Near-wellbore Region Research Articles

Autonomous Inflow Control Devices Help Maximize Life of Wells in Deepwater West Africa

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 35418, “Design Execution and Evaluation of Advanced Completions in Deepwater West Africa,” by Piyush Pankaj, SPE, Matthew S. Jackson, and Lokesh, ExxonMobil, et al. The paper has not been peer reviewed. Copyright 2024 Offshore Technology Conference. _ Deepwater wells offshore West Africa traverse a complicated faulted block with sand bodies that can feature thicknesses of tens of meters. The study described in the complete paper provides insight into designing advanced well completions under various challenging reservoir conditions with autonomous inflow control devices (AICDs) that enable maximizing the producing life of the wells. Introduction The study area for this paper has been a challenging brownfield. Wells have been drilled in difficult deepwater conditions, and the target reservoirs have been lenticular sands with interbedded shale layers. To further complicate production, the sand bodies are poorly consolidated. Openhole wells with standalone screen and gravel packs have become a common approach to address sand control. Water- and gas-injection programs have been used actively in the field during the past 25 years, which further augments production and reservoir management challenges. Water and gas breakthrough in the infill wells has been a major concern for reservoir management. To address the gas buildup in the near-wellbore region and early water production, AICDs have become a popular feature in the lower well-completion designs in high-angled wells that intersect multiple sand bodies along the lateral completion interval. Two case studies are provided in the complete paper; one is included in this synopsis. Flow-Control Technology Although technology that empowers the ability to control the flow of unwanted fluids from zones in the well has been in use since the 1990s, flow-control technology has rapidly evolved, with advancement fueled by the need for long, complex well designs. The two broad categories of these approaches include active and passive flow control. The decision to use inflow-control technologies can be driven by the following economic values: - Balance drawdown along the wellbore - Increase recovery factor and reserves - Improve well cleanup - Reduces risk of erosion or hot-spotting of sandface completion Choice of Inflow Control for West Africa Field of Study Fluidic-diode AICDs were chosen because of their applicability to encountered fluid properties and reservoir conditions and their robustness of design in providing reliable long-term solutions. The reliability is prolonged in such AICDs because they work without any moving parts. Upon changes in viscosity, density, and rate, the fluid flow path will vary to gain the required control of flow rates. This AICD design, with its special geometry, alters the flow path or pattern for preferential fluid restriction. Operational Execution Ultimately, the AICDs were deployed on an inner string. This allowed the standard wire-wrapped screens and gravel pack to function as the traditional sand-control mechanism, while the inner string, deployed inside the lower completion, provides resistance to flow from unwanted gas production.

Mechanisms of near-wellbore fracture growth considering the presence of cement sheath microcracks and their implications on wellbore stability

Placement of intended perforations is usually extensive enough into the reservoir to minimize any near wellbore influence on the expected fracture growth. However, some unplanned fractures do not necessarily originate from the intended shot holes. A sufficient volume of published work exists on the processes of crack growth from the near wellbore regions such as from the cement sheath or from fractures observed on the formation wall surrounding the wellbore. A robust quantification of wellbore stability issues should not detach such fracture development, which can potentially result into issues such as cement sheath damage and unnecessary formation damage in the near-wellbore regions. Such fractures may become fluid injection points during stimulation related wellbore pressurization, leading to pronounced development. In such scenarios, fracture development may become a nuisance if it jeopardises the intended structural support and zonal isolation integrity of the cement sheath around the wellbore, leading to wellbore failure, and a potential abandonment. The pressure transmission across this structural seal affects the zonal isolation integrity and its intended structural support leading to wellbore instability. Understanding crack growth behaviour in such cement-rock structural framework is still illusional yet it poses the wellbore to a risky state of instability. Our study provides insight into mechanical and elastic behavior of a tightly bonded cement-rock framework with presence of initial cracks. It also provides insight into how the acting far-field stresses, applied wellbore pressures, crack length, and orientation angle influence the crack growth morphologies including planar fractures, curved and cyclic fractures. The study is important not only for a proper selection of the cement slurry but also for the definition of allowable pressures during the wellbore lifespan. Inappropriately selected parameters might lead to the loss of wellbore integrity to a point as early as the start of a well’s life.

