A new thickening system extends the temperature range of traditional viscoelastic surfactant-based fluids and provides additional downhole benefits. Based on a low-molecular-weight associative polymer, the thickener forms an associative gel with surfactants at elevated temperature. This results in a gel structure that can carry proppant. Recent laboratory work has shown that viscosity alone may not accurately assess proppant transport. Thus, the aim of this paper is to evaluate rotational and oscillatory measurements to determine the viscous and elastic properties of the fluid. In addition, dynamic and static proppant settling tests were conducted using a high-pressure/high-temperature visualization cell to confirm the effect of elastic properties on proppant settling. This combination of measurements can better predict whether the fluid can be applied successfully in the field.
Thirty-three different formulae across a wide polymer and surfactant concentration range were examined at temperatures up to 250°F. Also, the effect of other fracturing fluid additives, such as friction reducers and nonemulsifying agents, were examined. Finally, proppant-settling tests were conducted with three proppant types of the same size, but different density and shape at a range of concentrations.
Experimental results show that each formula had a certain operating temperature range where the elastic modulus dominates. A polymer-to-surfactant concentration ratio of 1.4 was found to give the widest working temperature range with the highest elastic characteristics; the same range also gives better proppant suspension. At temperatures less than 100°F, the viscous regime was dominant for all tested formulas. However at the same temperature, the elastic modulus increased with shear rate. This gives a good proppant-carrying capacity during dynamic conditions (mixing and injection) with a small pressure drop. The friction-reducing agent was found to have a tendency to reduce the operating temperature range. However, the nonemulsifying agent reduced the effect of the friction reducer and enhanced the performance of the fluid. Data obtained from this study can be used as a guideline for field treatment design.
Gupta, Shilpi (Schlumberger ) | Sinha, Ravi (Schlumberger) | Verma, Vibhor (Schlumberger) | Kumar, Ajit (Schlumberger ) | Singh, R.K. (Schlumberger) | Swain, Saraswat (Schlumberger) | Pandey, Arun (Schlumberger) | Majithia, P.P. Singh (Oil and Natural Gas Corporation) | Hinge, P. (Oil and Natural Gas Corporation)
Field XYZ located in the western offshore India is a multi-pay, multi-layered heterogeneous Carbonate reservoir having lateral discontinuities. Discontinuous layers and scale deposition and near well bore damage have led to multi-dimensional problems related to both upper and lower completions reducing ultimate field recovery. Workover attempts like re-perforation, additional perforations and plugging, artificial lift by electrical submersible pump (ESP) and secondary recovery by water injection were implemented to maximize the field recovery. However, any work over had only short term impact on production increase and water injection and ESP performance were inefficient. Production History showed cyclic decline in production with time. Identifying and locating the layers’ discontinuities became crucial in candidate selection and design of efficient injection pattern, artificial lift, completion and work over in existing and new infill wells.
The following case study presents a workflow involving multi well geological, petro physical and time lapse formation pressure data and production logs to identify and locate lateral discontinuity within a pay of the field. The reservoir pressure support attempts using water injection methods were proved to be inefficient. Furthermore, this workflow has been successfully implemented for candidate well selection and designs the artificial lift using ESP.
An effective ESP design for three wells was implemented and seven future candidates for ESP were recognized. Additionally, locations of three new infill wells are identified and a strategic layer wise completion was designed.
Implementation of the results increased production from the field by 30%.
Stimulation results of carbonate matrix acidizing are strongly dependent on the acid injection rate. Numerous studies have shown that an optimum interstitial velocity (Vi-opt, injection rate over flow area and porosity) exists, which results in the minimum volume of acid required for wormhole propagation and best stimulation results. During the last decade, much progress has been made to determine the factors that affect the optimal conditions in linear coreflood experiments, including the temperature, acid type, and acid concentration. However, little work has focused on the effects of the core dimensions, although a core-size dependence has already been observed. It has been shown that for a fixed core diameter, the Vi-opt
increases with increasing core length, but it is not clear if the Vi-opt can be independent of the core length when the core length reaches a certain value. In this work, we conducted a series of coreflood experiments with Indiana limestone cores at room temperature. The cores are selected homogeneous ones, thus to eliminate the effect of heterogeneity. The acid was 15% plain hydrochloric acid. The core lengths range from 4-in. to 10-in. and the core diameters were 1-in., 1.5-in. and 4-in.
