The water quality in West texas, and more specifically in the Permian Basin has worsen over time, in particular the hardness among others. To make this water usable, service companies have had to increase gel loading and pH buffers, which drawback is the additional damage of proppant pack due to precipitation of solids and unbroken gel. Therefore, new chemicals are required to ensure stable results with current fracturing fluids.
A fluid stabilizer is an acid which is effective in the prevention form different type of scales, its use. prevents changing pH of fracturing fluid by stabilization of dissolving cations and anions. This product is environmental friendly and exhibits good thermal stability. Figure 1.
The fluid stabilizer has become paramount in fracturing operations because of the increasing fresh water scarcity, an issue of notable concern for our clients and the greater community. The essential mechanism of this chemical enhances hydration by lowering pH, while increasing viscosity of linear gel by 15%; at the same time, its controls pH of the fluid. This fluid stabilizer has also been able to remove various other undesirable chemicals.
This fluid component has been implemented in various locations in west Texas with different types water. It has proven to be robust and reliable and it has exceeded the expectations of all other chemicals in its class by holding its strength in fluids.
Using the stabilizer has enable the use of water from different sources water sources making it robust for fracturing operations.
A large number of stages have been successfully placed with up to 30% produced water
The use of produced water ultimately solves the scarcity of water for fracturing while maintaining the fluid performance.
Lopez, J. (Pemex) | Martinez Ballesteros, A. (Pemex) | Miranda, R. (Pemex) | Garcia, C. (Pemex) | Deolarte, C. (Pemex) | Vidick, B. (Schlumberger) | Giron Rojas, R. (Schlumberger) | Millan, A. (Schlumberger) | Rivas, J.G. (Schlumberger) | Lopez, A. (Schlumberger) | Miquilena, E. (Schlumberger)
An excessive water cut or high gas/oil ratio in a production interval presents a major concern in sustaining oil production, often requiring fast and efficient workover solutions to enhance the oil recovery process. Wells in the Cantarell field, a mature depleted field in the Bay of Campeche in the Gulf of Mexico, are facing drastic decreases in their production and, depending on producing zone, an increase in either water cut or gas/oil ratio. Other developed fields in Mexico’s Region Marina, such as the Ku-Maloob-Zaap, have constantly increased their hydrocarbon production through the years with an incipient increase in water and gas increments.
The high water cut and gas increments have had a strong impact on the production strategy, opening the opportunity for application of non-conventional, innovative, and engineered solutions to isolate or abandon production intervals invaded by gas or water and continue production from upper or deeper zones. The pay zones consist of naturally fractured, vugular carbonates with permeability as high as 5 Darcies, from Paleocene, Cretaceous, and Jurassic formations. Their characteristics present the following challenges that need to be overcome to succesfully achieve the required isolation:
This paper summarizes the non-conventional technologies and techniques applied to isolate the water and gas producing intervals and their synergistic performance: reticulated gel, lost circulation fiber tecnologies and gas-tight slurries integrated in an engineered solution. Results from field cases demonstrate the design, execution, and evaluation of these applications.
A suite of practical laboratory tests has been developed to characterize the performance of shale fracturing fluids and chemicals. The testing suite includes friction reduction, capillary suction time, and shale strength changes after exposure to the fracturing fluid.
The friction testing method was correlated to previously published work in larger diameter tubing and utilizes a small volume of water so that actual field water samples can be used. The capillary suction utilizes off-the-shelf equipment to give rapid determination of fluid and shale interactions. The shale strength change method involves dynamic exposure of share cores to the fracturing fluid at temperature, shear rates and times representative of the fracturing treatment. Shale strength changes are determined by measuring hardness of the core surface exposed to the fracturing fluid and comparing it to the opposite side of the core which was not exposed to fluids.