Analytical Model for Assessing the Impact of High-Rate CO2 Injection on Dry-out and Salt Precipitation in the Near-Wellbore Region of Saline Aquifers

Analytical Model for Assessing the Impact of High-Rate CO₂ Injection on Dry-out and Salt Precipitation in the Near-Wellbore Region of Saline Aquifers

Identification of plugging types and their formation mechanism based on production curves of coalbed methane wells

Taking the production curves of coalbed methane (CBM) wells in Shizhuang south block in south-central Qinshui Basin (Shanxi Province, China) as a research subject, evaluation indices for the identification of plugging types of pulverized coal were constructed according to changes in daily water production and daily gas production. Four plugging types were classified based on the identification indices’ critical values. The results show when the proportion of soft coal in coal seam segments is not greater than 30%, mid-remote wave-shaped plugging is likely to occur. If the proportion of soft coal in coal seam segments is in the range of 30–50% and the daily water production or daily gas production is large, near-wellbore wave-shaped plugging occurs readily. Under the same proportion of soft coal, mid-remote complete plugging is liable to develop if the daily rates of water and gas production are low. Once soft coal accounts for a proportion equal to and greater than 50% in coal seam segments, near-wellbore regions are likely to be completely plugged. The research provides a method and reference for identifying the types of CBM well de-plugging and formulating de-plugging measures.

Mathematical model of the hydrocarbon displacement process by water in zonally heterogeneous deformable reservoirs

The problem of displacing hydrocarbon systems injected into the reservoir by water in zonally heterogeneous collectors is considered. In this case, the reservoir of circular shape, developed by a single central well, is assumed to consist of two zones with different reservoir and rheological properties. The solution to the problem is obtained, taking into account the incomplete displacement, compressibility of water, and PVT properties of the hydrocarbon system—phase transformation, mass exchange between phases of the hydrocarbon system. Based on the binary representation of the complex hydrocarbon system, a solution to the considered problem is obtained, and an algorithm for calculating the main indicators of the hydrocarbon displacement process to the well is proposed. This algorithm accounts for the fact that the reservoir has different reservoir and rheological characteristics in the near-wellbore region (internal zone) and the distant part of the reservoir (i.e., in the external zone). Keywords: Displacement; Gas-condensate mixture; Volatile oil; Heterogeneous reservoir; Water flooding; Binary model; Unsteady-state flow.

An improved study of near-well zone flooding for polymer solution through the mechanical shearing and forchheimer flow simulation

Polymer flooding is a vital tertiary oil recovery technology that maintains stable oilfield production during high water cut periods. This technique involves improving the viscosity of injection fluids by using polymer solutions, which help reduce the mobility ratio of oil and water, expand sweep efficiency, and increase swept area. However, highly viscous polymer solutions form complex spatial structures between and within molecules, which leads to significant viscosity loss rates in the near-wellbore region at the well injection end. To address this issue, a near-wellbore shear device with nozzle completion was built to study the shear effects of two types of polymers. The study revealed that the polymer solutions destroyed intermolecular and intramolecular structures after shearing, causing the water cut curves to shift up and left. Based on the Brinkman equation of COMSOL Multiphysics's Carreau model, the percolation model of polymer solution in the near-well zone was constructed. COMSOL simulation results also demonstrated that high-speed shearing at the nozzle orifice was the primary cause of shear degradation. Therefore, it is essential to adopt reasonable injection intensities and proper polymer solution concentrations in oilfields to maximize oil recovery and minimize production costs. This is of crucial engineering significance in guiding oilfield production and optimizing injection parameters and processes.

Pressure transient characteristics of non-uniform conductivity fractured wells in viscoelasticity polymer flooding based on oil–water two-phase flow

Polymer flooding in fractured wells has been extensively applied in oilfields to enhance oil recovery. In contrast to water, polymer solution exhibits non-Newtonian and nonlinear behavior such as effects of shear thinning and shear thickening, polymer convection, diffusion, adsorption retention, inaccessible pore volume and reduced effective permeability. Meanwhile, the flux density and fracture conductivity along the hydraulic fracture are generally non-uniform due to the effects of pressure distribution, formation damage, and proppant breakage. In this paper, we present an oil–water two-phase flow model that captures these complex non-Newtonian and nonlinear behavior, and non-uniform fracture characteristics in fractured polymer flooding. The hydraulic fracture is firstly divided into two parts: high-conductivity fracture near the wellbore and low-conductivity fracture in the far-wellbore section. A hybrid grid system, including perpendicular bisection (PEBI) and Cartesian grid, is applied to discrete the partial differential flow equations, and the local grid refinement method is applied in the near-wellbore region to accurately calculate the pressure distribution and shear rate of polymer solution. The combination of polymer behavior characterizations and numerical flow simulations are applied, resulting in the calculation for the distribution of water saturation, polymer concentration and reservoir pressure. Compared with the polymer flooding well with uniform fracture conductivity, this non-uniform fracture conductivity model exhibits the larger pressure difference, and the shorter bilinear flow period due to the decrease of fracture flow ability in the far-wellbore section. The field case of the fall-off test demonstrates that the proposed method characterizes fracture characteristics more accurately, and yields fracture half-lengths that better match engineering reality, enabling a quantitative segmented characterization of the near-wellbore section with high fracture conductivity and the far-wellbore section with low fracture conductivity. The novelty of this paper is the analysis of pressure performances caused by the fracture dynamics and polymer rheology, as well as an analysis method that derives formation and fracture parameters based on the pressure and its derivative curves.

