No abstract

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.

The Orito field in the south of Colombia was initially put on production in 1969 and has produced continuously since then. The most prolific reservoir, is the Caballos Formation, a thick (250 ft avg.) laminated sandstone located at a depth of 6100 to 7500 ft that has produced (30 to 45 °API crude) for over 35 years, with production peaking at 66,000 BOPD. The permeability varies from 20 to 200 mD with streaks exceeding one Darcy. At different times in the past, attempts were made to hydraulically fracture one or more of the sands, using a variety of different (water- and oil-based) fluids. However, many of the wells indicated positive skin factors following the fracture treatments, irrespective of the fluid system used. In at least one case, a well stopped producing after being treated. A core study revealed that despite the relatively low clay content in the formation the critical velocity was less than one cc/min. Moreover, the retained matrix permeability after performing a static leakoff test (500-psi differential for 30 minutes) was less than 5%, regardless of the fluid used. From this testing it was concluded that the reduction in the permeability was due to the mechanical plugging of the kaolinite or disrupted mica in the pore throats. This reduction in the matrix permeability creating a very high fracture face skin that would account for the higher skin factors following fracture treatments. To eliminate the fracture face skin created during the fracture treatment a new treatment incorporating a pre-pad of acid viscosified with a solids free visco-elastic surfactant was developed. By incorporating this stage into the fracturing treatments, the retained matrix permeability was increased to +/- 30%, resulting in a negligible fracture face skin. The productivity of fracturing treatments performed using this technique resulted in negative skin factors and production ratios that exceeded expectations. Introduction The Caballos formation and reservoir is an asymmetric anticline with an orientation of N-NE to S-SW with two domes separated by a fault as shown in Fig 1. The field has an active aquifer that has maintained the reservoir pressure at around 1,500 psi during the last 20 years. The main production mechanisms being water and solution gas drive. Figure 1: Schematic of Orito Anticline The 250 ft thick reservoir is a massive sand with interbedded shale and carbonates, deposited in a marine environment. The variation in the vertical lithology subdivides the reservoir into four distinct flow units or layers A, B, C and D in ascending order Fig. 2.

The Orito field located in the South of Colombia, near the Ecuadorian border has been in production since 1967 and is operated by the Colombian state oil company, Ecopetrol (originally discovered and exploited by Texaco). Petrominerales signed an Incremental Production Contract agreement in April 2001 to participate with Ecopetrol in increasing production from the field. Under the terms of the agreement Petrominerales invest 100% of any development activity in return for a portion of the value of the incremental production. The Orito reservoir is a multi layered reservoir with three production intervals: Pepino, Villeta and Caballos at depths of 3000 ft TVD and 7000 ft TVD respectively. The reservoirs are depleted and pressures are below the original bubble point pressure. The wells can exhibit a number of challenges for production of fluids using artificial lift including: scale; solids production; high GOR; early high water production; and also very high CO2 (80%). Solids issues are exacerbated on wells where hydraulic frac jobs have been performed, which have resulted in a number of premature failures (less than 14 days) of ESP systems. Artificial lift has been applied to the field and most lift methods have been tried at some point including Electric Submersible Pumps (ESPs), Rod Pumps, Gaslift, Jet Pumps and Progressing Cavity Pumps (PCPs). This paper will: identify the challenges associated with each lift method in this operating environment; present a lift method selection philosophy; provide details of a pilot program to convert Gas lifted wells to rod pump and; document the key steps taken to evolve an ESP design capable of producing the solids from the fractured wells. Introduction The Orito field is located in the South of Colombia beside the town of Putumayo, near the border with Ecuador (figure 1). The Orito field is almost 17 miles 2 (43 km2) in area and is situated in the Putumayo basin. The field originally contained more than 1 billion bbl of oil-in-place, in three primary reservoirs. The most significant is the Cretaceous Caballos formation, a complex series of fluvial/ deltaic and marginal marine sands that originally contained more than 700 million bbl of oil-inplace and is still the main productive interval. The Caballos zone, alone, has produced 191 million bbl since the field was discovered in 1963. Through an Incremental Production Contract Petrominerales invest to reactivate existing wells or to drill new wells and has been doing so since 2001. Since commencing operations in the Orito field Petrominerales have worked over 47 wells and drilled 28 new wells. An active drilling program is being pursued resulting in approximately 1 new well per month. As part of the standard completion procedure new wells are hydraulically fractured, as this has been shown to increase well inflow performance significantly. Within the Orito field there are 3 hydrocarbon bearing intervals: Pepino from depths of 1500- 2500 ft, Villeta from 5000 - 6500 ft; and the Caballos at 6500 – 7500ft as shown in figure 2. Typically, Petrominerales target the Caballos formation as the primary zone of interest. The production parameters for each interval are shown in table 1. Current production from the field is almost 21,000 bfpd with an oil rate of 6700 bfpd. While potential for the field is high, increasing the production rate from the field has proven to be difficult due to: the highly heterogeneous nature of the formation making picking of new well locations difficult; rapidly increasing watercut; challenges with uptime of artificial lift equipment; and serious delays in undertaking optimization work.

fax 01-972-952-9435. AbstractThe 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 o 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.