Stimulation Workflow Applied on LAPA Pre-Salt Carbonate Field Deep-Water Brazil

Lapa is a pre-salt deep-water field located around 270km off the coast of São Paulo, Brazil at Santos basin. This carbonate reservoir lies in water depths of around 2,100m and can produce good quality light 26° API oil. The stimulation in large carbonate reservoirs is very challenging, and techniques used for Lapa were based on chemical divergence. The development in offshore environments requires proper planning, execution, and monitoring to achieve the desired results and, of course, profitability. The matrix acidizing method was chosen to stimulate all wells of this campaign (2 producers and 2 injectors). This method consists of bypassing formation damage and stimulating the reservoir by creating wormholes via chemical pumping. In the design phase, stimulation operations previously performed at this field were reviewed, analyzed, and optimized. The main changes were regarding the completion strategy without the use of coiled tubing and placement during the completion phase as it could optimize the time and the cost for the project. The volumetric rate (gal/ft) was also reduced and the selection of the main fluid changed after several laboratory analysis and software simulations. The Lapa field requires high fluid volumes due to the length of the intended treatment interval. The assembly of a stimulation plant on a supply vessel from operator fleet (multi-purpose FSV – field support vessel) was the most cost-efficient approach to address the high volumes required as there was no Well Stimulation Vessel (WSV) available "on call" in the Brazilian offshore market at that time. This solution could also optimize the vessel fleet while the vessel was not required for pumping as FSV was also equipped with ROV and was mean to carry subsea planned task. The fluid test strategy was also a key point for this successful project as many tests were performed to make sure that the correct fluid system was selected. During this process, several fluid systems and different formulations were submitted for core flow tests and dual core flow tests to evaluate worm holing efficiency of retarded fluids and diversion performance of Chemical diverters. Compatibility tests were also performed, and a mud cake breaker was developed locally, especially for this project. This paper will bring an overview of all aspects regarding Lapa stimulation project since the conception, fluid system selection, laboratory tests, lessons learned and the potentially future strategy for this field.

Dry Cationic Friction Reducers: New Alternative for High TDS Slickwater

Currently, well stimulation in North America has evolved almost entirely to slickwater fracturing with friction reducers (FRs). Some parts of North America are notorious for their poor water quality, so wells are commonly treated using high total dissolved solids (TDS)-containing flow-back or produced water. Cationic FRs are usually applied in these systems due to their tolerance to multivalent cations in such waters. Additionally, dry friction reducers have gained momentum for better economics and logistics. In this paper, a dry cationic FR is systematically studied with respect to its "on the fly" hydration capability, friction reduction, mechanical stability, compatibility with other anionic chemical additives, and thermal stability in different levels of TDS brines. The cationic FR solution was subjected to varying shearing rates to understand its hydration capability, friction reduction, and mechanical stability. Its compatibility with anionic additives, such as a scale inhibitor, was also tested in a laboratory friction loop. Thermal stability of the cationic FR solution was studied at 150°F using a viscometer and Multi-Angle Laser Light Scattering (MALLS) method to obtain molecular weight information. The charge characteristics of the cationic FR, indicative of self-degradation properties, with exposure to heat, were also studied. Potential formation damage of the FR solution was evaluated with core flow tests in the absence of oxidizing breakers. Friction reduction and hydration tests show that the FR performs well in high TDS waters, even at low temperature, reaching its peak performance rapidly. The cationic FR possesses high mechanical stability even after being exposed to high pumping rates in the friction loop. It is well known that cationic FRs are not compatible with polyanionic scale inhibitors; in this study, a compatible scale inhibitor, SI-1, is identified. Additionally, there has historically been hesitation to use such cationic materials due to concerns of formation compatibility with negatively charged source rocks or flocculation in water treatment plants. Thermal testing with cationic FRs reveals that the material degrades to anionic without the aid of any other additive, which is confirmed by the fact that addition of polycationic additive, C1, caused coacervation in the heat-treated sample. As a result, concerns over effects of rock wettability or incompatibility with water treatment additives can be alleviated. No anionic FRs undergo similar change of the ionic charge. Thermal testing with cationic FR solutions also shows a significant viscosity drop, surprisingly without pronounced molecular weight loss (via MALLS). However, core flow testing of cationic FR fluids shows good regained permeability, even without breakers, further confirming self-cleaning capability. The degradation mechanism of these FRs will be shown. The self-cleaning capability of the dry cationic FR, even at relatively low bottomhole temperature (BHT), in combination with its high salt-tolerance, makes it an excellent friction reducer for multiple applications, especially with low quality water.