High-Resolution Time-Lapse Monitoring of Mud Invasion in Spatially Complex Rocks Using In-Situ X-Ray Radiography

Borehole measurements, such as electrical resistivity, neutron porosity, or nuclear magnetic resonance, are critical for the in-situ petrophysical assessment of subsurface rocks. However, the interpretation of borehole measurements is often subject to uncertainty arising from their sensitivity to the interplay between mud filtrate, connate fluids, and the rock’s pore structure. This uncertainty remains present even in homogeneous geological formations. Mudcake deposition on the borehole wall causes additional complexity, impacting both well construction and formation evaluation. It is, therefore, essential to account for the latter effects and perform appropriate corrections when interpreting borehole measurements. Recently, new experimental procedures were introduced to quantitatively describe the process of mud invasion under realistic rock and fluid conditions, focusing on gas-bearing rocks and without considering how original saturating fluids affected the process of invasion. Both mud-filtrate invasion and filter-cake deposition must be understood and incorporated into numerical and analytical models to reliably interpret borehole measurements and maximize value. This objective can only be fulfilled via experiments. We use X-ray microfocus radiography to examine in real time the processes of mud-filtrate invasion and internal and external mudcake deposition in thin rectangular rock samples. The high-resolution experimental procedure (10 to 30 μm) mimics the borehole and near-wellbore regions and facilitates the time-lapse visualization of in-situ fluid-transport processes in spatially complex rocks. Water- and oil-based muds were injected into rock samples initially saturated with a range of different connate fluids, including viscous liquids, while being continuously scanned with X-rays. Because the injected drilling muds were the same across all experiments, the observed discrepancies between experiments originate from differences in rock properties, heterogeneity and anisotropy, or initial fluid saturation conditions. Experimental results emphasize the effect of rock heterogeneity and initial connate fluid on the spatial distribution of fluids and mudcake formation ensuing from mud-filtrate invasion. Mud-filtrate invasion rates and final average mudcake thicknesses were similar across all cases for a given drilling mud, suggesting that mudcake properties, as opposed to rock properties, were the controlling factors. By contrast, the spatial distribution of fluids in each rock sample varied significantly between cases, highlighting the impact of rock heterogeneity/anisotropy on the process of invasion. Laboratory experiments also emphasize the impact of viscous and/or capillary forces on mud-filtrate flow behavior. The experimental method is efficient and reliable, allowing for a better understanding of the uncertainty of the effects of mud-filtrate invasion on borehole geophysical measurements acquired while or after drilling.

Time-Lapse Pulsed-Neutron Logs for Carbon Capture and Sequestration: Practical Learnings and Key Insights

Pulsed-neutron logs are a staple of time-lapse monitoring programs for saline aquifer carbon capture and sequestration (CCS) projects and are unsurprisingly the most frequently run wireline logs in both injection and monitoring wells. While the emphasis imposed by government regulators and the focus of operators to date has been on the verification of CO2 containment, it is envisioned that a savvy interpretation of the multiple independent measurements should be able to unlock much greater value for the project than merely detecting the location of stored CO2. Recently introduced capabilities for novel measurements and improved environmental compensation should further increase the repeatability, interpretability, and value of these logs. We reviewed more than 30 time-lapse runs of pulsed-neutron logs acquired over a period of 15 years on three mature CCS projects using both previous- and new-generation pulsed-neutron tools, including measurements of formation sigma, hydrogen index, and fast neutron cross section. Special attention in processing is required when changes occur to the wellbore environment between runs, although this is mitigated by the improved environmental compensation scheme of the newer tool. We performed both standalone estimates of CO2 saturation from single-physics time-lapse measurements and simultaneous interpretation of multiple independent time-lapse measurements and studied the results side-by-side with openhole log interpretation, core analysis, and well test results from the evaluation phase. The apparent changes in saturation were framed within the context of the injection history and important events in the life of the wells. A first finding is that differences in apparent CO2 saturation between the various independent measurement physics of the pulsed-neutron tool are often reconcilable and may carry additional information about the state of the well or reservoir. With respect to verification of containment, depending on the well configuration, it may be possible to differentiate between CO2 in the formation and CO2 in the annulus. The interpreted CO2 saturation itself can have different significance depending on the timing of acquisition and the type of well. Measured at the right time, it is a direct in-situ measurement of formation CO2 storage efficiency. In other cases, the interpretation reveals formation dryout in the near-wellbore region of injection wells, a condition that may presage loss of injectivity. We now understand that it is important for operators to plan the timing and frequency of pulsed-neutron runs according to what they want to measure and not based solely on regulatory obligations. In a CCS project, time-lapse pulsed-neutron logs should be thought of as much more than simple indicators of the presence and migration of CO2. They give important information about migration pathways. They can also help to quantify essential uncertainties on reservoir performance that are difficult to ascertain during evaluation. For example, storage efficiency is difficult to quantify with openhole logs since the formation is initially at zero CO2 saturation. Yet it is one of the keys to determining the ultimate storage capacity of any reservoir. Time-lapse pulsed-neutron logs provide an abundance of information that, when properly history matched, can greatly improve our models of CCS reservoirs to better navigate both the economic and operational risks associated with these projects.

