Formate-Based Reservoir Drilling Fluid Resolves High-Temperature Challenges in the Natuna Sea

Abstract

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractSelecting the components of fluids for reservoir drilling and completion can require extensive laboratory work to determine the most compatible fluid. Well temperatures in excess of 300°F (150°C) create additional challenges, as the additives required to give water-based reservoir drilling fluids the rheological and fluid-loss characteristics needed to successfully drill and complete long horizontal wells degrade at such elevated temperatures. In addition, supplying the necessary additives to a drilling operation in a remote location can be a major logistical burden, leading to a compromise in the fluid formulation.The Belanak field lies off the coast of Indonesia in the Natuna Sea. The reservoir temperature is high (315°F), and the reservoir sections are drilled horizontally, typically between 3,500 and 4,500 ft and often feature particularly tortuous well paths. A low-solids, brine-based reservoir drilling fluid was required because the wells use premium screens for sand control.Six wells were drilled using the sodium formate-based reservoir drilling and completion fluids. The particle size distribution and concentration of the calcium carbonate bridging solids were monitored closely while drilling to ensure that filter cake quality was not compromised. A chelating agent-based breaker was used to break down the filter cake prior to the onset of production.The laboratory work required to optimize the fluids for this project had to take into account not only the requirements for the best fluid technically, but also the effect of the limitations created by working in a remote location. Considerations included minimum loading of calcium carbonate required to deposit a clean, high-quality filter cake and the effect of mixing brine for the reservoir drilling fluid or completion using seawater in case of a shortage of drill water.Fluid testing carried out in the laboratory included drilling performance at temperature, fluid compatibilities, bridging solids optimization, scale inhibition testing, and breaker selection. The fluid selected was based on sodium formatethe first application of a formate-based fluid in Indonesia.

Characteristics and Removal of Filter Cake Formed by Formate-Based Drilling Mud

“…The leak-off also happens during the completion phase when drilling fluid lose their suspension properties at high bottom hole temperatures due to degradation of the polymers (Saasen et al, 2002;Bradshaw et al, 2006).…”

“…Traditionally, cleaning up a reservoir filter cake has been accomplished with conventional chemical and mechanical means. The chemical means include formate brines (Hands et al, 1998), live mineral and organic acids (Huang et al, 2000), enzymes (McKay et al, 2000;Al Otaibi and Nasr-El-Din, 2005), chelating agents (Bradshaw et al, 2006), or a combination of formate brines and organic acids (Svendsen et al, 1995). The combination of high reservoir temperature and long shut-in times after acid treatment lead to a high probability of severe corrosion of the well completion.…”

Enhancing the performance of xanthan gum in water-based mud systems using an environmentally friendly biopolymer

“…In addition, biopolymers are environmentally friendly (Dayawant 1999), enhance the properties of water-based muds even at low concentrations (Darley and Gray 1988), and can be used separately or mixed together to improve bentonite performance (Darley and Gray 1988). Nevertheless, drilling fluids containing biopolymers have some limitations: High solid contents (Amoco Production Company 1994) and high temperatures are a major challenge to running biopolymer-based muds successfully (Tehrani et al 2007;Galindo et al 2015;Bradshaw et al 2006;Zheng et al 2019). High temperatures cause the degradation of biopolymers in drilling muds (Wenjun et al 2014;Tehrani et al 2009;Zhang 2016), thus leading to the decrease or total loss in viscosity and other properties of drilling fluids (Weaver et al 2003).…”

Novel Thermally Stable High-Density Brine-Based Drill-In Fluids for HP/HT Applications

“…As the amount of HP/HT wells increases, a need for novel drill-in fluid formulations capable of providing necessary performance in harsh operating conditions continues (Bradshaw et al 2006;Soric et al 2003;Krilov et al 2000). The primary components limiting the application of drill-in fluids in HP/HT conditions are biopolymers.…”