For the 1-in. and 1.5-in. diameter cores, we found that the optimal conditions changed as core length increased for lengths less than 6 inches. The optimal flux was found to scale with core diameter, as found in other recent studies. In the paper, we show how these results improve scale-up of laboratory acidizing results to the field scale.
Zhang, Ke (Rice University) | Chanpura, Rajesh A. (Schlumberger) | Mondal, Somnath (University of Texas at Austin) | Wu, Chu-Hsiang (University of Texas at Austin) | Sharma, Mukul M. (University of Texas at Austin) | Ayoub, Joseph A. (Schlumberger) | Parlar, Mehmet (Schlumberger)
Particle size distribution (PSD) is used for various purposes in sand control: decision between various sand control techniques (e.g., Tiffin criteria), sizing of the filter media (sand screens and/or gravel packs) through either rules of thumb (Coberly, 1937; Saucier, 1974; etc.) or physical experiments or theoretical models (Chanpura et al., 2012, 2013; Somnath et al., 2011, 2012). PSD of formation sand samples are also often used to generate “simulated” formation sand for laboratory experiments. Two most commonly used techniques for PSD measurements are sieve and laser, while some engineers use one technique for no obvious or justifiable reasons, others use both techniques for measurements and don’t know what to do with the data when significant differences exist in PSDs obtained from each technique. Although the inherent limitations of, and the differences between, these two techniques as well as other factors impacting the measurements are well known, a systematic study as to what is relevant to sand control along with when and why is lacking. In this paper, we critically review the current practices in PSD determination and use and misuse of the information obtained from those measurements, propose a methodology towards determination of what is relevant, when and why, and present our initial experimental results that support our conclusions.
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.
Restrepo, Alejandro (Equion Energia ) | Ocampo, Alonso (Equion Energia) | Lopera, Sergio (Universidad Nacional De Colombia) | Coronado, Jorge L. (Equion Energia ) | Sanabria, Rosa B. (Equion Energia) | Alzate, Luis G. (Equion Energia ) | Hernandez, Sergio (Equion Energia)
The following paper is the continuation of SPE Paper 152309 (GaStim Concept - A Novel Technique for Well Stimulation. Part I: Understanding the Physics) and contains the experimental work and field pilot testing stages of the GaStimulation method already proposed by the authors. Systems studied correspond to tight quartzarenites containing retrograde gas condensates exhibiting Krg impairment under depletion. In this type of systems treatment penetration and durability are key factors for benefit sustainment. Supported by the theoretical background and preliminary lab tests presented in part I (SPE152309), the second stage of the GaStim project was planned and executed covering the phases of product´s screening, well candidate selection, pilots´ execution and results evaluation. Two pilots are reported, one in which water induced blockage is removed by stand-alone gas injection and another in which deep Gas + chemical dispersion is injected to reach a condensate blockage damage radius of 100 ft +. In the first scenario, it is noted that Sw reduction / Kg improvement is attained in the gastimulated area probably by coupled effects of evaporation and water slug displacement. In condensate blockage scenarios, it was noted that micellar type of surfactants exhibit the best performance when tested against IFT reduction capacity, Kg re-establishment (after condensate and water blockage) and treatment durability. Additionally, it was observed that the tuning of chemical concentrations and deployment method is key to maximize hydrocarbon flow capacity and minimize emulsion effects at surface after gastimulation. Further experimental work is planned to support modelling approaches both aimed on improving design criteria and expanding the potential of the technique into more challenging environments.
