Combining Acid- and Hydraulic-Fracturing Technologies Is the Key to Successfully Stimulating the Orito Formation

Rozo, Rafael Eduardo; Paez, Javier; Rojas, Alberto Mendoza; Milne, Arthur William; Soler, Diego Fernando

doi:10.2118/104610-ms

Cited by 7 publications

(1 citation statement)

References 6 publications

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“…The cycle 2 corresponds to a viscous acid treatment that was pumped as a prepad ahead of the main propped fracturing treatment (Rozo et al 2007). This treatment gives the opportunity to investigate how to adjust the range to use for a nonconstant injection rate case.…”

Section: Fracture Pressure Analysis (Fpa) For Sacha-258 Wellmentioning

confidence: 99%

Increasing Production and Reserves in a Mature Field with Hydraulic Fracturing by Combining Fracture Pressure Analysis, Pressure Transient Analysis, and Rate Transient Analysis

Murminacho

Sánchez

Lopez

et al. 2015

SPE Latin American and Caribbean Petroleum Engineering Conference

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Even as new discoveries are developed and produced, substantial additional reserves can be secured by enhancing recovery from mature fields. It is known that one of the most cost-effective ways to revitalize mature fields is to institute an efficient workover program. These programs can be more effective because of the implementation of fracturing/refracturing techniques for unlocking new pay intervals or putting back on production existing, nonproducing stages. Fracture stimulation is commonly used to increase the production and improve the economics of oil and gas fields worldwide. In many cases, however, if the average production increase justifies the hydraulic fracture, very little effort is made to optimize the treatments. Further economic gains can be achieved through the optimization of the hydraulic fracturing process by improving the fracture model calibration and better understanding of reservoir parameters. This is particularly true in mature fields where the fracture geometry understanding is critical to avoid contacting a water zone or a gas cap in some cases. Also, sometimes there is an impact on the reserves determined by decline curve analysis (DCA) after the fracturing treatment.The analysis of the fracturing model through pressure interpretation or fracture pressure analysis (FPA) provides powerful tools not only for understanding and improving the fracturing design parameters, but also for better understanding the reservoir parameters. On the other hand, reservoir transmissibility, a variable of significant importance in hydraulic fracturing design and production evaluation (PE), is frequently unknown because candidate wells either do not flow or pretreatment pressure transient tests are not available. The after-closure analysis (ACA), the component of the FPA in the after-closure region, allows for the identification of linear and radial flow and the determination of reservoir transmissibility and pressure from injection testing. The reservoir parameters determined with this method can be verified by comparison with results obtained from conventional well testing or pressure transient analysis (PTA) and rate transient analysis (RTA).This paper presents a detailed analysis and comparison of the reservoir parameters obtained by FPA, PTA, and RTA in block 60 (Sacha field), a mature field located in the Oriente basin operated by Operaciones Rio Napo CEM. The three techniques have been integrated for reservoir modeling in a moderately permeable, underpressure, black oil sandstone reservoir allowing not only increasing the production but also the reserves in the hydraulically fractured wells.

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Section: Fracture Pressure Analysis (Fpa) For Sacha-258 Wellmentioning

confidence: 99%

Increasing Production and Reserves in a Mature Field with Hydraulic Fracturing by Combining Fracture Pressure Analysis, Pressure Transient Analysis, and Rate Transient Analysis

Murminacho

Sánchez

Lopez

et al. 2015

SPE Latin American and Caribbean Petroleum Engineering Conference

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Acid Fracturing Optimizing Design and Application in Deep Naturally Fractured Carbonate

Che

Wang

Peng

et al. 2021

IOP Conf. Ser.: Earth Environ. Sci.

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More than 30% of carbonate reservoirs in the Tarim oilfield and XiNan oil-gas field are naturally fractured-vuggy reservoirs, of which the production is high in most cases and economic returns can be achieved within a short period of time. Acid fracturing is one of the key technology for development of such naturally fractured-vuggy reservoirs. Mud overflow and loss may be emerged at the same time while drilling fractured-vugular carbonate, once it happened, the well control will become complicated. So, the wellbore is drilled a certain distance up or transversal to these huge caves or natural fractures, and acid fracturing will be executed to connected the reservoirs to obtain the hydrocarbon in the reservoir. Acid-fracturing design of fractured-vugular carbonate is based on the relationship between the wellbore and fractured-vugular reservoirs. The acid fracturing design in naturally fractured-vuggy carbonate reservoir is different from the conventional one, it should be optimized based on the spatial positions of the fracture-vuggy body identified via geophysical prospecting, the wellbore and the distance between the two. In the case that the wellbore precisely reaches the top of the fracture-vuggy body, good oil and gas show or overflow is frequently happened. At this moment, drilling ceases and the wellbore are cemented and completed. The small-scale acid fracturing treatment is then carried out, and connectivity between etched fractures and the top of the fracture-vuggy body will lead to high hydrocarbon production. If a certain distance exists between the wellbore and fracture-vuggy reservoirs, 3D seismic imaging will be adopted to calculate the vertical distance between the center of the storage body and the wellbore, which is then used to optimize the injected fluid volume, pump rate and acid fracturing techniques. To create connectivity with the fracture-vuggy storage body relatively far away from the wellbore, acid fracturing involving preflush or multi-stage injection is used. Pressure drops by several ∼ several tens of MPa usually occur as the artificial fracture propagates into the fracture-vuggy body. After fracturing penetrating into the fracture-vuggy body, acid injection starts. During the early acid injection, the pump rate is raised up for longer etched length inside the fracture. It is then lowered during the late acid injection to improve the conductivity of etched fractures. If multiple fracture-vuggy bodies exist near the wellbore, the temporary diverting acid-fracturing will be treated, optimized with respect to the distance between the wellbore and different fracture-vuggy storage bodies, spatial relationship between the maximum principal stress direction and fracture-vuggy storage body and the trend of natural fractures, will be implemented to communicate with multiple naturally fractured vuggy reservoirs. This acid fracturing integrating geophysical prospecting and wellbore trajectory has been applied in hundreds of wells in the Tarim oilfield. Moreover, the success rate of such acid fracturing treatments is increasing with the advancement in the characterization of the fracture-vuggy reservoirs.

