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Abstract It is fundamental to pilot and deploy IOR/EOR initiatives to improve recovery from petroleum reservoirs using cost effective methods, ensuring a continuous supply of production that would meet the ever-increasing demand for energy. Under-Balanced Drilling (UBD) technology proved worthy as a valuable initiative in the redevelopment strategy of a Giant Carbonate reservoir located in the Middle East. It improved well deliverability especially in low permeability reservoir zones. The strategy for this has been to deploy 3-4000 feet laterals to maximize reservoir contact to such tight units or drill as far as possible to have maximum flow input/productivity. Horizontalization (non-UBD), together with stimulation has been going on for many years with mixed success as recent production log surveys showed negligible contribution from several wells completed in these low permeability units. In 2011, well-X was drilled underbalanced to assess the value of this technology in augmenting productivity and improving reservoir characterization. Significant improvement in Productivity Index was accomplished by minimizing damage from drilling and completion operations. In addition, considerable knowledge was acquired from Flowing While Drilling (FWD) data and multi-rate tests in four segments of the production zone. Real-time geosteering was actively used to account for changes in the reservoir architecture. Analysis of the FWD data has derived in new understanding of the dynamic nature of the reservoir's South-central region, highlighting sectors of high permeability, fractures, tight areas, different pressure regimes and varying fluid composition. Furthermore, despite the innovative nature of the technology, drilling and completion was very well controlled by the Well Construction teams, resulting in costs not significantly higher than normal over-balanced wells. The enhanced reservoir knowledge that UBD delivers as shown from well-X will result in improved recovery efficiency and possible delayed water production. Moreover, it is a lead value improvement technology that will meet strategic business objectives with minimum risk and lowest Unit Technical Cost.
- Asia > Middle East (0.88)
- Europe (0.88)
- North America > United States > Texas (0.68)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (21 more...)
This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 139534, ’Preliminary Test Results of Nano-Based Drilling Fluids for Oil- and Gasfield Application,’ by M. Amanullah, SPE, Mohammad K. Al-Arfaj, and Ziad Al-Abdullatif, Saudi Aramco, prepared for the 2011 SPE/IADC Drilling Conference and Exhibition, Amsterdam, 1-3 March. The paper has not been peer reviewed. The oil and gas industry is looking for small, chemically and thermally stable, biologically degradable, environmentally benign material to use in the design of smart fluids. Because of highly enhanced physiochemical, electrical, thermal, and hydrodynamic properties, nanomaterials are considered a promising material. Recently developed nano-based fluids were formulated to study the rheological and filtration properties and evaluate fluid suitability for oil- and gasfield application. Initial test results indicate that the newly developed nano-based drilling mud produces suitable high- and low-end rheological properties. Introduction Water- or oil-based drilling fluid is the first foreign fluid that contacts the reservoir zone of a borehole. Most muds contain particles that are part of the mud formulation. These desirable mud solids can cause severe formation damage in the presence of a poor quality mudcake. Moreover, the cutting debris generated while drilling may produce enough microsized and colloidal particles to cause severe formation damage if a poor quality mudcake is deposited on the borehole wall. Hence, drilling muds that are unable to form a well-dispersed, tight, thin, plaster-like external mudcake on the borehole wall can cause serious formation damage because of the formation of an internal mudcake. Spurt loss associated with most of the mud systems is one of the notorious sources of solid-particle and particulate invasion in the vicinity of the wellbore. Fine particles coming into the drilling mud as a part of drill solids may also cause severe formation damage if the mudcake formed on the borehole wall is poorly dispersed, is very thick because of particle flocculation, and has highly porous fabric because of loose-fabric formation by the flocs, aggregates, and particles. The thickness of the deposited mudcake is also a critical factor in many drilling and reservoir-engineering problems. Muds producing soft and thick cakes increase the potential of differential sticking and, thus, are not desirable for geological formations highly prone to differential sticking.