Asphaltene Flow Assurance Risk Evaluation Case Study to Establish Guidelines for CCUS in Arabian Gulf Carbonate Oil Field

Summary In this paper, we present a case study for a comprehensive series of asphaltene flow assurance risk evaluations in the Arabian Gulf Carbonate Oil Field, where CO2 enhanced oil recovery (EOR) is recognized as one of the highest potential technologies for full-field implementation. At first, the sampling location was carefully selected considering the target reservoir’s features because the reliability of asphaltene studies highly depends on sample representativeness. After the quality assurance and quality control of collected samples, asphaltene onset pressures (AOPs) were measured at multiple temperatures under CO2 mixing conditions. The experimental design was optimized in terms of not only improving evaluation accuracy but also minimizing the experimental/sampling cost. The AOP measurements showed clear potential risks associated with CO2 injection. Subsequently, the numerical model analysis was conducted with the cubic-plus-association equation of state model to identify the risk area during CO2 injection. The analysis suggested that risk area is applicable to not only near-wellbore region at the sampling location but also tubing section/surface facility. Furthermore, risk level can be higher at the deeper location of the target reservoir. Finally, CO2-induced asphaltene formation damage risk was investigated from the viewpoints of precipitated asphaltene particle size and pore throat size in the porous media. As a result, the clogging risks from CO2-induced asphaltene were estimated to be high in the target reservoir. By virtue of the comprehensive risk evaluation, the asphaltene flow assurance risk associated with CO2 injection was identified field-wide. The findings from the evaluation encouraged us to move on to future actions, such as more detailed formation damage risk evaluation and mitigation plan development. The extended asphaltene risk evaluation covering the precipitation to deposition phenomena and the reverse engineering for sampling operations based on the experimental design made a worthy demonstration to reduce unnecessary cost and time while obtaining the key information to drive the project. The procedure in this work can contribute to establishing a subsurface part of a guideline for carbon capture, utilization, and storage (CCUS) from the viewpoint of asphaltene flow assurance risk evaluation.

Reduced-Order Models Blend Chemistry, Machine Learning for Water-Property Analysis

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 213869, “Water Digital Avatar—Where Chemistry Is Mixed With Machine Learning,” by Jesse Farrell, SPE, and Sergey Makarychev-Mikhailov, SPE, SLB. The paper has not been peer reviewed. _ Water affects almost every operation in the exploration and production industry. Until now, time-intensive laboratory tests or cumbersome third-party simulators were required to extract physicochemical properties. In the complete paper, a family of machine-learning-based reduced-order models (ROMs) trained on rigorous first-principle thermodynamic simulation results is presented. The developed ROMs that predict water properties enable automated decision-making and improve water-management work flows. The presented approach can be extended to other oilfield, chemical, and chemical-engineering applications. Introduction The properties of the water phase and all produced fluids directly influence flow assurance, three-phase flow pressure/volume/temperature modeling, and fluid-compatibility aspects across the full life cycle of the well, including during well construction, stimulation, and production operations. Modeling these systems enables one to predict, mitigate, and, in some cases, completely prevent deleterious effects in tubing, the reservoir, and near-wellbore regions. First-principle thermodynamic simulations are often considered to be ground truth in the oilfield industry and are widely used in place of time-consuming laboratory experiments. The use of rigorous thermodynamic software, however, is not always practical. In certain cases, commercial and open-source simulators are overloaded with functionality unnecessary for a task, require training of personnel, and are often difficult to incorporate into digital work flows in the cloud or to deploy at the edge on surface equipment or the downhole tools available to model changing conditions in real time. This is where ROMs find their application because they are fast, reasonably accurate, and highly customizable solutions. The authors’ scientific hypothesis was that machine-learning-based ROMs can be used to quantify the physicochemical properties and scaling tendencies of oilfield waters in place of rigorous, first-principle thermodynamic models. Methods The United States Geological Survey (USGS) Produced Waters Geochemical Database was used as the initial data source for this study. The original database contains approximately 115,000 produced-water and other deep-formation water samples collected and characterized in the United States in the past 120 years. Although the USGS database is an excellent source, the data still required cleaning and enrichment. For the first step, inconsistent, poorly populated, and outlier samples were removed, which led to noticeable data attrition and resulted in approximately 85,000 “clean” records. The enrichment phase included several manipulations and alterations of the original data. The resulting data set is not always accurate regarding individual samples but is much better populated than the original one in terms of minor ion concentrations, and is believed to be representative on a large scale.

