Wellbore instability is caused by the radical change in the mechanical strength as well as chemical and physical alterations when exposed to drilling fluids. A set of unexpected events associated with wellbore instability in shales account for more than 10% of drilling cost, which is estimated to one billion dollars per annum. Understanding shale-drilling fluid interaction plays a key role in minimizing drilling problems in unconventional resources. The need for efficient inhibitive drilling fluid system for drilling operations in unconventional resources is growing. This study analyzes different drilling fluid systems and their compatibility in unconventional drilling to improve wellbore stability.
A set of inhibitive drilling muds including cesium formate, potassium formate, and diesel-based mud were tested on shale samples with drilling concerns due to high-clay content. An innovative high-pressure high temperature (HPHT) drilling simulator set-up was used to test the mud systems. The results from the test provides reliable data that will be used to capture more effective drilling fluid systems for treating reactive shales and optimizing unconventional drilling.
This paper describes the use of an innovative drilling simulator for testing inhibitive mud systems for reactive shale. The effectiveness of inhibitive muds in high-clay shale was investigated. Their impact on a combination of problems, such high torque and drag, high friction factor, and lubricity was also assessed. Finally, the paper evaluates the sealing ability of some designed lost circulation material (LCM) muds in a high pressure high temperature environment.
With high reservoir heterogeneity in terms of permeability and fluid properties, substantial amounts of oil are produced along with water. At water cuts higher than 96–98%, wells become uneconomic and are shut in or undergo water shut-off treatments. For this reason, shutting off water flow through thief zones in flooded reservoirs to prevent it from entering wells is one of the biggest technical challenges in enhancing oil recovery from mature multi-reservoir oil fields.
As the water cut increases, water flow through thief zones must be reduced, along with the amount of water entering the well, to enhance sweep efficiency in lower-permeability portions of the reservoir. A new technology employing polymer dispersed systems (PDS) shuts off formation and injected water flows by increasing flow resistance in thief zones. This process redistributes the energy of the injected water in the reservoir and helps produce oil from unswept zones, thus increasing flooding efficiency and oil recovery. PDSs do not require drastic changes in existing development systems and are employed together with conventional water-flooding methods.
This paper presents studies of basic and modified PDS versions for oil recovery enhancement adapted for conditions existing in the Vyatka area of the Arlan oil field containing poorly continuous reservoirs with lithofacies heterogeneity. This depleted area had a stable, high water cut.
The new method for enhancing water flooding efficiency using polymer dispersed systems presented in the paper selectively increases flow resistance in the thief zones of productive formations with a resulting increase in sweep efficiency.
With the current applications of CO2 in oil wells for enhanced oil recovery (EOR) and sequestration purposes, the dissolution of CO2 in the formation brine and the formation of carbonic acid is a major cause of cement damage. This degradation can lead to non-compliance with the functions of the cement as it changes compressive and shear bond strengths and porosity and permeability of cement. It becomes imperative to understand the degradation mechanism of cement and methods to reduce the damage such as the addition of special additives to improve the resistance of cement against acid attack. Hence, the primary objective of this study is to investigate the effects of hydroxyapatite on cement degradation.
To investigate the impacts of hydroxyapatite additive on oil well cement performance, two Class H cement slurry formulations (baseline/HS and hydroxyapatite containing cement/HHO) were compared after exposure to acidic environments. To evaluate the performance of the formulations, samples were prepared and aged in high-pressure high-temperature (HPHT) autoclave containing 2% brine saturated with mixed gas containing methane and carbon dioxide. Tests were performed at different temperatures (38 to 221°C), pressures (21 to 63 MPa) and CO2 concentrations (10 to 100%). After aging for 14 days at constant pressure and temperature, the samples were recovered and their bond and compressive strength, porosity and permeability were measured and compared with those of unaged samples.