Nano-Texturing of Hydrocarbon Reservoirs with Omniphobic Nanoparticles to Mitigate Liquid Phase Trapping

Gas reservoirs contain substantial amounts of natural gas and, in some cases, associated high API liquid hydrocarbons. Condensation of heavy hydrocarbons, especially in the area closer to the wellbore, occurs as a direct result of the decline in reservoir pressure. This hydrocarbon condensate, and in some cases water, tends to accumulate in the pore space and form a liquid bank. This liquid bank will result in a reduction in gas relative permeability and overall reduction in the well's productivity. This paper illustrates the synthesis and utilization of surface modified silica nanoparticles to mitigate the liquid banking phenomenon in gas reservoirs. Silica nanoparticles (S-NPs), of different sizes, were synthesized using the Stöber process. The impact of the nanoparticle size and degree of functionalization with different hydrophobic and omniphobic groups on altering the rock wettability properties to mitigate liquid banking in gas reservoirs were studied. The S-NPs (of sizes between 50-400 nm) were functionalized with various linear and branched fluoroalkyl groups, terminal amine, and epoxy groups. The particle size of surface modified silica nanoparticles was determined using dynamic light scattering (DLS). The performance of the surface modified silica nanoparticles was evaluated through measuring surface charge, change in contact angle, and by performing core flow experiments at reservoir conditions. A glass slide dip coated with 135 nm surface modified silica nanoparticles solution derivatized with terminal amine and perfluoroalkyl group provided a contact angle of 120° and 83° with water and decane, respectively. The contact angle can be tailored by changing the amount of amine and perfluoroalkyl concentrations on the particle surfaces. A contact angle of around 90° indicates a nonwetting neutral surface that results in minimizing capillary pressure and enhancing mobility of both hydrocarbon and water liquid phases. Using core flow studies and by estimating the improvement in gas and liquid relative permeabilities, surface modified silica nanoparticles treatment demonstrated a comparable performance to commercially available solutions at 1/5 the treatment volume. The surface modified silica nanoparticles sustained its performance indicating a stable and permanent coating on the rock surface. The silica nanoparticles functionalized with fluoroalkyl group, terminal amine and epoxy can be directly pumped without the need for a pretreatment of the rock surface. This results in less complexity when it comes to the field operation. The dual- functionalized silica nanoparticles were found to be effective in changing the rock surface wettability to neutral or nonwetting, thereby providing a potential solution to liquid banking problem in gas reservoirs.

Dolomite Stimulation with Retarded Acids

Globally, dolomite formations are important reservoirs for oil and gas. Acid stimulation is commonly used to extend the life of carbonate reservoirs, and a good understanding of the fluid performance is essential for effective treatment design. Three acids, hydrochloric acid (HCl), emulsified HCl, and a single-phase retarded acid based on HCl, were assessed for their ability to create wormholes in Silurian dolomite under laboratory conditions using a standard core flow experiment. Select cores were imaged by X-ray computed tomography to visualize the wormhole morphology. Similar experiments in Indiana limestone was used as a control. The core flow experiments showed that the pore volume to break-through (PVbt) values for the retarded acids in Indiana limestone were less sensitive to changes in temperature overall than unmodified HCl. For Silurian dolomite though, the opposite is observed. HCl has uniformly high PVbt values at lower (200 °F) and higher (325 °F). The emulsified acid and the single-phase retarded acid are more efficient than HCl, but the difference is smaller at 325 °F. Core images revealed that all three fluids had some degree of wormhole branching at 200 °F and much less branching at 325 °F. By visual inspection, the single-phase retarded acid has less ramification than HCl and the emulsified acid. Overall, the results show that retarded acids should make effective stimulation fluids for dolomite reservoirs.