Analytical expression for the skin factor of the salt deposition zone around a CO[formula omitted] injection well: Extension to the case of ternary miscible displacement

Anthropogenic CO2 disposal in saline aquifers is broadly acknowledged a feasible technique to mitigate climate changes. Scale deposition in the near-wellbore region can however reduce the performance of the CO2 injection wells utilized in the subsurface storage. In this study, we aim at evaluating the rate of salt precipitation and deposition and associated permeability reduction near a CO2 injection well completed in a saline aquifer. We employ a mathematical model of the CO2–H2O–NaCl fluid flow in a porous medium and take into account all relevant phase transitions. Then using a rather simple graphical construction with the fractional flow curve, we present a new analytical solution describing a radial flow of CO2 from the well. We demonstrate under certain assumptions that the solution contains two shocks traveling with a characteristic velocity and a rarefaction between them. The leading shock is the familiar Buckley–Leverett displacement front, whereas the trailing shock bounds the region of halite deposition in the near-wellbore region. We consider this region a skin zone and using the analytical solution, eventually derive a new simple relationship for the skin factor. We show that the skin factor caused by the halite deposition is most sensitive to the brine salinity and the relative permeability of the liquid phase. For particular reservoirs, a rather high value of the skin factor can be reached after injecting just several thousand tons of CO2. We show that the injection into reservoirs characterized by a high brine salinity and a large critical water saturation can cause the skin factor to be as high as four at an early stage of injection and as high as seven at a later stage. The proposed relationship can be useful for an instantaneous quantification of the skin and in reservoir simulations of the CO2 storage.

High-resolution modeling of overflush and its implications for fracture productivity

Hydraulic fracturing operations typically aim to create a highly conductive fracture that will intensify well production or injectivity. At the end of pumping, a fluid without proppant, called flush, is injected to clean the wellbore and tubing of the remaining slurry. Overflush is the situation when flush volume exceeds the volume between the wellhead and perforations so that flush fluid enters the propped fracture and washes out the near-wellbore region of propped fracture. In this work, we examine overflush impact on fracture closure near perforations in detail by considering several overflush scenarios and running simulations using a suite of high-resolution models of fracturing itself, fracture closing on proppant, and productivity. We show that at certain conditions, overflush has no impact on well productivity or may even enhance it. Additionally, we develop a simplified analytical model of well production for an axisymmetric overflushed region and compare the model results to precise numerical simulations. We consider several overflush scenarios, both beneficial and unfavorable. It was found that the dominant role in the formation of overflushed region geometry is that of Saffman–Taylor instability, the manifestation of which leads to the formation of long channels that with high possibility do not cause fracture closure with pressure decrease during production and can remain open even at large pressure drawdown. The work has both research and practical interest and demonstrates an integral approach to numerical overflush modeling. In addition, it gives basis for the revision of the existing “harmful overflush” paradigm.

Numerical modeling of near-wellbore diverter bridging in hydraulic fracturing

In this work, we used a particle transport model integrated into the fluid solver in FLAC to simulate the transport of particles in the near-wellbore region inside a hydraulic fracture. Complex flow behaviors, including divergent flow near the fracture entrance and detouring flow around diverter packs, can be captured in this coupling system. In the numerical implementation, the coupled fluid flow and particle transport are realized by updating the fracture permeability, particle concentration, and velocities of fluid and particles in each time step. Simulation results indicate that the final shape of the particle bridging zone at the near-wellbore region is determined by the flow-driven and settling-driven particle transport. A continuous bridging band initially forms at the bottom region of the fracture, then the fluid-driven particles move upwards to block the top region of the fracture. Lastly, a V-shaped bridging band is formed inside the fracture. It is observed that high initial particle concentration and large particle size result in the creation of a small-scale bridging band near the injection entrance, which promotes the rapid growth of the closed bridging band and high-pressure buildup.

