TX 75083-3836 U.S.A., fax 01-972-952-9435. AbstractTo maximize the production and enhanced total recovery of hydrocarbons, the oil companies must have a complete understanding of the reservoir rocks and fluids present in their producing fields. The measurement of rock properties enables us to determine its ability to allow fluids to flow and understand the way these fluids will behave when the reservoir is produced. This information provides the starting point to conduct a Formation Damage Analysis that will lead to an appropriate diagnosis in order to select the best solution. It will provide detailed explanation to the problems that well and production have and will offer basis and support to the stimulation treatment investigation and its effects. The Formation Damage is any mechanical, chemical, biological or thermal process in a reservoir that causes a reduction in porosity and permeability. Almost all the field operations constitute a potential source of damage for the well productivity that often results in reduced productivity of oil or gas reservoirs or reduces injectivity of injection wells, on a secondary recovery, This paper is an attempt to supply a preparatory methodology to enable the potential risks of formation damage evaluation, trying to correlate the results in a laboratory scale with the field test. The laboratory diagnosis, usually preliminary for stimulation, help auspiciously to avoid or decrease the risk of damage. The study and control of formation damage requires a test design consistent with the feasibility of the operatives options and involves properties such as the knowledge of geological and petrophisics of the formation to be stimulated, fluids compatibility, operative procedures, etc.
Water production control has become a key issue in most mature oil fields worldwide. Several water shut off technologies have been developed during the last two decades, and intensive research work is continuously conducted in this field. Relative permeability modifiers (RPM) have proven to be an effective method to enhance oil recovery, especially under linear flow conditions achieved after fracturing. This technique is being extensively used worldwide, with many successful case histories published in the literature. When adequately design and applied, RPM treatments will increase well profitability, improving water-oil ratio, reducing water management costs and environmental impacts. However, RPM treatments are not always effective, as they depend on several aspects associated to formation and fluid production characteristics, polymer chemistry and the interaction between each other. Many oil and gas zones in Entre Lomas field require hydraulic fracturing for a profitable production. However, the risk of contacting close water layers might jeopardize wells productivity. RPM treatments have been conducted in this field since 2007. In most cases the RPM solution was pumped as part of a fracture conformance job. This paper presents the results from more than 50 wells fractured bull-heading RPM treatments. The field work was supported by a laboratory study based on different experiments performed to evaluate RPM efficiency. Regain permeability (RK), relative permeability curves and nuclear magnetic resonance (NMR) tests were conducted using core plugs and Berea sandstone samples. The RPM polymer washout rate was evaluated by spectrophotometer measurements performed on brine samples collected during the flow test. The NMR spectrums run on treated and untreated cores in the saturated and irreducible water condition provided evidence of the polymer bonding capacity and its ability to retain water. The use of RPM´s allowed fracturing formations with close high water saturation transition zones that otherwise would not be produced. Pre and posfrac formation evaluations tests and production data is provided. Laboratory results show that the RPM polymer under study produced a significant reduction in water permeability, without substantial oil perm modification. Polymer wash out time showed strong flow rate dependence affecting the treatment durability. Introduction Entre Lomas field description The Entre Lomas field is located in the northwest Neuquina Basin, Argentina (seeFigure 1). It was discovered in 1960, being formation Tordillo one of the main oil payzones which is under secondary recovery since 1975. Tordillo is a clustered sandstone present at approximately 2300 m. The bottom part of this formation consists of a sequence of fluvial layers, while the top part presents eolian sedimentation characteristics. The bottom part has thin interspaced clay layers with variable extensions. The clustered layers present strong heterogeneity, with week areal and vertical barriers on the payzones under production (Benito, 1997). These characteristics explain the variable production response of certain wells showing, in some cases, low recovery factors. Several water shut-off treatments were conducted in the fluvial layers during 1995, 1999 and 2001 in order to reduce water cuts. These layers presented heterogeneous permeability's (0.5 to 25 mD) which caused injection water channeling and inefficient water flooding results (Wouterlood, 2002).
Sustained Annulus Pressure (SAP) is a common issue that affects shale plays wells worldwide. The cement sheath barrier deteriorates due to extremely high hoop stresses generated in the cement annulus during fracture treatments. These stresses are approximately one order of magnitude higher than the cement maximum tensile stress. Once cement sheath fails, gas or oil migrates from high-pressured subsurface formations through vertical cracks along the annulus. Pressure at the wellhead can reach values above the installation maximum rate which persistently rebuilds after bleed-down operations. The presence of SAP means that well integrity has been compromised generating serious safety and environmental risks for operators. After conducting several finite element simulation studies, that demonstrated the failure hypothesis, a research project was conducted to design an isolating material that would withstand service conditions generated during well termination and its overall life cycle. A polymeric sealing ma terial with high deformation capacity, consequently low Young's modulus, high toughness and bonding properties was developed. The material was tested following API recommended practices and ASTM standards. A procedure to prevent SAP in new wells was proposed. Five well of different Vaca Muerta shale fields were isolated combining a cement slurry batch with the polymeric system pumped in tandem. Also, a repair procedure for wells showing SAP was proposed and successfully tested using a similar polymeric sys tem. This procedure consisted of injecting a 14.8 ppg formulation in the annulus in a pump and relief (P&R) manner. The pilot test is currently under evaluation. Wells isolated with the polymeric system have not presented SAP after more than six months, nor have the two remediation jobs conducted so far. Annular pressure of new and repaired wells is being monitored to determine treatment effectiveness.
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