- Asia > Middle East > Saudi Arabia (0.54)
- Europe > Netherlands > North Holland > Amsterdam (0.24)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > Asia Government > Middle East Government > Saudi Arabia Government (0.54)
Abstract In scale inhibitor squeeze treatments, precipitation of the inhibitor within the formation can lead to extended squeeze lifetimes. However, such processes also have the potential to cause formation damage unless they are carefully designed and controlled. The formation of a partially soluble inhibitor/metal complex within a reservoir is the objective for almost all precipitation squeeze packages. However, historically there are numerous ways this is achieved almost all of which require a limited operational window to be deployed successfully. In this paper, we describe the development of a novel dual chelant system which provides a method for controlling both the "wanted" and "unwanted" precipitation of the scale inhibitor package within the formation. The highly tunable nature of the system allows for ease of pumping at more extreme conditions (higher and low temperatures, calcium levels etc.) than have previously been possible. By using the dual chelant mechanism described in this paper, a package can be tuned to precipitate within a certain time frame both at low and high temperatures in brines with varying degrees of salinity and hardness. The scale inhibitor (SI) itself is a chelant or ligand for divalent ions present (mainly Ca) and this is denoted L2 and the second chelant, L1, is added to the system at certain design concentrations, as explained in the paper. In many situations, the high divalent metal ion content of a produced brine, or formation water can limit the successful pumping of a scale inhibitor due to high levels of calcium, for example. Under these conditions the dual chelant mechanism can also be deployed to prevent scale inhibitor phase separation. This paper discloses the theory of how the dual chelant mechanism works using computer modeling and the subsequent confirmation of the simulations by laboratory testing. The importance of the pKa of the SI (L2) and the added chelant, L1, and the relative metal binding constant interactions between L1/ L2 and Ca are explained and investigated. The comparison of the dual chelant mechanism versus conventional packages is demonstrated by core flood experiments. The dual chelant mechanism gives a clear improvement in squeeze lifetime and controllability and provides a platform for the development of many types of controlled solubility scale inhibitor treatment.
- Water & Waste Management > Water Management > Water & Sanitation Products (1.00)
- Water & Waste Management > Water Management > Constituents > Salts/Sulphates/Scales (1.00)
- Materials > Chemicals > Specialty Chemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
Abstract Finding new areas to exploit for hydrocarbon production has become a challenge. This has led to wells being completed with more than two or three intervals in different configurations and with various petrophysical properties, which can greatly affect production and also accepting treatment fluids. In addition, in low-pressure wells with multiple open intervals, conducting effective stimulation treatments using chemical diverters or foamed fluids is not always the best alternative. For cases with multiple areas, stimulation using coiled tubing (CT) is optimal to help ensure stimulation in areas where new intervals have been created as a result of having previous intervals which had preferential acceptance of fluids. The purpose of this study is to show how stimulation using CT has evolved from using conventional, rotary, and hydraulic-cleaning tools to the development of a new application for stimulation tools, which helps achieve better placement of acid treatment systems. The advantages obtained with this new application are Water cut can be reduced with this technique to help ensure intervals near the water-oil contact are not encouraged. It can handle higher pumping rates for effective removal of the damage. Penetration of the stimulation fluids was evaluated using radioactive isotopes, and spectral recordings were taken to assess the depth of stimulated intervals, placement and an estimate of the treatment volume, and the radial penetration of fluids. Fluid flowback is faster, which saves time on installation and introduction of CT for interventions. This acid-stimulation placement technique is the best way to stimulate wells with more than two intervals when selective treatments are required.
- North America > United States > Texas (0.29)
- North America > Mexico (0.29)
Abstract Formation damage is a by-product of the drilling, completion, and production process and can be attributed to many factors. In openhole (OH) and cased-hole (CH) wells, hydrocarbon flow may be impeded by various damaging mechanisms caused by drilling and completion fluids, in-situ emulsions, water block, organic deposition, and oily debris left downhole. Microemulsion fluids have been successfully developed to effectively resolve the persistent problem of near-wellbore damage. The physical-chemical properties of these microemulsion systems include high oil solubilization, high diffusion coefficients through porous media, and the reduction of interfacial tension between organic and aqueous phases to near zero, making them excellent candidates for removing formation damage. The chemistry of microemulsion fluids make these systems excellent choices for superior synthetic or oil-based mud (S/OBM) displacements in casing and for OBM filter cake cleanup in openhole completion applications. Formulations have also been developed for casedhole perforation applications as well as post-perforation remediation treatments to remove the formation damage around the perforation or fracture zones. This paper presents a technical overview of microemulsion technology and a review of the test protocol used to qualify treatment solution designs for S/OBM displacement/cleanup and removal of formation damage in openhole and casedhole wells. Challenges and results from numerous field applications are presented that demonstrate the efficiency of microemulsion fluids for removing S/OBM debris and filter cakes, reducing near-wellbore damage and improving well productivity.
- Africa > Middle East > Egypt (0.68)
- Asia > Middle East > Saudi Arabia (0.46)