Fig 9- - uploaded by Bernardo Coutinho
Content may be subject to copyright.
Similar publications
Citations
... Conventional techniques of rock classification in heterogeneous carbonate rocks depend on the integration of core-scale measurements and well logs (Ramakrishnan et al., 2001;Skalinski et al., 2006;Skalinski et al., 2009). Researchers qualitatively integrate routine core analysis (RCA) data, special core analysis (SCA) data, mercury injection capillary pressure (MICP) data, petrographic examinations using thinsection images, whole-core computed tomography (CT) scan, core photos along with advanced well log data including elemental capture spectroscopy (ECS) logs, NMR T 2 logs, and image logs for improvising rock classification efforts in heterogeneous carbonates (Gonzalez and Heidari, 2022;Cantrell and Hagerty, 2003;Boyd et al., 2015). The goal of integrating the aforementioned diverse data types is to characterize and quantify spatial variations in intricate pore networks, complex mineralogy, depositional, and diagenetic attributes. ...
Reliable rock classification is important for estimating petrophysical properties and making informed production decisions. High-resolution image data (e.g., image logs, core photos, and CT-scan images) can enhance rock classification by incorporating rock fabric (i.e., spatial variations of rock components) information. The additional value that image data contributes to enhancing formation evaluation is essential to assess for making informed decisions on acquiring expensive image data. Recently developed methods have been proven successful for image-based rock classification mainly in siliciclastic formations. However, the reliability of image-based rock classifications in heterogeneous carbonate formations comprising complex depositional sequences has yet to be investigated. The objectives of this paper are (a) extracting rock textural features to obtain image-based rock classes from high-resolution images that capture changes in depositional sequences of complex carbonate formations, (b) assessing the impact of different sources of image data on the enhancement of rock classification, and (c) evaluating the reliability of rock classes identified by integrating well logs and image data and its impact on formation evaluation. First, we conduct conventional well-log interpretation and preprocess the image data (i.e., CT-scan images, core photos, and image logs) using the image masking techniques to remove artifacts and noise from the available images. Then, we extract textural features from wellbore/core image data using a gray-level co-occurrence matrix (GLCM) algorithm that captures the spatial relationship of pixel intensity values in images to quantify rock fabric. Next, we adopt an unsupervised algorithm to detect rock classes using the extracted features. We perform and compare rock classification through three different methods taking as inputs: (a) only conventional well logs, (b) different sources of image data (i.e., image logs, core photos, and CT-scan images), and (c) the integration of conventional well logs and image data. Finally, we compare the outcomes of these three methods and their impact on assessing petrophysical properties. We applied the proposed workflow on image data (i.e., CT-scan images, core photos, and image logs) and well logs in a pre-salt carbonate formation having a complex syn-depositional rock texture and pore system altered by a diagenetic process. The rock classes obtained by high-resolution core photos were more successful in detecting the post-depositional features in heterogeneous carbonates than rock classification using other sources of image or well-log data. The contribution of image data was more measurable in rock classes with higher levels of heterogeneity and spatial variations of rock fabric. The outcomes of this work are (a) to capture changes in depositional sequences of heterogeneous carbonate formations in rock classification, (b) to assess the impact of different sources of image data (i.e., CT-scan images, core photos, and image logs) on rock classification efforts of complex carbonate formations, and (c) to enable taking decisions on the optimum type of image(s) for image-based rock classification that best captures rock fabric information in a given formation.
... This same approach was then used to build an absolute permeability model. It didn't take long for the petrophysicists to realize that one of the best measurements for representing matrix porosity was the Nuclear Magnetic Resonance logs (NMR) (Boyd et al., 2015). Consequently, this data became the primary log suite used for that purpose at every stage, from well scale up to geocellular models of the field (Burgoa Tanaka et al., 2022;Menezes de Jesus et al., 2019). ...
... • Phiden (var clean) -Variable Density porosity cleana combination of Phiden(var) and Phison(var), given that Phison (var) is used when the amount of the mg − pore log (obtained from BHI) exceeds Phiden (var); NMR logs became widely used for porosity estimation in pre-salt reservoirs (Boyd et al., 2015) due to the understanding that they could provide a reliable direct estimation of matrix porosity. One convenient aspect is that fixed cutoffs for the T2 relaxation spectrum can be utilized to estimate different pore volumes, which can be used for water saturation and permeability estimation (Coates et al., 1999). ...
