Improving HPHT Stability of Water Based Drilling Fluids

Abstract

A new method is discussed to improve the HPHT stability of conventional rheology modifiers and fluid loss polymers used in water-based drilling fluids. The method exploits the interactions of polysaccharides (e.g. xanthan gum, scleroglucan), cellulosics (e.g. CMC, PAC) and starches with polyglycols. Polymer and polyglycols were found to associate by intermolecular hydrogen bonding and hydrophobic interactions. This association / complexation was found to stabilize the polymers at higher temperatures. Our laboratory findings are validated by field observations in the Kakap field in Indonesia that show improved HPHT stability when adding polyglycols to water-based drilling fluid formulations. Introduction During the history of oil- and gas exploration drilling fluids have evolved from simple clay-based "muds" to highly sophisticated drilling fluids that are specially engineered to meet demanding tasks. Chemicals are intentionally added to perform very specific functions, such as rheology modification, fluid loss control, shale stabilization etc. Until now, relatively little attention has been given to the mutual interactions that may occur unintentionally between drilling fluid components and their consequences for the properties of these complex fluids. Polyglycols are well-known in the drilling fluid industry for their use in controlling troublesome shales. Excellent control over rheology and fluid loss, low dilution rates and overall ease of maintenance are some of the characteristics of polyglycol systems frequently reported by mud engineers handling them in the field. In this paper, it is shown that there actually exists a scientific basis for these subjective observations. In a drilling operation it is the task of the mud engineer to let a drilling fluid system perform at its best within the given limitations of that particular system. Such limitations are clearly posed by the degradation of polymers at high temperatures, which leads to loss of rheology and fluid loss control. There may be significant consequences for drilling progress and ultimate recovery if these properties cannot be maintained. Loss of rheology can result in hole cleaning problems, leading in turn to stuck pipe and loss of hole. Loss of fluid loss control can lead to unnecessary loss of fluids to formations. Note that invasion of formation-incompatible filtrates may cause reservoir impairment and reduced recovery of hydrocarbons. In the last decade there has been a growing interest in the association of anionic, cationic and nonionic surfactants with water-soluble polymers because these complexes are of great importance to cosmetic products, paints, coatings and in enhanced oil recovery. Here we show that similar complexes can also be utilized in the drilling fluid industry to extend the HPHT stability of polymers used for fluid loss control and rheology modification. Introduction to Polyglycols The generic group of glycols is strictly limited to diols which contain two hydroxyl (-OH) endgroups. Polyglycols are formed when these groups are condensated between glycols to form ether links (i.e. C-O-C bonds). A significant number of commercial additives also known as polyglycols in the oilfield, however, are in fact initiated from alcohols (e.g. butanol), fatty acids or fatty amines which are condensated with ethylene oxide (EO) or propylene oxide (PO). Note that the additives thus formed contain only one hydroxyl endgroup and are therefore not true diols/glycols. Most of them are non-ionic surfactants which combine in a single molecule a hydrophobic group (e.g. the alkyl-chain that originated from the initiator) and a hydrophilic group (the EO- or EO/PO chain). In conformance with oil-field convention, these molecules will still be referred to as polyglycols below. Main focus in this paper will be on three polyglycol types. Polyglycol A is a polyalkylene glycol with a 50/50 EO/PO distribution. Polyglycol B is a simple polyethylene glycol (PEG). Polyglycol C is a fatty amine ethoxylate. All have a molecular weight in the 500–600 a.w.u. range. P. 249^

New shale hydration inhibitors adapted to the downhole conditions

“…The polyglycols ability to reduce the hydration of clay formation was also confirmed by the authors (Balaban et al, 2015) by measuring the capillary suction time and swelling of clay formation. Chemical compounds being the part of polyols group as components of drilling mud may also restrain drilling induced formation fractures and support mechanical stability of the wellbore (van Oort E. et al, 1997;Taugbol et al, 2005;Zamora et al, 2013;Zhang et al, 2015;He at al., 2016;Kazemi-Beydokhti and Hajiabadi, 2018).…”

Drilling muds with stable rheological parameters using modified natural polymers

“…drilling fluids containing polymers of natural origin contribute to the prevention of damage to the near-wellbore zone (Dawson, 1991;Clark et al, 1993;de Kruijf et al, 1993;Rae, di Lullo, 1996;van Oort et al, 1997;Eriksen et al, 1997;Delshad et al, 2008;Seright et al, 2009;Steliga and Uliasz, 2012;Yerramilli et al, 2013;Elkarsani et al, 2014;Leonhardt et al, 2014;Li and Delshad, 2014;Ogezi et al, 2014Brattekas et al, 2016Behr and Rafiee, 2017).…”

Application of Nonionic Tenside Homologues in IOR/EOR and Oilfield Chemistry: Fundamental and Engineering Aspects

“…As early as in 1974 Mondshine 35 raised the idea of tenside addition to water-base drilling muds to improve their rheological properties. Van Oort et al 36 pointed out that substitution of water-soluble polymers with nonionic like poly-ethylene glycol will improve not only the flow properties, but also the fluid loss and thermal stability. Further, the field experiences proved an enhanced drilling efficiency: in the presence of nonionic surfactants the drilling rate increased by 35 % on account of the lower friction loss between the rock and the bit (Unger et al 37 ).…”