Relationship between perforation depth and core flow efficiency

The perforation parameters have a large influence on the productivity of offshore wells. Perforation depth and core flow efficiency (CFE) are the key parameters for evaluating perforation response, but the relationship between these two parameters is seldom studied. In this paper, the perforation experiment and CFE evaluation are carried out. The results show that with the increase of confining pressure, perforation depth decreases, CFE increases, and perforation damage decreases. The CFE decreases with the increase of perforation depth, and the relationship between them satisfies the exponential function.

Optimized Clay Control Fracturing Fluid Used in a Highly Water-Sensitive Tight Oil Reservoir Hydraulic Fracturing Application in Xinjiang Oil Field: Case Study

The candidate wells are tight oil wells and most of the wells in the area have a low recovery rate of fracturing fluid after fracturing treatment. The lithology is glutenite with weak cementation and a high sensitivity tendency. This paper presents the process of sensitivity evaluation and fracturing fluid evaluation. Also, this paper introduces a customized and optimized clay control fracturing fluid wells in a highly sensitive reservoir. Per local national standard, traditional methods of swelling test (ST) and x-ray diffraction (XRD) were employed for qualitative formation cutting analysis. An innovative trial was then developed to evaluate cores quantitatively by water sensitivity. A clay stabilizer was then chosen to be used for the highly sensitive cores and regain permeability testing of the broken fracturing fluid was performed. Based on the analysis and evaluation, a customized treatment design was initiated for the hydraulic fracturing treatment. The qualitative evaluation showed the rock is highly water sensitive and the cores easily collapse because of weak cementation. No flow could be established during traditional core flow tests with brine. The newly developed method used kerosene as the working fluid to prevent the cores from contact with water or brine. The core flow tests resulted in a velocity sensitivity damage rate of 92%, which is considered as highly velocity sensitive. Accordingly, a special clay stabilizer was chosen to be used in the fracturing fluid and the permeability damage of the broken fracturing fluid is only 26.9%(Table 16). Field results have shown that the fracturing fluid recovery rate in treated wells is higher than the area average level and treated wells have significant oil production increase. The innovative clay control fracturing fluid and its field application reduces the influence of water and velocity sensitivity. The customized treatment with special clay stabilizer helps increase the recovery rate of fracturing fluid in reservoirs with severe clay stability and weak cementation issues.

Wyznaczenie liczby Damköhlera i jej znaczenie w projektowaniu zabiegów matrycowego kwasowania