Effect of initial water saturation on the performance of fracturing fluids with and without polyallylamine under simulated EGS conditions

Objectives/scopeStimuFrac (US Patents 9,873,828 B2 and 9,447,315 B2), a CO2-reactive polymer aqueous solution [polyallylamine (PAA) 1wt% in water] combined with CO2, can potentially be used as a less water-intensive fracturing fluid for enhanced geothermal systems (EGS). Our previous results show that in hot dry rock (HDR), PAA/CO2 fracturing fluids outperformed other fluids such as water, CO2, and CO2/water in generating large fractures with less fluid consumed. The objective of this work is to investigate the effect of initial water saturation on the performance of StimuFrac by conducting hydraulic fracturing tests with ½ foot cubic rock samples held under representative EGS stress/temperature conditions and by using cyclic injection strategies (under constant injection rate). The resulting fracture hydraulic conductivities, breakdown pressures, and volumes of fluids required are compared. Methods/procedures/processTo simulate geothermal reservoir conditions, in all tests, the rock sample was held under triaxial confinement and at 200 °C, and different volumes of water were initially injected into the rock sample before any fracturing processes were initiated. For the single-cycle PAA (or water) alternating CO2 (PAG or WAG) injection fracturing experiments, one complete cycle consisted of two steps: (1) injecting a PAA slug (or water slug) followed by (2) injecting CO2 to initiate and propagate the fracture. For experiments involving multiple injection cycles, the CO2 injection pressure is increased until it peaks and begins to decline (indicating fracture initiation at this moment), and then continued being injected for another 30 s to propagate the fracture. Then, these two-step cycles [injection of PAA (or water) followed by CO2 injection (up to 2–4 mL/min)] are repeated. Applications/significance/noveltyThe results of this study suggest that water saturation significantly affects the fracturing fluid transmission into the rock pore space, thus affecting fracture initiation and propagation. In this study, fracturing tests via a single injection cycle or multiple injection cycles were performed. When the rock samples are split in half following testing, it is evident that fracture propagation is considerably restricted under high water saturation conditions (where a three-day initial water injection was conducted) in comparison to stimulation experiments carried out in hot and dry rock. The fractures propagate less than 1/3 of the distance from the wellbore to the outer rock surface, and in some cases, no fracture is generated. This may be caused by leak-off dominating the fracturing process and the fluid injection rate is insufficient to overcome leak-off, even under high injection rate conditions. Additionally, CO2 could be leaking off into the wellbore annulus and this may be making it more difficult to generate sufficiently high-pressure gradients away from the near-wellbore region. Under low water saturation conditions (dry rock or after 1-day initial water injection), PAA/CO2 consistently generated significantly larger fractures compared with the other fluids. CO2 generated large fractures only in the hot dry rock and only when using high injection rates, though data variability is high.

Permanent Fiber-Optic DTS Evaluates Production Enhancement

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 31654, “Production Enhancement Evaluation Through Permanent Fiber-Optic Distributed-Temperature-Sensing Interpretation for a Gas-Lifted Producer in Field B, Offshore Malaysia,” by Chang Siong Ting, Nur’ain Minggu, and Dahlila Kamat, Petronas, et al. The paper has not been peer reviewed. Copyright 2022 Offshore Technology Conference. Reproduced by permission. _ In the complete paper, the authors evaluate the effectiveness of production-enhancement activities for Well B Long-String (i.e., Well BL) using distributed-temperature-sensing (DTS) technology. Installation of permanent fiber-optic cable across the reservoir sections has enabled gas-lift monitoring, identification of well-integrity issues, and zonal inflow profiling from perforation contribution. The effectiveness of executed remedial jobs is described along with findings and interpretations of DTS results. Field and Well BL Background Field B is a mature brownfield 45 km offshore east Malaysia in a water depth of approximately 230 ft. The field’s structure has a gentle rollover anticline with a collapsed crest caused by growth faulting. The reservoirs were deposited in a coastal shallow marine environment with channels. The production wells completed in these reservoirs were completed with internal gravel packs. The typical completion types for wells in Field B are dual strings with sliding sleeve doors (SSD), intended for commingled production from the multilayered reservoirs. Most of the wells in Field B were installed with permanent downhole gauges (PDGs), and five wells were equipped with permanent DTS across the reservoir section. The well was completed in 2015 as a gas-lifted dual-string producer with a 3½-in. completion string for short string (BS) and 3½×2⅞-in. tubing crossover for long string (BL). The long string of Well B also produces from two zones, Zones 2 and 3, while the short string of Well B produces from only one zone, Zone 1. Each zone consists of sublayers. In addition, DTS fiber-optic cable was installed along the long string across the reservoir sections in Well BL, and the system enabled the operator to monitor continuously the wellbore temperature across all producing intervals. Each zone also was equipped with a zonal PDG (temperature and pressure) and SSDs. DTS System The double-ended DTS system was installed permanently across the multilayered reservoir in Well BL to measure the dynamic change of temperature in the near-wellbore region over time. Double-ended temperature measurement was used to correct for differential light losses (light-loss correction) that appear gradually over the lifetime of the fiber as its quality is degraded because of hydrogen darkening or exposure to high temperatures. This measure improves the quality and accuracy of the measurement signal backscattered to the surface receiver for processing. With double-ended DTS, small thermal changes over time in the well can be tracked. Temperature measurements are detected in 1.6-ft intervals along the length of the cable. This generates a profile of temperature effects along the production string by analyzing backscattered Raman wavelength light from a pulsed laser source. This DTS measurement allows continuous monitoring of production events as they happen.