... In Brazilian pre-salt carbonates, the conventional interpretation remains applicable both for oil-based muds (OBM) and water-based muds (WBM) in intervals where matrix porosity dominates. It is assumed that the mud filtrate behaves similarly to pre-salt light oils, with high bulk relaxation values around 500 ms (Boyd et al., 2015;Victor, 2017), as depicted in Figure 4. ...
The dynamic impact of the extra-matrix pore systems in Brazilian pre-salt carbonate reservoirs has driven the development of new techniques and workflows for their characterization. The presence of large-scale and well-connected pore systems can significantly influence various processes, from drilling and completion efficiency to flow modeling and history matching. Characterizing these systems requires a specific type of modeling that is based both on measurements and assumptions, as the pore network geometry extends beyond the well and resides in an intermediate scale between well logs and seismic data. Borehole image logs, although not fully capturing this pore scale, provide the most representative detection of these systems. Consequently, quantitative analysis of these structures based on borehole image logs became mandatory for pre-salt carbonate projects. In these reservoirs , porosity, and permeability models from the well to the field scale have been built by integrating attributes extracted from borehole image logs, conventional petro-physical log suits, routine core analysis and permeability estimations based on drill stem test measurements. However , the traditional petrophysical logs used for modeling the matrix porosity partially detect the extra-matrix pores system, even after proper environmental corrections. As a result, the logs typically used to characterize the matrix porosity are consistently contaminated by a mixture of pore volumes that actually belong to different pore types and scales, each with distinct flow behavior. In this study, a comparative analysis of the different poros-ity logs acquired in pre-salt karstified carbonate sections is conducted to isolate the extra-matrix pore systems and characterize the matrix porosity more precisely. The decomposition of the T2 spectrum into log-normal base functions is considered the most accurate method for representing matrix porosity, as it separates the mud signal detected in large cavities from the relaxation of the matrix pore volumes. Conversely, the quantitative analysis of the borehole image logs must be used to represent the extra-matrix porosity. By separating the effects of mega and giga pores on porosity logs, it becomes possible to model parts of the reservoir that are expected to behave as standard porous media, while treating the large-scale pore system with different mathematical representations. A sensitivity analysis was performed on a 3D model to demonstrate the impact on STOOIP under three scenarios: one with the ideal matrix porosity log, another one with the NMR porosity log contaminated by extra-matrix pore volume, and another considering the sum of ideal matrix porosity and extra-matrix porosity. The extra-matrix pores in karstified reservoirs do not flow like traditional porous media and can significantly impact project scope and field productivity as they may channel fluids and cause early breakthrough of gas or water, due to their high permeability. Hence, it is essential to represent these systems as accurately as possible. This approach aims to determine the best practices for representing poros-ity in karstified reservoirs while separating contaminated and non-representative measurements generated by large-scale pores in direct porosity tool readings, leading to more predictive models.
... The mineralogy of pre-salt carbonates primarily consists of calcite, dolomite, quartz, and magnesium-rich clays like stevensite (Boyd et al., 2015;Amosu and Sun, 2018;Michelena et al., 2020). This study utilizes the multi-mineral inversion approach, which has been validated by spectroscopy well logs and X-ray Diffraction ( ) data, for the purpose of mineral identification. ...
... The quality of the Barra Velha carbonates is influenced by secondary porosity, including fractures, molds, and vugs, resulting in porous intervals of varying thicknesses (Boyd et al., 2015;Hosa et al., 2020;Lima et al., 2020;Mohammadizadeh et al., 2021;Wagner Lupinacci, 2015). The substantial rates of fluid flow within the Barra Velha Formation ( ) are predominantly attributed to vuggy dolomitized carbonates present in diverse lacustrine facies, such as coquinas, stromatolites, and travertine shrubs (Boyd et al., 2015;Hosa et al., 2020;Lima et al., 2020;Wagner Lupinacci, 2015). ...
... The quality of the Barra Velha carbonates is influenced by secondary porosity, including fractures, molds, and vugs, resulting in porous intervals of varying thicknesses (Boyd et al., 2015;Hosa et al., 2020;Lima et al., 2020;Mohammadizadeh et al., 2021;Wagner Lupinacci, 2015). The substantial rates of fluid flow within the Barra Velha Formation ( ) are predominantly attributed to vuggy dolomitized carbonates present in diverse lacustrine facies, such as coquinas, stromatolites, and travertine shrubs (Boyd et al., 2015;Hosa et al., 2020;Lima et al., 2020;Wagner Lupinacci, 2015). The diagenesis process affects layers that would normally have low porosity and permeability at such depths (4.5 to 6 km) and the observed high porosities are likely influenced by diagenesis (Boyd et al., 2015;Quan et al., 2023). ...