The results demonstrated that adding hydroxyapatite limits carbonation. Baseline samples that do not contain hydroxyapatite carbonated and consequently their compressive strength, porosity, permeability, and shear bond strength significantly changed after aging while hydroxyapatite-containing samples displayed a limited change in their properties. However, hydroxyapatite-containing samples exhibit high permeability due to the formation of microcracks after exposure to carbonic acid at high temperature (221°C). The formation of microcracks could be attributed to thermal retrogression or other phenomena that cause the expansion of the cement.
This article sheds light on the application of hydroxyapatite as a cement additive to improve the carbonic acid resistance of oil well cement. It presents hydroxyapatite containing cement formulation that has acceptable slurry properties for field applications and better carbonic acid resistance compared to conventional cement.
Cao, Jinrong (The University of Tokyo) | Liang, Yunfeng (The University of Tokyo) | Masuda, Yoshihiro (The University of Tokyo) | Koga, Hiroaki (Japan Oil, Gas and Metals National Corporation) | Tanaka, Hiroyuki (Japan Oil, Gas and Metals National Corporation) | Tamura, Kohei (Japan Oil, Gas and Metals National Corporation) | Takagi, Sunao (Japan Oil, Gas and Metals National Corporation) | Matsuoka, Toshifumi (Fukada Geological Institute)
In this paper, we present an improved method to predict the methane adsorption isotherm for a real shale sample using molecular dynamics (MD) simulation with a realistic kerogen model. We compare our simulation results both to the experiment and to the simulation results on the basis of a simple graphite model, and show how our procedure leads to the creation of more accurate adsorption isotherms of a shale sample at a wide range of pressure. A Marcellus shale sample was chosen as an example to demonstrate how to calculate the adsorption isotherms using MD simulations. Type II kerogen molecular model was selected for the dry gas window. The constructed bulk kerogen model contains mesopores (> 2 nm) and micropores (≤ 2 nm) inside. Ten different mesopore sizes of kerogen nanopore systems were constructed. According to the characteristics of methane density distribution in the simulation system, three regions can be clearly distinguished, free gas, adsorbed gas, and absorbed gas. We show that the adsorbed gas per unit pore volume increases with the pore size decreased. This is similar to previous molecular simulations with graphite model. For predicting the total adsorption isotherm of a real shale sample, both adsorbed and absorbed gas were considered. For the adsorption amount, the calculated adsorption isotherms were averaged based on pore size distribution of that Marcellus Shale sample. For nanopores smaller than 5 nm, we used total organic carbon (TOC) data to weight the absorption contribution in the kerogen bulk (i.e. inside the micropores). The total adsorption isotherm thus obtained from our simulations reproduced experiments very well. Importantly, kerogen model has overcome the difficulties of prediction using graphite models (i.e. an underestimation of adsorption under high pressure conditions) as documented in previous studies. Furthermore, we predicted the adsorption isotherms for higher temperatures. With the temperature increased, lower adsorption amount is predicted. The novelty of our improved method is that it is able to predict methane adsorption isotherm at a wide range of pressure for a shale sample by considering both adsorption in kerogen mesopores and absorption in kerogen bulk. It can be readily used for any shale sample, where the pore size distribution, porosity, and TOC are known. We remark that the above results and conclusion resulted from our simple assumption. Further discussion might be necessary.
