Mohammed Khalid Al-Arfaj

Preliminary Test Results of Nano-based Drilling Fluids for Oil and Gas Field Application

Current experience shows, it is often impossible to fulfill certain functional tasks that are essential in challenging drilling and production environments using conventional macro and micro type fluid additives due to their inadequate physical, mechanical, chemical, thermal and environmental characteristics. Hence, the industry is looking for physically small, chemically and thermally stable, biologically degradable, environmentally benign chemicals, polymers or natural products for designing smart fluids to use virtually in all areas of oil and gas exploration and exploitation. Due to totally different and highly enhanced physio-chemical, electrical, thermal, hydrodynamic properties and interaction potential of nanomaterials compared to their parent materials, the nanos are considered to be the most promising material of choice for smart fluid design for oil and gas field application. This paper describes the formulation and preliminary test results of several nano-based drilling fluids. The recently developed nano-based fluids were formulated using a blend of nanos and nanostabiliser to study the rheological and filtration properties and evaluate its suitability for oil and gas field application. Initial mud formulation indicates that development of a functionally viable, physically stable and homogeneous and also long lasting nano-based drilling mud is difficult using water or salt water as the fluid phase. However, use of a suitable viscosifier at a right concentration and adoption of a special preparation method lead to the formulation of a nano-based drilling mud with desirable rheological and filtration properties along with the gelling behavior and mudcake quality. Initial test results indicate that the newly developed nano-based drilling mud produces suitable high and low end rheological properties including gelling characteristics and thus expected to fulfill its functional task during drilling and after cessation of drilling. Introduction Water or oil-based drilling fluid is the first foreign fluid that contacts the reservoir zone of a borehole. Most muds contain sufficient quantities of particles that are used as a 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 micro-sized 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 and thin plaster like external mudcake on the borehole wall can cause serious formation damage due to the formation of an internal mudcake in the vicinity of the wellbore. The solids and the liquid phases invading the near wellbore formation may also interact with the formations such as salt, clays, anhydrite, etc leading to precipitation, clay dispersion, pore throat blockage, in-situ polymerization and thus may create a flow barrier to stop or reduce oil and gas flow. Damage by solids particle invasion and difficulties in cleaning the particulate damage have long been recognized by the industry. Hence, prevention of formation damage in the first place is the best strategic tool than cleaning the damage in the second place (Amanullah and Ziad, 2010). The spurt loss associated with most of the mud systems is one of the notorious sources of solid particles and particulate invasion in the vicinity of the wellbore. According to the experimental results of Beeson and Wright (1952) spurt losses ranging from 2.3 to 7 ml may take place in the presence of formation having permeability in the range of 7 to 469 md. Mungun (1965) pointed out that the primary cause of permeability reduction in the invaded zone is the blockage of pore passages by dispersed solid particles. This blockage or barrier may be due to the physical movement of the fine particles into the formation or chemical interactions of solids/filtrate with the formation or a combination of both. The investigation of the effect of particle penetration and particle concentration on formation damage and depth of invasion conducted by Todd et al. (1990) indicates that even 1-15 ppm water suspension containing less than 3 micron size particles may cause in-depth invasion with serious damage to the formation permeability. That’s why suspended particles, even in very dilute solutions like mud spurt may cause significant permeability impairment and thus may lead to a drastic reduction in oil and gas production.

Investigation of Water-Swelling Packers

Achieving successful zonal isolation during well completion is critical to minimize early water production. Currently, cementing is the only method used in Saudi Arabian fields to provide zonal isolation. In horizontal sections, cementing becomes a challenge and excessive water production can occur due to channeling. Another method for zonal isolation is to use a rubber elastomer bonded onto a base pipe. The rubber swells in water and provides a seal between the base pipe and the open hole. This article outlines step-by-step qualification testing that was carried out in Saudi Aramco facilities in an attempt to improve zonal isolation in horizontal and multilateral wells. In this study, we present lab evaluation of elastomers at 190 oF using brines of different ionic strengths and pH values. The evaluation involved examining the effect of salinity and pH on the rate of swelling of elastomers. Also, the study investigated the effect of 15 weight-percent (wt%) hydrochloric (HCl) acid on the swelled elastomers, and whether or not the exposure to water after the acid exposure will restore their size. To the best of the authors’ knowledge, no previous work was conducted to examine the impact of these factors on water swelling packers. The elastomer bonded in pipes was tested in autoclaves. The pressure drop across the pipe was measured as a function of time. The influences of pH and divalent cations on water swelling packers were investigated using elastomer samples. Swelling was related to fluid characteristics. Some water swelling elastomers withstood pressures up to 5,000 psi at 190 oF after placing the elastomers in brines with salinities up to 200,000 mg/l. The swelled elastomers shrank in 15 wt% HCl. Calcium chloride (CaCl2) completion fluids at 72 pounds per cubic foot (pcf) failed to swell the elastomers. The swelled elastomers shrank in 15 wt% HCl acid and their swelled size was not regained after soaking in water. This article discusses the advantages and limitations of swelling elastomers and gives recommendations for field application.

Swelling Packers: Lab Testing and Field Application

The best well completion is the lowest cost one that meets the demands for the well during its life time. There are different aspects that we need to consider when designing completion such as reservoir consideration (Allen and Roberts, 2006).We can have openhole completions, perforated casing completion, or horizontal completions. In this study, we present lab evaluation of oil and water swelling elastomers for potential field application in Saudi Arabia fields.