This paper takes a novel approach towards managing the architecture and protocol of injection/production system. The shut-in valve positioning and time of valve closure control the amplitude and frequency of pressure waves generated during shutdowns. The proposed approach provides the means for mitigating negative impact of water hammer on the integrity of near wellbore region and the intensity of cross-flow. It is based on a comprehensive model of fast wellbore transients (water hammer) generated by routine or emergency shutdown of injector or producer and interacting with a near wellbore reservoir region. The modeling handles the conventional transient pipe flow hydraulics coupled with the transient reservoir flow. The decompression wave created by shutting down an injector interacts with the near wellbore region and may induce a transient flow back from reservoir creating a risk of mechanical damage and sand production. The compression wave created by shutting down a producer may induce repeated injection pulses. In both cases, multiple cross-flow phenomena can be triggered between formation layers and wells interconnected within the injection or production system. The analysis of these transient phenomena helps to potentially quantify the mechanical damage, which may be induced in near wellbore reservoir region, and assess the potential damage risk associated with produced solids.
Mesophase technology for wellbore clean-up and remediation in the drilling industry has been used in various oil fields to increase well productivity and injectivity. The majority of these applications include oil-based mud filter cake removal, near-wellbore remediation, and wellbore displacement.
The open hole wells completed with standalone screens in the deepwater tertiary formations offshore West Africa have benefited from previous knowledge and experiences accumulated by the operator and the service company in the application of Mesophase technology in other fields.
This paper discusses the field application of the Mesophase technology in several deepwater offshore fields in West Africa. Previous to the field application, the Mesophase formulation was customized for the field conditions, such as temperature, fluid density, type of completion brine, and specific oil-based mud. The customized formulation was evaluated to determine the regain of injection permeability, fluid compatibility and the breakthrough time. Intensive tests were required to fine-tune the formulation to obtain the desired high-injection permeability for the challenging conditions encountered in the field.
Results from the laboratory and description of the field application are discussed and presented in this paper. The field applications data proved that, after placement of the mesophase treatment in the wells, diffusion of the treatment produced: (1) break-up of blocking solids from the completion screens; (2) removal of filter cake residues; and (3) water-wetting of all solid surfaces. This cleaning treatment gave very good results in the production and water-injection wells.
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.
Further advancement of prediction methods for wellbore stability requires a detailed description of fluid motion in the invasion zone and the development of real-time algorithms. Such algorithms should be based on a reliable model of motion and interaction of the fluids and pore space. This joint general deformation model should be approximated to obtain a number of reduced models that one can use for less-accurate but quick calculation of the near wellbore parameters. The objective of our research is to study the stress-deformed state of a porous medium saturated with fluids with the basic assumption that there is a number of different spatial scales porous medium deformation and fluid filtration flow. The general model is based on the principles of continuum mechanics and deformation of interpenetration continuums. A small parameter expansion method is applied for a dimensionless equation system. This method will use a relation of the spatial scales of deformation of the solid components and fluid flow.
The coupled models of fluid filtration in deformed media can be widely applied in the oil and gas industry, mining, medicine and hydrogeology. The approximated models can be used in software products for fast estimation of wellbore stability.
An initial sequence of models has been determined, corresponding to different approximations for the small parameter, where the zero-approximation model describes constant-volume deformation of a porous material. In this case the porous-pressure equation is separated from the matrix-deformation model. For the zero-approximation a number of analytical solutions were obtained in particular, in cylindrical coordinates, to describe the stress-deformed state around a vertical well. These solutions contain the non-zero shear stresses able to cause the formation damage. The first-approximation equations for incompressible saturating phases have transferred into a system similar to the Buckley-Leverett equations of two-phase filtration, but written for a deformed porous medium.
The zero-approximation poroelastic solutions are valuable as a class of non-one-dimensional approximations of motions of a porous material in a medium with constant volume. The zero- and first-approximation equations are enough to develop the fast numerical algorithm, for they can be used to estimate the areas of possible matrix destruction.