"Ladetes"-A novel device to test deformation behaviors of hydrate-bearing sediments.

Natural gas hydrate (NGH) exploitation is severely restricted by geotechnical problems. Deformation behaviors of the hydrate-bearing strata (HBS) control the occurrence and evolution of geotechnical problems during extracting natural gas from HBS. In this paper, a novel approach named Ladetes is introduced to evaluate the lateral deformation behaviors of the near-wellbore and fracture-filling regions of the HBS. The pressuremeter test and the flat dilatometer test are designed to simulate the inner boundaries of an NGH-producing well and an artificial stimulation fracture for the first time. The device can realize the in situ hydrate formation prior to the experiment and axial loading application throughout the experiment. Both the strain control mode and the stress control mode can be achieved to estimate the deformation characteristics of HBS under different downhole conditions. Prime experiments proved their adaptability and reliability. The Ladetes provides an effective and alternative way of obtaining geotechnical parameters for HBS.

Salt precipitation in carbonates during supercritical CO2 injection: A pore-scale experimental investigation of the effects of wettability and heterogeneity

Salt precipitation in near-wellbore regions of subsurface reservoirs is a significant phenomenon that may occur during carbon dioxide (CO2) injection for carbon sequestration and enhanced oil recovery. It induces pore plugging, which causes reductions in porosity and permeability and hence well injectivity. Previous research in this area focused predominantly on salt precipitation in fully brine-saturated media, such as those found in deep saline aquifers. However, studies on salt precipitation in hydrocarbon reservoirs where brine and oil coexist are rare, particularly at the pore scale. In this study, we elucidate the occurrence and dynamics of salt precipitation at the pore-scale during supercritical CO2 injection into depleted carbonate and sandstone oil reservoirs at elevated temperature and pressure conditions. Specifically, we examine the influence of wettability and morphological heterogeneity on salt precipitation evolution and dynamics. Investigations on the influence of wettability reveal that the time required for the initiation of precipitation is shorter for an intermediate-wet carbonate compared to that for a weakly oil-wet carbonate. Relatively higher amounts of salt deposits are formed in the more hydrophilic (intermediate-wet) carbonate, leading to an intensification of porosity reduction in this rock. In addition, the presence of oil within the pore space does not hinder the precipitation process but suppresses the reverse flow of solutes toward the evaporation front, thereby creating localized precipitation at the front. The level of heterogeneity affects the precipitation initiation and its duration as well as the amount of precipitates formed, with lower salt saturations encountered in the less heterogeneous sandstone compared to the more heterogeneous carbonate. Heterogeneity also influences the salt cluster size distribution within pore elements such that, for the same wettability state, medium-sized clusters dominate in sandstone, while large clusters are the main contributors to the total salt volume in the more heterogeneous carbonate. This study forms a fundamental basis for the prediction of salt precipitation during three-phase flow processes induced by supercritical CO2 injection into porous media containing high-salinity brine and oil.