During the matrix acidizing of carbonate formations, channels with high permeability are created, known as wormholes. The effectiveness of this type of treatment depends primarily on the structure, geometry, and the depth of penetration of the wormholes beyond the damaged zone. This should be ensured by a properly developed acidizing fluid, which in the case of carbonate formations most often consists of solutions of hydrochloric acid and/or organic acids such as acetic or formic acid. Additionally, in the case of high-temperature formations, additives are used to reduce the reaction rate of acid with the reservoir rock. The Damköhler number (Da) is an important factor that influences the model of the wormholes created. It represents the ratio of the rate of the reaction between the acid and the rock to the rate of its convection along the wormhole. The aim of the study was to determine the Damköhler number for four selected acidizing liquid–rock systems and to confirm that the structure of the wormholes depends on this variable. As part of the work, rheological tests of gelled acidizing liquids using a viscoelastic surfactant were conducted. The reaction rate tests were carried out on core plugs cut from Pińczów limestone and Guelph dolomite, which are characterized by relatively low permeability and porosity coefficients: 9.11–14.23 × 10−15m2 and 28.51%–29.10%, respectively, in the case of Pińczów limestone and 3.69–7.48 × 10−15m2 and 7.67%–9.38%, respectively, for Guelph dolomite. A rotating disk apparatus was used to determine the kinetics of the reaction of these rocks with two types of acidizing liquids. Then, core flow tests were performed on the core plugs using the AFS-300 system for the same types of rocks and liquids. The core plugs of Pińczów limestone used in these tests had a permeability coefficient ranging from 9.65 to 26.27 × 10−15m2 and a porosity coefficient ranging from 28.78% to 31.29%. On the other hand, samples of the Guelph dolomite had permeability coefficients of 7.48 to 61.52 × 10−15m2, while the porosity was much lower, ranging from 7.63% to 10.60%. After the core flow tests, the Damköhler number was calculated for each identified wormhole, using X-ray computed microtomography combined with an analysis of the geometric parameters. The types of structures that are formed in carbonate rocks as a result of matrix acidizing and their impact on the effectiveness of treatment are described in the theoretical part of this publication. Seven models of carbonate acidizing, which are used to estimate the influence of the parameters of the treatment and the properties of the liquid and rock on the efficiency of the acidizing process, are also discussed. Particular attention was paid to the theory of the Damköhler number, the value of which determines the formation of wormholes. The tests showed that at 80°C the overall reaction rate for each of the four acidizing liquid–rock systems was controlled by the mass transport rate. It was found that a gelled 15% HCl solution using TN-16235 viscoelastic surfactant reduced the overall reaction rate by reducing the mass transport rate. In the case of Pińczów limestone, the addition of 7.5% TN‑16235 surfactant reduced the De value from 4.45 × 10−6cm2/s to 3.53 × 10−6cm2/s; for Guelph dolomite De decreased from 2.25 × 10−6cm2/s to 1.97 × 10−6cm2/s. The values of the acidizing liquid pore volumes required to break through the core plug (PVbt) were determined based on the core flow tests. The lowest values of this parameter for Pińczów limestone were 0.26 for a 15% HCl solution and a velocity of 2.93 cm/min and 0.28 for a gelled 15% HCl solution and a velocity of 0.30 cm/min. For the Guelph dolomite rock, they were 0.88 for a 15% HCl solution and a velocity of 3.68 cm/min and 0.25 for a gelled 15% HCl solution and a velocity of 1.00 cm/min. Gelling a liquid with TN-16235 viscoelastic surfactant thus enables efficient matrix acidizing of carbonate formations with lower pumping rates. It was also found that the model of dissolution of the porous medium by a given acidizing liquid depended on the value of the Damköhler number. For wormholes created in the plugs of Pińczów limestone using the 15% HCl solution, the calculated values of Da were in the range of 0.244 to 0.026 (optimal value: 0.031); for the gelled 15% HCl solution it ranged from 0.145 to 0.008 (optimal value: 0.097). The optimal value for Da was considered to be the value for which wormholes were able to penetrate the entire length of the core with minimal acid spending described by PVbt. For wormholes etched in the Guelph dolomite rock by the 15% HCl solution, the calculated values of Da ranged from 0.104 to 0.030 (optimal value: 0.066), and for the gelled 15% HCl solution they ranged from 0.188 to 0.030 (optimal value: 0.069). The research methodology presented in this paper allows the Damköhler number to be determined for acidizing liquid–rock systems, and thus facilitates the preparation of technology for matrix acidizing of carbonate formations in such a way as to make these treatments as effective as possible. Keywords: matrix acidizing, Damköhler number, viscoelastic surfactant

Equatorial auroral records reveal dynamics of the paleo-West Pacific geomagnetic anomaly

Localized regions of low geomagnetic intensity such as the South Atlantic Anomaly allow energetic particles from the Van Allen radiation belt to precipitate into the atmosphere and have been linked to a signature in the form of red aurora–like airglow visible to the naked eye. Smoothed global geomagnetic models predict a low-intensity West Pacific Anomaly (WPA) during the sixteenth to nineteenth centuries characterized by a simple time dependence. Here, we link the WPA to an independent database of equatorial aurorae recorded in Seoul, South Korea. These records show a complex fluctuating behavior in auroral frequency, whose overall trend from 1500 to 1800 AD is consistent with the locally weak geomagnetic field of the WPA, with a minimum at 1650 AD. We propose that the fluctuations in auroral frequency are caused by corresponding and hitherto unknown fluctuations in the regional magnetic intensity with peaks at 1590 and 1720 AD, a time dependence that has been masked by the smoothing inherent in regularized global geomagnetic models. A physical core flow model demonstrates that such behavior requires localized time-dependent upwelling flows in the Earth’s core, possibly driven by regional lower-mantle anomalies.