In complex carbonate reservoirs, it is crucial to understand the connections between reservoir compositions (minerals, facies, and properties). Conventionally, core samples have been used to measure reservoir parameters and identify minerals and facies. However, core samples are limited to certain wells. Therefore, additional techniques are necessary to overcome this limitation comprehensively. This study aims to identify key mineralogical and facies components of the Barra Velha Formation (BVF) and their relation to reservoir parameters. Dolomite, calcite, quartz, and clay minerals were commonly found using X-Ray Diffraction (XRD). By employing multi-mineral (MM) petrophysical evaluations, we accurately recreated mineral quantities from XRD and petrophysical properties from core analysis to ensure reliability. Replications of inputs well logs and the mineralogical volume from spectroscopic (ECS) were used as reliability techniques for validating the MM. A total of 47 wells were analyzed using those methods. In this study, the classification of facies was accomplished through the selection of three prominent supervised artificial intelligence techniques, among which SOM, a widely employed method for facies estimation, was included. Additionally, the ensemble methods of Random Forest and XGBoost were adopted due to their recognized efficacy in handling tabular data and their track record of success in machine learning and artificial intelligence competitions. Remarkably, the performance evaluation revealed that Random Forest and XGBoost algorithms outperformed SOM, yielding the most favorable outcomes in this context. An integrated analysis of mineralogical and facies results was conducted, incorporating production data and special profiles such as nuclear magnetic resonance (NMR) and Wellbore Image (WBI) to identify vug-containing areas. The dolomitic facies exhibited favorable reservoir qualities, influenced by diagenetic processes represented by vuggy porosity, which enhanced permeability. Shrubstones, spherulites, and reworked facies showed superior petrophysical qualities and were connected with productive regions, leading to elevated dolomite concentrations, and vuggy abundance. The study highlights two major innovations: the use of mineralogical volume from multi-mineral assessments as inputs for AI-based property estimation to improve facies estimates, and the discovery of relationships between facies, minerals, and reservoir properties, compared to production data. This understanding allows for more accurate static model creation, optimal production interval selection, improved hydrocarbon recovery, and better specification of stimulation processes.
... Integrating petrophysical methods over multiple scales is necessary in order to maximise the capture of heterogeneities . Nuclear magnetic resonance (NMR) logging is one of the preferred methods for porosity measurement in reservoirs due to the techniques relative insensitivity to changes in mineralogy and its reliability in estimating permeability (Boyd et al., 2015). Nuclear magnetic resonance, after calibration with laboratory measurements, consequently plays a central role in addressing complex pore geometries and other heterogeneities, certainly in combination with X-ray computed tomography (XCT; Alabi et al., 2014;Belila et al., 2020;Chitale et al., 2014;Diniz-Ferreira & Torres-Verdín, 2012). ...
... Adapted FFI/BVI T 2 cut-offs for different petrophysical sample types are expected to strongly improve NMR based permeability estimations. Boyd et al. (2015) analysed the NMR response of oil-wet carbonates in Presalt core samples, oil samples and oil-based mud filtrate at downhole conditions. The authors showed that laboratory measurements are crucial in understanding how varying wettability and surface relaxivity affect the NMR T 2 response. ...
Applying an integrated methodology, including petrography, Mercury Injection Capillary Pressure, laboratory Nuclear Magnetic Resonance and X‐ray Computed Tomography, on continental spring carbonate reservoir analogue samples is a prerequisite to understand plug scale porosity and permeability heterogeneities. Depending on the dominant pore type in a sample, the orientation and distribution of the pores, pore network connectivity varies from poor to excellent in these continental spring carbonates. The latter exhibit large‐scale ranges for both porosity (3‐25%) and permeability (0.004‐3,675 mD). Facies classification alone proved insufficient to link porosity and permeability, due to intrafacies pore network variability. Better assessment of reservoir properties can be achieved by subdividing facies into lithotype and pore type classes. Obtained pore network data addresses the pore types, pore (throat) sizes, number of pore compartments, and allow a subdivision of the pore size distributions into unimodal, bimodal and atypical types. There is no micropore compartment present in samples with unimodal Mercury Injection Capillary Pressure and Nuclear Magnetic Resonance distributions. Decoupled micropore compartments are observed in samples with bimodal Mercury Injection Capillary Pressure and Nuclear Magnetic Resonance distributions, which show isolating calcite rims, and have limited permeabilities. The cement rims decrease the macropore connectivity and decouple the micropore compartments, which reside in micritic dendrites. The micropore compartment (r < 1 µm) is coupled with the mesopore (r = 1‐15 µm) and macropore compartment (r > 15 µm) for atypical samples which lack pore‐lining calcite rims.