INVESTIGATION OF CLAY STABILIZER POTENTIAL FOR HIGH CLAY CONTENT FORMATION

Clay swelling has been studied for decades due to its damaging problem in the reservoir. It has caused permeability impairment due to blockage at the pore throat and reduction of the available pore spaces in the reservoir. The past few decades have seen rapid development of clay stabilizers to treat clay minerals near-wellbore region areas. However, there a limited study investigating the potential of clay stabilizers to prevent clay swelling throughout the reservoir. The present study aimed to investigate the potential of potassium chloride (KCl) and Poly-diallyldimethylammonium chloride (PolyDADMAC) as cationic clay stabilizers to mitigate the clay swelling phenomenon throughout the reservoir. This study conducted a series of free swelling tests on bentonite with varying brine salinity and clay stabilizer concentration. In addition, the rheological properties of KCl and PolyDADMAC were measured at 24°C and 98°C and at a 7.34 s–1 shear rate to determine its flow potential throughout the reservoir. The results showed that 0.3 wt.% to 1.5 wt.% of KCl and PolyDADMAC were able to control the expansion of bentonite immersed in an aqueous solution, with PolyDADMAC has shown excellent performance, whereas the bentonite expansion in PolyDADMAC solution is significantly lower than KCl. This result is driven by the fact that PolyDADMAC has greater amounts of cationic charges to neutralize abundant negative charges on clay mineral surfaces. Furthermore, the viscosity of 0.3 wt.% to 1.5 wt.% of KCl and PolyDADMAC at 24°C and 98°C recorded is low, which is 0.25 cP to 1.45 cP and 0.83 cP to 2.32 cP respectively. This low value proves its potential to be penetrated throughout the reservoir, not limited to near the wellbore region only.
 Keywords: Cationic clay stabilizer, salinity, bentonite swelling, viscosity

Diagnostic Tool for Unconventionals Evaluates Near-Wellbore Fractures

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper URTeC 2021-5408, “New Fracture Diagnostic Tool for Unconventionals: High-Resolution Distributed Strain Sensing by Rayleigh Frequency Shift During Production in Hydraulic Fracture Test 2,” by Gustavo A. Ugueto, SPE, Shell; Magdalena Wojtaszek, SPE, Brunei Shell; and Somnath Mondal, Shell, et al. The paper has not been peer reviewed. _ Fiber-optic (FO) monitoring in unconventional reservoirs has proved to be an invaluable diagnostic tool. Unfortunately, gaining detailed understanding of the near-wellbore fracture geometry or cluster or stage productivity through FO has proved to be more difficult. A new FO diagnostic method, distributed strain sensing based on Rayleigh frequency shift (DSS-RFS), provides insights about the characteristics of the near-wellbore-region (NWR) during production. The authors write that this novel FO technique can significantly improve understanding of near-wellbore hydraulic fracture characteristics and the relationships between stimulation and production from unconventional oil and gas wells. Introduction Successful production profiling through distributed acoustics sensing (DAS) has been reported in gas-producing wells. Regrettably, many wells do not generate strong DAS signals while flowing. Recently developed FO production-profiling data-acquisition protocols and work flows rely on collecting signals during short shut-in reopening cycles lasting only a few minutes. Therefore, a need exists to develop new work flows and algorithms using high-fidelity FO data that can be related to the production characteristics of individual perforation clusters (PCs). DSS-RFS Method DSS-RFS uses Rayleigh backscatter in a nonengineered single-mode fiber to measure strain changes along the fiber. When an optical fiber is manufactured, random inhomogeneities of the glass density are created in the fiber core. The random density heterogeneities manifest as a variation of refractive index along the fiber. For a certain laser frequency, the interferences between the Rayleigh backscatters cause irregular but unique amplitude fluctuations in the coherent optical time-domain reflectometer along the fiber length. For each discrete fiber segment, a unique Rayleigh scattering spectrum is obtained by scanning the fiber with a coherent optical time-domain reflectometer with a range of laser frequencies using a tunable-wavelength laser system. This unique Rayleigh scattering spectrum shifts in frequency if the temperature or strain of the fiber section changes. DSS-RFS measures relative strain changes instead of absolute strain along the fiber. However, DSS-RFS has a higher measuring sensitivity than strain measured using Brillouin optical time-domain reflectometry. DSS-RFS has higher spatial resolution than low-frequency DAS. Finally, DSS-RFS does not have the fiber sensing length restrictions of commercially available fiber-Bragg-grating-based DSS systems. First DSS-RFS During Shut-in and Reopening Test In February 2020, DSS-RFS data was acquired at one of the two FO-instrumented wells in Hydraulic Fracture Test Site 2 (HFTS2). The spatial resolution of the measurement was 20 cm, with a time-sampling interval of 150 seconds. The test began after establishing a baseline measurement during normal flowing conditions. The well was shut in for 4 days and opened again in a series of 2-hour shut-in and 1-hour producing cycles. Finally, the well was reopened and DSS-RFS was acquired for approximately 6 hours. This DSS-RFS data allowed for the definition of intervals where extension has occurred corresponding to active clusters with positive strain-change signals, slightly compressed intervals with negative strain-change signals between the clusters, and intervals with inactive clusters. These signals were interpreted to be caused by fracture-aperture changes that, in turn, were caused by pressure increases during shut-in within the fracture network in the NWR.