The friction reduction test has been used with great success to rate the performance of friction reducers in various types of water, to determine optimum friction reducer concentration, and to determine the interaction of other common additives such as biocides or scale inhibitors with the friction reducers. The strength testing has shown significant strength reduction in some shales with certain types of fracturing fluids and little strength reduction when the fracturing fluid was changed. A variety of fracturing fluids have been tested from slickwater to gelled oil fluids to traditional crosslinked fluid. The strength reduction should be indicative of proppant embedment in the shale.
The suite of tests proposed has been successfully used for multiple operators in order to determine interaction effects of fracturing fluids with shales as well as to optimize friction reducer performance.
A three-dimensional numerical model was developed to simulate the stability of wellbore and perforation tunnels completed in weak sandstone formations. Post-yield mechanical behavior of granular materials is incorporated in the model to study the mechanical instabilities associated with such completions. Fluid flow calculations are also incorporated in which they are computationally coupled with the mechanical calculations to generate pore pressure and stress distribution in the sand matrix. In addition, the presented model extends the use of the sand erosion criterion developed by Kim (2010) in order to compute the mass of the produced sand.
It has been shown through field experience that sanding is influenced by several factors such as completion geometry, wellbore inclination, perforation orientation, and in-situ stress anisotropy. The developed model is capable of simulating the impact of these factors and assessing their sanding risk through advanced modeling and meshing techniques. The model can be utilized accordingly to design a wellbore completion that maximizes the mechanical stability and reduces the sand production rate. Different production and operational conditions can also be simulated to determine the onset of sand production and the critical drawdown pressure.
Results obtained from the model shows that vertical wellbores produce less sand sands in regions where the overburden stress is the maximum in-situ stress. In horizontal wellbores, vertically oriented perforations are more stable than horizontally oriented perforations and can withstand higher drawdown before sand is produced. A wellbore model with multiple perforations was also constructed to investigate the effect of mechanical and hydraulic interference from adjacent perforations on the evolution of plastic strain. It was shown that perforation spacing has an influence on both the magnitude the spatial spread of the plastified zone. By combining the effects of phasing angle, perforation density, and wellbore diameter, the presented model is capable of determining the completion configuration with the least sanding risk.
This paper presents the simulation results of acidizing process in naturally fractured reservoir (NFR) by application of advanced numerical technique. Accurately predicting fracture and matrix flow is often critical to assessing well productivity in naturally fractured reservoirs.
Fracturing with acid (usually hydrochloric acid [HCl]) is an alternative to propped fractures in acid-soluble formations such as dolomites and limestones. Computational Fluid Dynamics (CFD) is a computational technology that enables study of the dynamics of materials that flow. The CFD code is used to simulate the fluid flow through the fracture and matrix. The model is based on coupled multiphysics phenomena such as Darcy’s law in porous media, reaction flow equation for the fracture and fracture growth by acid dissolution. Reaction flow in the fracture is controlled by diffusion and convection terms. The model simulates the impact of fracture geometry, acid properties, fracture width, matrix permeability on the acidizing process.
The results show that diffusion and convection terms will control the transport of acid through the fracture (as there are limits to this process). when the mass transfer coefficient (Kg) is higher than 10e-5 m2/sec, the mechansim of acid trasnport will be controlled by convection term on the fracture surface. Physically ,this means that acid transport to wall by diffussion term is negligilble. When the fracture width is higher than 200 micron (0.00002 m), the acid will react with the most of the surface of the fracture and it will be dissolved by acid considerably. The mass transfer coefficient will also play an important role during acidizing process as the results show. The results of this study were used as guidelines to design a more effective acid job by predicting the acid penetration and acid volume for matrix acidizing in naturally fractured reservoirs. Furthermore, the contrasts in job design for lithology of the carbonate formation are also presented.
This paper presents the findings of a study into the impact of reservoir flow behaviour on both the scaling risk at production wells, and the options for managing this scaling risk, for a deepwater sandstone reservoir in the Gulf of Mexico. One significant feature in this field is that flow takes place through isolated formation layers, and choices made regarding the seawater injection wells have a great impact, not only on the BaSO4 scaling tendency, but also on the placement of scale inhibitor squeeze treatments in the producers.