... There has been several interests in the facies classification of the lacustrine sediments of the presalt (Boyd et al, 2015;Okubo et al, 2015;Zalan, 2016;Carlotto et al, 2017;Faria et al, 2017; Ribeiro da Silva and Pereira, 2017;Rodriquez et al, 2017;Vincentelli et al, 2017;Wright and Barnett, 2017;Chaves, 2018;Muniz and Bosence, 2018;Aizprua et al, 2019;Althaus et al, 2019;Farias et al, 2019;Jesus et al, 2019;Pecanha et al, 2019;Amarante et al, 2020;Basso et al, 2020;Chinelatto et al, 2020;Gomes et al, 2020;Leite et al, 2020;Rebelo et al, 2020). ...
... CaCO3, while travertine is associated with geothermal water charged with calcium and bicarbonate in solution reaching the surface and precipitating around vents (Riding, 2000;Boyd et al., 2015). ...
... reservoir quality, however, these facies are normally not as productive as the stromatolites, travertines, coquinas and reworked deposits (Boyd et al., 2015). with the standard siliciclastic and carbonate rock classifications (Tucker 1982). ...
A DIRECTED STUDY REPORT SUBMITTED TO THE FACULTY OF MECHANICAL ENGINEERING, STATE UNIVERSITY OF CAMPINAS, SAO PAULO.
... Os microbialitos do Pré-sal são heterogêneos, estratificados, altamente permeáveis, possuem qualidade de reservatório variável e colunas de óleo superiores a 200 m (BOYD et al., 2015). Nos últimos anos, pesquisadores tem buscado compreender como os constituintes primários do arcabouço e a diagênese impactaram no sistema poroso dos carbonatos do Pré-sal da Bacia de Campos, fornecendo informações petrofísicas relacionadas a porosidade e permeabilidade destes reservatórios (HERLINGER et al., 2016;DE ROS, 2017;LIMA;DE ROS, 2019;(MACHADO et al, 2012). ...
... Nos últimos anos, pesquisadores tem buscado compreender como os constituintes primários do arcabouço e a diagênese impactaram no sistema poroso dos carbonatos do Pré-sal da Bacia de Campos, fornecendo informações petrofísicas relacionadas a porosidade e permeabilidade destes reservatórios (HERLINGER et al., 2016;DE ROS, 2017;LIMA;DE ROS, 2019;(MACHADO et al, 2012). Para a Bacia de Santos raros trabalhos fazem alusão às condições permo-porosas destes reservatórios, acrescentando poucas informações acerca da quantificação das propriedades petrofísicas e a sua correlação com as facies sedimentares (BOYD et al., 2015). MOREIRA et al. (2007). ...
... Lula Field (formerly known as Tupi area) was the second discovery of SBPSC (in September 2006) and is believed to hold potential recoverable volume up to 8.3 billion barrels of oil equivalent (Filho et al., 2015). According to the study of Boyd et al. (2015), Pre-Salt carbonate wells of Lula Field are currently producing high quality oil (e.g., 28 to 30° API) at an average rate of 30,000 BOPD. These high flow rates can be explained by the primarily flow from vuggy carbonates, which can occur in a variety of lacustrine facies, such as coquinas, stromatolites and travertine shrubs. ...
Pre-salt carbonate reservoirs are known by their huge heterogeneity and their porous system present a challenge regarding reservoir characterization, petrophysical parameters analysis and full understanding of fluid flow dynamics. Besides that, the cost of obtaining rock samples from the reservoir and the destructive nature of most experimental tests increase the interest in develop the concept of Digital Rock Physics (DRP); DRP is based on high resolution imaging and three-dimensional digitizing aiming to investigate and calculate the physical and fluid flow properties of the porous media. In this approach, this work uses X-Ray computed microtomography, digital reconstruction and image processing to achieve the 3D modeling of porous media and estimate petrophysical parameters of Pre-Salt lacustrine carbonate analog samples: coquinas from Morro do Chaves Formation, Northeast Brazil. Experimental data is used to validate the predictions. The results suggest that an important step in the rock digital reconstruction refers to the segmentation process and the high computational cost is a limiting factor to generate the porous media model in three dimensions. Despite this, the estimated physical properties are in good agreement with the previous measured experimental values and the generated 3D model will be widely used in numerical flow simulations in the next steps of this study.