Tong, Fangchao (Yanchang Petroleum) | Tang, Mingming (Yanchang Petroleum) | Chen, Gang (Yanchang Petroleum) | Wang, Ningbo (Yanchang Petroleum) | Liu, Peng (Schlumberger) | Yan, Gongrui (Schlumberger) | Lin, Wei (Schlumberger)
Drilling horizontal wells in YB gas field in Ordos Basin presents significant challenges due to severe wellbore instabilities problems in drilling through Permian Lower Shihezi and Upper Shanxi formations, where laminated shales overlies with sand and coal seam. In first phase of horizontal wells drilling, most wells encountered severe wellbore instabilities including pack-off, stuck-pipe, over-pull, drilling pipe lost in hole and even side track. Post-well analysis showed that these horizontal wells instabilities mainly occurred in Permian Lower Shihezi and Upper Shanxi formation where most cavings and drilling events (stuck-pipe, over-pull) were observed. In contrast, vertical exploration wells have no such instability issues in same interval. To analyze and understand the mechanism of wellbore instability issue and provide optimal mud weight and better drilling practice to reduce the risk of wellbore instabilities, an anisotropic wellbore stability modeling using Plane-of-Weakness (PoW) failure criterion was carried out in this study. The PoW failure criterion is adopted to compute the onset of rock shear sliding and/or fracture along a weak plane (bedding or fracture) and identify the potential wellbore instability risk in drilling through anisotropic rock formations. The influence of bedding orientation, rock anisotropic elastic and strength properties, and wellbore trajectory on the wellbore stability are all included in the model.
This paper describes the process and workflow of conducting PoW wellbore stability modeling for YB field wellbore drilling. The proposed drilling parameters (stable mud weight) from the modeling and its application and improvement for next wells drilling, are also included. The analysis showed that the laminated shale and coal intervals were very prone to fail when well drilled with deviation between 600 to 850. The stable mud weight computed from PoW for drilling through these intervals is 1.40-1.45 g/cc, where as it is 1.20-1.25 g/cc from conventional isotropy wellbore stability model, which was not enough to keep wellbore stable. Based on results from PoW modeling, drilling mud weight scheme was updated and applied to another 3 horizontal wells planned at nearby location. All these three wells were drilled and completed safely without severe wellbore instability issue. In these wells’ 216mm (8.5 in) section, wellbore instability related non-productive time (NPT) was reduced about 11.5 days per well and section time was reduced about 26 days per well.
This PoW modeling was first time applied in wellbore stability analysis for horizontal well drilling at Ordos Basin and the results are satisfied and encouraged. The insights provided in this paper suggests that, for drilling in other locations with similar instability challenges, PoW modeling will be a better choice to provide solution and recommendation to ensure drilling safely, improve drilling efficiency and reduce drilling costs.
Zhou, Chao (SINOPEC Research Institute of Petroleum Engineering, China University of Petroleum-Beijing) | Zhang, Tongyi (SINOPEC Research Institute of Petroleum Engineering) | Wu, Xiaodong (China University of Petroleum-Beijing) | Zhao, Fei (Engineering Technology Research Institute of Huabei Oilfield Company) | Xiong, Xiaofei (China University of Petroleum-Beijing)
Vortex drainage gas recovery is a new drainage gas recovery technology. However, its operating mechanism has not been figured out. Theoretical analysis of force condition of the liquid film in the wellbore vortex flow field is still lacking, and dynamic analysis method of the liquid film is not established. The objective of the proposed paper is to establish the liquid film dynamic analysis model and calculate the optimal helical angle of the vortex tool. Dynamic analysis of the liquid film in the wellbore vortex flow field is carried out on the basis of the flow pattern and force condition of the liquid film. Expression of each acting force is determined and the force equilibrium equation is obtained. Referring to the annular flow theory, friction coefficient and average thickness of the liquid film are calculated. Through derivation of the vertical resultant force equation of the liquid film, the optimal helical angle of the vortex tool is obtained. Then, vortex tools were designed and deployed in the wellbore of a gas well in field. Field study shows that the relative difference of the optimal helical angle obtained by liquid film dynamic analysis relative to that obtained by numerical simulation is less than 4%. The optimal helical angle calculated by the liquid film dynamic analysis model is reliable and provides guidance for the structure optimization of vortex tools. Optimal helical angle would increase with well depth decreases because of enhancement of fluid-carrying capability of the gas. The liquid film dynamic analysis model can reasonably explain the motion and force condition of the liquid phase in the wellbore vortex flow. Compared with the conventional annular flow field, vortex flow filed includes additional centrifugal force on the liquid film, which may benefit the upward motion of the liquid film. The liquid film dynamic analysis model in the wellbore vortex flow field and the formula for calculating the optimal helical angle of the vortex tool are established for the first time, whose results fill the gap in existing studies and have a guiding significance for optimization design and field application of vortex tools.