In addition to seawater injection, oil production is supported by the aquifer. The first stage of this study involved identifying the split between connate, aquifer and sea water in the produced brine. This provided data that could be used to calculate the evolution of the scaling risk over the lifecycle of each well. The formation brines contain barium and the injection water if full sulphate seawater and the relative proportion of each brine, the water production rate, and pressure and temperature conditions all determine the scaling risk.
The evaluation of the extent of ion reaction between the injection water (sulphate) and formation water (Ba) from injection to production well can result in a significant reduction in the available barium within the produced water and hence the scale risk/scale inhibitor concentration required preventing disposition. In this study as the injection wells were completed with inflow control devices (ICD’s) it gave the opportunity to manage the injection split via these ICD’s, not only to improve sweep efficiency, but also to balance reservoir pressures and make squeeze treatments more efficient. The study will present the squeeze treatment volumes and estimated treatment lifetimes possible for two scenarios for the water injection application to this deep-water field.
The implications of this type of study will be highlight in terms of the economic option that this data allows an operator to consider prior to commissioning water injection in these challenging environments.
The Viking formation in southern Saskatchewan Canada represents an active area where steep production declines in the first year of production are common and are often attributed to near wellbore or reservoir deposition of paraffin. Decline rates of 50-60% in the first year on production have been observed.
Traditionally, extended paraffin protection in the wellbore is the targeted area for solid paraffin inhibition programs. Treatments are evaluated on their ability to delay the need for conventional liquid chemical applications in the wellbore or flow lines. In this study, solid paraffin inhibitors were used to target paraffin deposition in the reservoir, to delay production declines. This area is beyond the reach of conventional treatments. Low formation temperatures, cloud points, and higher asphaltene content are common Viking characteristics that promote paraffin precipitation. The solid paraffin inhibitors are used to stabilize the paraffin in the initial stages of the well life, when deposition is predicted to be most severe.
The chemical additive treatment was designed through product selection testing using cold finger deposition tests, compatibility testing with the fluid system, and crush prediction models. A baseline of the untreated oil characteristics was determined using offset wells. Pour point, carbon number distribution and asphaltene percentage were analyzed in each well. The solid inhibitor application effectively prevented conductivity restrictions due to paraffin deposition issues in the reservoir.
Placement of solid paraffin inhibitors into the Viking formation with the proppant during hydraulic fracturing increased cumulative production by approximately forty percent per well in the first 350 days on production and reduced decline rates. The comparison of 150 untreated wells completed in 2010 to 2012 with the 90 wells treated with the solid paraffin inhibitor has increased reserves estimates by fifty percent. Wells drilled in the same area, with similar frac systems, depths, horizontal lengths and stages are compared.
Oil-field scales result from changes in the physicochemical properties (pH, temperature, pressure etc.) of the produced fluids and/or due to the chemical incompatibility between waters having different compositions (e.g., formation brine and injection brine). Nevertheless, the comprehensive modeling and prediction of such phenomena remains a challenge, due to the complexity of the precipitation kinetics and chemical reaction processes that occur in the reservoir. Hence, it is the case that often reactions in the reservoir are not considered on evaluation of the scaling tendency, probably because they are difficult to measure and also, to model the calculations considerable effort and expertise is required.
Since no comprehensive geochemical-based modeling has been applied in this research area, in this work, a previously developed robust, accurate, and flexible integrated tool, UTCHEM-IPhreeqc, is used to model the comprehensive geochemistry to predict scales problem for field scale applications.
IPhreeqc, the United States Geological Survey geochemical tool, is able to simulate both homogeneous and heterogeneous (mineral dissolution/precipitation), irreversible, and ion-exchange reactions under non-isothermal, non-isobaric and both local-equilibrium and kinetic conditions. Through coupling of IPhreeqc with UTCHEM, The University of Texas at Austin research chemical flooding reservoir simulator, the entire geochemical capabilities of IPhreeqc can be used in a multi-dimensional and multiphase reservoir simulator for comprehensive reactive-transport modelings.