... We have noted that carbonate and sulfate minerals were supersaturated. Therefore, we forced the precipitation of calcite and anhydrite because these minerals have been observed in the Lula Field (Boyd et al. 2015 ). Moreover, because there was no information in the literature about the H 2 S content, FeS precipitation was not considered, and, therefore, we concentrate our analysis on the precipitation of CaCO 3 during depressurization along the production tubing. ...
Vapor/liquid-equilibria (VLE) calculations, particularly involving the phase behavior of carbon dioxide (CO2) and hydrogen sulfide (H2S), are used in scale-prediction modeling. In this work, the impact of VLE calculations for CO2- and H2S-rich gas phases and for acid- and sour-gas mixtures on scale-prediction calculations is evaluated.
Three equations of state (EOSs)—Soave-Redlich-Kwong (SRK) (Soave 1972), Peng-Robinson (PR) (Peng and Robinson 1976), and Valderrama-Patel-Teja (VPT) (Valderrama 1990)—are implemented in the Heriot-Watt model and used in VLE calculations. The solubility of single-component CO2 and H2S in water and the solubility of a gas mixture in water were compared with experimental data in terms of the absolute relative deviation (ARD). The solubility data were then used in PHREEQC (USGS 2016) to calculate the impact of using different EOSs on carbonate and sulfide scales, particularly on calcium carbonate (CaCO3) and iron sulfide (FeS).
Average ARDs of 6.04, 4.10, and 3.77% between experimental and calculated values for CO2 solubility in water were obtained for the SRK, PR, and VPT EOSs, respectively. Similarly, for H2S solubility in water, average ARDs of 6.49, 6.66, and 6.48% were obtained for each EOS, respectively. For the solubility of sour- and acid-gas mixtures in water, average ARDs of 13.92, 13.25, and 10.78% were obtained, respectively. It has thus been concluded that the VPT EOS performs better than the SRK and PR EOSs in VLE calculations for the analyzed data.
The errors introduced in VLE calculations have been found to impact the calculation of the amount of CaCO3 precipitated, with consequences for scale-inhibitor selection. Higher deviations were found in the amount of CaCO3 precipitation for gas mixtures when compared with a single-component, CO2-rich phase. Furthermore, the large errors occurring in VLE calculations for H2S solubility have not been found to impact the calculation of the amount of FeS precipitated when H2S is in excess with respect to Fe2+. In addition to this, a case study that was performed by use of formation-water data from the Brazilian presalt revealed that the choice of EOS can cause errors of 6 kg of precipitate during each day of production.
Scale-prediction calculations carried out with PHREEQC demonstrate that VLE calculations can have a high impact on mineral precipitation. Thus, it is recommended that the best VLE model available should always be used for scale-prediction modeling, particularly when mixtures of gases are present.
... Rao (1996) published a review on the influence of temperature on wettability of substrates which indicated that wettability of sandstones and quartz substrates would shift to a more oil-wet state with increasing temperature and carbonates would become less oil-wet with increasing temperature, therefore the results obtained in this stage of the work are in agreement with the literature. The practical outcome suggested by these results is that at reservoir temperature, should the porous media contain calcite and silica (as the Pre-Salt fields (Boyd et al., 2015)), the wettability of the system would likely assume a mixed-wet state. Obviously, this is a hypothesis because the contact angle tests were performed in flat surfaces without the presence of capillary forces, however it is a starting point. ...
... The same experiments were also performed for quartz substrates, given that pre-salt rocks can be highly heterogeneous in some fields and contain some silica in their composition (Boyd et al., 2015). Figure 7 displays the results of equilibrium contact angles for the system of recombined Crude_BFW_aged quartz at: 1. P = Pamb , T = Tamb; 2. P = 1000 psi, T = 60°C (after contact angle had been established without any CO2, a CO2 gas cap was injected); 3. P = 1000 psi and T = 60°C (with all the fluids pre-equilibrated prior to the start of the experiment). ...