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An Alternative Solution to Sandstone Acidizing Using a Nonacid-Based Fluid System with Fines-Migration Control

Rozo¹,

Paez²,

Rojas

et al. 2007

SPE Annual Technical Conference and Exhibition

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The Caballos formation is thick laminated sandstone with less than 10% of total clays and permeability ranging from 20 mD to as high as one Darcy. However, the production from this formation is often limited due to the low critical flow rate in the matrix (less than 1 mL/min) and associated fines migration as shown in several tests. Historically matrix acidizing and hydraulic fracturing treatments in this formation have only been partially successful due to destabilization of the clays and inadequate fines stabilization, along with the incompatibility of the crude oil with many conventional acid systems. In order to overcome the limitations associated with the use of conventional acid systems an extensive laboratory study was conducted using a non-acid based stimulation fluid. The base fluid selected was a newly developed chelating agent that is very tolerant to high concentrations of both carbonate and aluminosilicates, and iron and zeolite bearing minerals. By including acid salts in the fluid it proved possible to develop a fluid system with the equivalent dissolving power of a conventional 6:1.5 (HCl: HF) mud acid, even at temperatures as low as 180°F. Testing also showed that the fluid was capable of controlling fines migration and that a scale inhibitor could be included in the formulation, while the fluid system exhibited excellent compatibility with the formation fluids throughout the field. The newly developed non-acid fluid system provides some unique advantages for matrix acidizing applications and in particular for stimulating the Caballos formation 1) Minimizes the risk of secondary and tertiary precipitation due to the nature of the chelating agent 2) A single treating fluid instead of the multiple fluids/stages used in a conventional treatment 3) Greatly reduced sludging and emulsion tendencies compared to conventional acid systems (without the addition of surfactants or demulsifiers) and much lower corrosion rates 4) The ability to stabilize fines present in the matrix 5) Allows for a scale inhibitor to be included in the treating fluid 6) Reduces the logistics and HSE risks during the execution of the treatment. This paper reviews the laboratory testing including an extensive core flow testing performed to develop a new nonacid treating fluid for both matrix acidizing and dual stimulation applications in the Caballos formation and its implementation in the field, illustrated with case studies and production data. Introduction In the Orito field in the south of Colombia the most prolific reservoir is the Caballos Formation, 250-ft thick interbedded fluvial/deltaic and marginal marine sands that originally contained more than 700 million bbl of oil in place. Due to distinct changes in the vertical lithology the reservoir is divided into four distinct flow units or layers A, B, C and D in ascending order shown in Fig 1. Furthermore, the production of the wells along with a petrographic and petrophysical study has shown that there are two distinct zones of markedly different reservoir quality. The lower zone - layer A, is a much better quality reservoir than the upper zone. Layer A is a well sorted sand with kaolinite present in the pore spaces. The porosity and klinkenberg permeability varies from 12 to 14 % and from 100 to 300 mD, respectively. While, the upper zone - layers B, C and D - is a much poorer quality reservoir. A single facies of poorly sorted and loosely packed quartz with kaolinite in the inter-granular spaces. The porosity in this upper zone is predominantly intergranular ranging from 11 to 12 % and the klinkenberg permeability from 5 to 150 mD, (Fig. 2). In addition, due to the presence of a number of major and minor faults the reservoir is compartmentalized. The complexity of the stratigraphy reflected in the marked changes in the quality of the reservoir and the properties of the oil in place, across the field. Due to the fractional composition of the oil, the properties of the crude oil also vary between the different layers, independently of the location of the wells on the structure.

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Combining Acid- and Hydraulic-Fracturing Technologies Is the Key to Successfully Stimulating the Orito Formation

Cited by 7 publications

References 6 publications

Increasing Production and Reserves in a Mature Field with Hydraulic Fracturing by Combining Fracture Pressure Analysis, Pressure Transient Analysis, and Rate Transient Analysis

Increasing Production and Reserves in a Mature Field with Hydraulic Fracturing by Combining Fracture Pressure Analysis, Pressure Transient Analysis, and Rate Transient Analysis

Acid Fracturing Optimizing Design and Application in Deep Naturally Fractured Carbonate

An Alternative Solution to Sandstone Acidizing Using a Nonacid-Based Fluid System with Fines-Migration Control

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