Gassmann equation, the effect of microscopic or mesoscopic heterogeneities with complex distributions on the wave dispersion and attenuation signatures can be captured. The proposed theoretical framework provides a simple and straightforward analytical methodology to calculate wave dispersion and attenuation in porous rocks with multiple sets of heterogeneities exhibiting complex characteristics. We also demonstrate that, with the appropriate consideration of multiple crack sets and complex fluids patches distribution, the modeling results can better interpret the experimental data sets of dispersion and attenuation for heterogeneous porous rocks.

Reliability of Relative Permeability Measurements for Heterogeneous Rocks Using Horizontal Core Flood Experiments

New guidelines and suggestions for taking reliable effective relative permeability measurements in heterogeneous rocks are presented. The results are based on a combination of high resolution of 3D core-flooding simulations and semi-analytical solutions for the heterogeneous cores. Synthetic “data sets” are generated using TOUGH2 and are subsequently used to calculate effective relative permeability curves. A comparison between the input relative permeability curves and “calculated” relative permeability is used to assess the accuracy of the “measured” values. The results show that, for a capillary number (Ncv = kLpc × A/H2μCO2qt) smaller than a critical value, flows are viscous dominated. Under these conditions, saturation depends only on the fractional flow as well as capillary heterogeneity, and is independent of flow rate, gravity, permeability, core length, and interfacial tension. Accurate whole-core effective relative permeability measurements can be obtained regardless of the orientation of the core and for a high degree of heterogeneity under a range of relevant and practical conditions. Importantly, the transition from the viscous to gravity/capillary dominated flow regimes occurs at much higher flow rates for heterogeneous rocks. For the capillary numbers larger than the critical value, saturation gradients develop along the length of the core and accurate relative permeability measurements are not obtained using traditional steady-state methods. However, if capillary pressure measurements at the end of the core are available or can be estimated from independently measured capillary pressure curves and the measured saturation at the inlet and outlet of the core, accurate effective relative permeability measurements can be obtained even when there is a small saturation gradient across the core.