In this paper, the importance of ion activities, temperature, and pressure in the reactive-transport modeling is emphasized by performing several sensitivity analyses. Oilfield scale is quantified by including the effect of dissolution or precipitation of all possible minerals (either initially present or subsequently precipitated by injecting an incompatible water) on the reservoir petrophysical properties (e.g., porosity). Three common permeability–porosity approaches (Modified Fair–Hatch, Kozeny-Carman, and Verma-Pruess models) are then implemented in the UTCHEM-IPhreeqc simulation tool to model the effect of scalings on the reservoir permeability. To show how well this integrated tool can be applied for field scale applications, a synthetic five-spot pattern is presented using several water compositions.
In water injector wells, continuous injection can wash gravel from the annulus around the screen, especially when injecting above the fracture pressure. The voids created after the annular washouts are sometimes filled by an influx of formation sand during shut-in operations. This sand accumulation consequently reduces the injectivity when the injection operations resume. A technique to prevent gravel washout was needed to maintain sand control and injectivity throughout the life of these water injector wells.
We therefore designed a product to prevent gravel washout by reinforcing the gravel pack with an interconnected network of fibers. The fibers contain a layer on the outside that is activated by temperature, forming a bonded fiber network that locks the gravel in place. This technique can be used with any type of proppant. The key benefit is that the fibers can withstand cyclic loading of stress during the shut-in and re-start of injection operations, which typically happen several hundred times during the life of an injector well.
Our experimental study to test this new product showed that the drag force of injected water easily displaced the gravel in the annulus into the fracture, whereas gravel reinforced with fibers withstood the drag force even at high injection rates (e.g., 100 bbl/d per 0.5-in-diameter perforation). We performed several more experiments to evaluate the strength of the pack under cyclic stress conditions. After 30 cycles, the pack strength was unaffected. The fiber chemistry was also adjusted for compatibility with commonly used fracturing fluids and brines. We found that the fibers remained connected in an interconnected network even after long-term interaction with sea water. We also studied the interaction of fibers with screens and other downhole equipment that come in contact with the fibers during gravel placement. The laboratory results of that study showed that the fibers did not create any issues with proppant placement or tool functionality during the sand control operation.
Our experimental study showed that the fibers provided an effective solution for preventing gravel washout in water injectors, thereby ensuring that sand control and injectivity remain as designed for the life of the well.
Currently, many producing formations are carbonates and/or depleted sands that are characterized by highly permeable flow paths or vugs. Severe-to-total loss of drilling fluid in these formations is a major concern both from the drilling and reservoir damage perspectives. Conventional particulate Lost Circulation Materials (LCMs) such as acid-soluble ground marble may not effectively cure severe losses. Furthermore, since the application is in a producing formation, avoiding reservoir damage is a major criterion that any potential solution must satisfy. The ‘band-width’ of available solutions that are both efficient and reservoir friendly is narrow; leading to both high cost and potentially risky drilling practices.
A possible solution is an acid-soluble Right-Angle-Setting Composition (RAS-Co) developed to provide the industry with a more efficient solution for plugging and isolating producing zones that have high drilling fluid loss rates. RAS-Co is formulated from inorganic, nonhazardous powders and fluids mixed in freshwater or seawater. RAS-Co is engineered to be a low viscosity (18-30cPs) fluid containing small particulates allowing it to be mixed at the rig site and pumped through any drillstring configuration. It is designed to react at a specific bottomhole circulating temperature in a consistent and controllable manner with a ‘right angle’ set. Once it is spotted/placed in the suspected loss zone, it eliminates further fluid losses and formation damage. The small particle size distribution acts as a pore-bridging material while in the fluid state and the right angle set characteristic makes the material non-invasive to the formation and lets it be easily drilled or removed with acid. It can be used in zones with up to 300°F circulating temperature and tolerates up to 50% contamination with water or drilling fluids.
This paper describes attributes of RAS-Co along with successful field applications, which makes it an effective solution for controlling reservoir damage by stopping severe lost circulation events.