Pre-Salt carbonates are the greatest oil reserves discovered in the last decades and are expected to play a major role in the Oil and Gas Industry due to their volume and quality of the oil. It accounts for more than 20% of the oil production in Brazil, and it is expected to become more important in the future. However, carbonates reservoirs with high salinity and hardness have not been studied in depth, especially with respect to the description of reservoir wettability, a characteristic that dictates the distribution of fluids in the pore spaces and the multiphase flow in the pore network. Understanding the interaction between the fluids and the rock, therefore being able to investigate the initial wettability of the reservoir, is fundamental for the correct interpretation of the capillary pressure and relative permeability curves which govern the flow and displacement of oil and water in porous media. This work aims to describe and discuss experimental results related to COBR (crude oil-brine-interactions) interactions between a recombined crude oil with similar characteristics to that present in the pre-salt reservoirs, the formation water within them, and model rocks, calcite and quartz. The influence of dissolution of carbon dioxide (CO2) in the system was also assessed. To achieve these objectives, contact angle experiments were carried out both at ambient conditions and at pressure of 6.8 MPa (1000 psi) and temperature of 60°C.Two sets of experiments were carried out at high-pressure, one in which the oil had not been previously saturated with CO2, the other in which the oil was fully saturated with CO2 at test conditions. At ambient conditions, a dynamic test was also performed to investigate the effect that injection of a de-sulphated seawater sample would have on the contact angle between the crude oil, brine and rock. It was observed that on unaged substrates there is adhesion of the Brazilian recombined oil and the substrates used in formation water indicating the ability of the oil to change the wettability of the rock from its initial water-wet state. Furthermore, after ageing took place calcite presented contact angles in the range of oil-wet rock (average of 130°) and quartz had contact angles in the range of neutral/mixed-wet conditions (average contact angle of 90°). After dynamically replacing the formation water by the de-sulphated seawater, no major changes in contact angle were seen for both system. At higher temperature (60°C), calcite presented contact angles in the neutral wet range, and the average contact angle for the quartz substrates at 60°C increased from 85° to 135, indicating that the composition of the crude oil is particularly important for the establishment of initial wettability of the system. In CO2 pre-equilibrated systems, both calcite and quartz presented contact angles in the range of neutral-wettability, pointing that CO2 influences the establishment of initial wettability. The results provide important insights into the state of wettability of the pre-salt fields and the impact of important pertinent parameters on wetting characteristics of these reservoirs which would be needed for assessment of pre-salt fields and for design of associated coreflood experiments.
Drilling offshore pre-salt reservoirs offshore Brazil with water-based drill-in fluids (WB DIF) represents a challenge. The system must be reservoir friendly, lubricious, and capable of withstanding high differential-pressures in heterogeneous carbonate sections. WB DIF are desirable for offshore operations due to fewer environmental restrictions, lower cost, and carbon footprint.
A CaCl2-based DIF was successfully designed and used offshore Brazil. Expanded density range was accomplished by using high concentrations of calcium carbonate avoiding environmental restrictions around CaBr2 brine.
A unique chemistry package is used to suspend the high concentration of solids while providing optimum rheology. Fluid loss control and rheological properties are tailored to deliver efficient drilling performance. The system was designed for densities up to 13.5 lbm/gal using up to164 lbm/bbl of sized-CaCO3. Testing followed the API 13I recommended practices incorporating testing for fluid rheology, sagging, fluid loss and filtration control, and return permeability (RP) using pre-salt reservoir cores.
The sized-CaCO3 bridging package was engineered to efficiently seal the targeted reservoir formation, resulting in minimum filtrate invasion, seepage loss and preventing reservoir formation damage. Moreover, the bridging package provided additional wellbore strengthening, preventing lost circulation problems and loss of well integrity. Fluid additives controlling viscosity were fine-tuned to avoid gelation issues at high pressure and temperature variation for the deepwater operation in off-shore Brazil. Measured fluid filtration loss volume was lower than 5 mL for disk sizes of 20, 55, and 120 microns with filter cake thickness less than 2 mm. Return permeability testing showed excellent results with returns higher than 70% without the use of breakers, and filter cake lift-off pressures around 4 psi.
The WB DIF was successfully and easily introduced and scaled to field operations including mixing large fluid volumes at the liquid mud plant to offshore operations on the rig for fluid additions, maintenance, and storage. Minimal changes were observed when blending the product in the liquid mud plant. The low-end rheologies were slightly lower but did not affect the application in the field. The fluid was capable to stand over 250 hours on static conditions while logging with no issues with sagging, separation, or density decreased in the wellbore.
The divalent brine-based fluid with a high load of solids has an immense potential for being used to drill a wide range of pre-salt high-pressure wells while maintaining the reservoir integrity and minimizing damage.
WB DIF are desirable for offshore operations since they allow discharge, minimizing environmental constraints, and lowering overall cost and carbon footprint.
