Drilling efficiency depends on several dynamic factors and challenges. Horizontal drilling well design is critical to maximizing production and reservoir contact particularly cases in which several fluid engineering aspects affect drilling. Challenges increase when transitioning from horizontal to extended-reach drilling (ERD); however, minimizing metal-metal or metal-formation friction is vital. This paper presents a detailed study of laboratory testing of a range of lubricants and software simulation models of a true drilling environment to minimize friction.
For nearly a decade, efforts to reduce friction have focused on engineering the lubricant only without taking into consideration additional factors that could help diminish friction. The challenges of drilling reservoirs are numerous; however, the availability of intelligent software allows for replication of the actual conditions precisely enough to design and drill wells with minimum friction, while taking into account the numerous aspects affecting success. A detailed laboratory study that included software simulation was conducted to create a true ERD environment model with the goal of creating a plan to reduce friction; thus, improve production.
During one of the ERD intelligent projects, the service company team successfully simulated a scenario showing how the drilling fluid behaves under downhole conditions. Taken into consideration were temperature and pressure, the effect of tripping pressures on the equivalent static density (ESD), the effect of drilling parameters on equivalent circulating density (ECD), and the effect of lubricants on performance of different types of fluid design. A comprehensive study of all the parameters was completed, and their effect on drilling performance was determined. Both laboratory-prepared fluids and field fluids were further studied for high-pressure/high-temperature (HP/HT) rheology, lubricity, tripping pressure calculations, and ECD predictions to identify any gaps. Both data sets were consistent, allowing for excellent predictions for the fluid performance when well geometry is known.
A wide range of lubricants, both solid and liquid, and their effects were studied as well as the effect of using ester-based oil to formulate nonaqueous synthetic fluid. The study was extended to include both clay-based and clay-free invert emulsion fluids (IEF), including variable concentrations of ester-based fluid at different oil/water ratios and with different types of lubricants to present a comprehensive overview of all aspects of lubricity.
A challenging explorative deep high-pressure/high-temperature (HP/HT) well was planned and executed in the Mediterranean area of offshore Egypt. The expected bottomhole static temperature (BHST) and bottomhole pressure (BHP) were 400°F and 21,000 psi, respectively. To fulfill the requirements, a customized fluid was necessary during the planning phase. The main target was to achieve mud thermal stability. It was necessary to ensure longer mud exposure time during the extensive planned well-data acquisition of the explorative well to be drilled. Extensive laboratory work was required to develop a mud formulation with the lowest mud rheology. The aim was to build a suitable hydraulic model and manage equivalent circulating density (ECD) during the execution phase to achieve the smallest ECD impact. The drilling fluid was designed to help minimize pressure spikes resulting from the nature of the gel strengths when initiating circulation after downtime for connection for trips. Another fluid challenge was avoiding barite sag under HP/HT conditions to mitigate well-control issues during execution. During the planning phase, several laboratory tests were conducted using different base oils available in the market to deliver the best rheological model in accordance with the expected bottomhole temperature (BHT) and to achieve longer mud thermal stability, up to 168 hr static condition, at 392°F. The customization of the proper combination of high-performance additives and invert emulsion mud formulations was designed for a suitable fluid hydraulic model for each hole section, helping minimize the ECD in dynamic conditions as well as induced losses as potential causes of well-control issues. Drilling fluid, pressure, and temperature behavior were optimized during the planning phase. During the execution phase, over 516 days, operations never stopped to condition the fluid, and zero non-productive time (NPT) was recorded, confirming expectations under downhole conditions. All casing ran smoothly to the target depths; moreover, intensive logging programs, running nine days each, proved highly successful, including pressure points and fluid sampling.
Drilling Fluid Design in HP/HT Challenges
Planning HP/HT wells entails significant drilling challenges. Rig selection and its capability are very important to meet the specific requirements and can be costly. By definition, high-pressure wells require high mud weight with consequently high solids content, and this combination results in a low rate of penetration, extending drilling and fluid exposure time. Planning and designing HP/HT drilling fluids are fundamental for building the hydraulic model at a certain temperature and under pressure conditions to help minimize NPT and therefore drilling costs.
Viscosity and Density are important physical parameter of crude oil, closely related with the whole processes of production and transportation, and are very essential properties to the process design and petroleum industries simulation. As viscosity increases, a conventional measurement becomes progressively less accurate and more difficult to obtain. According to the literature survey, most published correlations that are used to predict density and viscosity of heavy crude oil are limited to certain temperatures, API values, and viscosity ranges. The objective of present work is to propose accurate models that can successfully predict two important fluid properties, viscosity and density covering a wide range of temperatures, API, and viscosities. Viscosity and density of more than 30 heavy oil samples of different API gravities collected from different oilfield were measured at temperature range 15oC to 160oC (60oF to 320oF), and the results were used to ensure the capability of proposed and published correlations to predict the experimental viscosity and density data. The proposed correlation can be summarized in two stages. The first step was to predict the heavy oil density from API and temperature for different crudes. The predicted values of the densities were used in the second step to develop the viscosity correlation model. A comparison of the predicted and actual viscosities data, concluded that the proposed model has successfully predict all data with average relative errors of less than 12% and with the correlation coefficient R2 of 0.97, and 0.92 at normal and high temperatures respectively. Meanwhile, the results of most of the available models has an average relative error above 40%, with R2 values between 0.19 to 0.95. These comparisons were made as a quality control to confirm the reliability of the proposed model to predict density and viscosity values of heavy crudes when compared with other models.