Wu, Jiwei. (East China University of Science and Technology) | Pan, Jiake. (East China University of Science and Technology) | Wang, Hualin. (East China University of Science and Technology) | Wang, Lixiang. (PetroChina Southwest Oil & Gas Field Company Chengdu Natural Gas Chemical General Plant) | Lan, X. (PetroChina Southwest Oil & Gas Field Company Chengdu Natural Gas Chemical General Plant) | Yang, L. (PetroChina Southwest Oil & Gas Field Company Chengdu Natural Gas Chemical General Plant) | Liu, Wenjin. (SJ Petroleum Machinery CO.SINOPEC)
With the flourishing shale gas exploitation produces more oil based mud (OBM) drill cuttings, the hardto-treat hazardous wastes burdens the local environment heavily. However, the problems of high energy consumption, high treating cost and high risk secondary contamination still remain unsolved for mainstream technologies such as thermal distillation, incineration and chemical extraction. Therefore, a new method and device based on cyclone desorption of high speed self rotation to dispose of OBM drill cuttings is put forward to overcome the challenge. The working process includes: viscosity reduction in heated gas; cyclone deoiling; condensation and recycling of exhaust; separation of oil and water in coalesce. It is found that the self-rotation speed of solid particles in a 3-dimensional rotating turbulent flow field of cyclone is as high as 2,000 to 6,000 rad/s which coexists with evolving speed of s The remarkable pulsing centrifuge force in the rotation and revolution coupling motion can enhance the desorption process of the oil so as to accomplish the separation and enrichment of oil and solid phase, and deep removal of organics from OBM drill cuttings.
Pitting corrosion on the tubing ID has caused failures of CT strings in operations across every operating region, with unconventional plays in North America being especially affected. A localized coating that can be applied to the bias weldment has been developed to protect the most susceptible portion of the coiled tubing string from corrosion. This paper will discuss the development process for the coating as well as initial case histories.
Steel is plastically deformed in the manufacturing process to make coiled tubing, and the product is repeatedly plastically deformed in operations. As a result, coatings have historically not been successful with coiled tubing due to insufficient adherence to the tubing, which is the substrate.
Once the decision was made to pursue a localized coating, a test plan was developed to test different iterations of the coating including coating materials and application processes. The initial testing plan included checking for adherence to the substrate as well as resistance to acid with the goal of highlighting a methodology for a working prototype.
The results of the testing plan are provided and were used to determine the path forward to commission a working prototype. Physical Vapor Deposition (PVD) was selected as the best method for application of the local coating. PVD operates by exciting a target within a vacuum chamber, which coats the substrate. Coiled tubing is a continuous product, which prevents the use of a traditional vacuum chamber. This development led to the creation of the first-ever vacuum chamber of its kind—one that does not entirely enclose the product.
The working PVD prototype has been successfully installed at the manufacturing facility in Houston, and test strings coated locally on the bias welds have been created. The paper will describe the first beta-test strings that have been released to the field and any reported observations from the CT service companies.
This paper describes a new processing technique for the manufacturing of coiled tubing. Initial results show that the coating can dramatically improve operations, especially the prevention of unexpected failures with minimal cost impact to the coiled tubing operator.
The second round will offer 19 offshore blocks clustered in five zones to continue natural gas development in the eastern Mediterranean’s Levant Basin. Devon Energy will be getting simpler and smaller by selling two no-growth assets—gas acreage in the Barnett Shale in Texas and oil sand operations in Canada. Its future is staked on growing oil production in the Permian’s Delaware Basin and three other unconventional oil plays. The Oklahoma City independent has a new-look portfolio and new operational and financial priorities. And now it has enlisted an energy research firm to leverage advanced analytics and machine learning to help get the most out of its assets.