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.
Devshali, Sagun (Oil and Natural Gas Corporation Ltd.) | Manchalwar, Vinod (Oil and Natural Gas Corporation Ltd.) | Deuri, Budhin (Oil and Natural Gas Corporation Ltd.) | Malhotra, Sanjay Kumar (Oil and Natural Gas Corporation Ltd.) | Prasad, Bulusu V.R.V. (Oil and Natural Gas Corporation Ltd.) | Yadav, Mahendra (Oil and Natural Gas Corporation Ltd.) | Kumar, Avinav (Oil and Natural Gas Corporation Ltd.) | Uniyal, Rishabh (Oil and Natural Gas Corporation Ltd.)
The paper describes the feasibility of revisiting old sands, for improving the recovery factors and enhancing production, which otherwise were already abandoned. The paper also outlines the systematic methods for predicting the onset of liquid loading in gas wells, evaluation of completions for optimization and comparison of various deliquification techniques. ONGC is operating in two gas fields in eastern and western regions in India. Earlier in both the fields, many sands had to be closed/isolated after the wells ceased to flow due to liquid loading in the absence of continuous deliquification. In order to predict liquid loading tendencies and identify opportunities for production enhancement, performance of 150 gas wells has been analyzed. To select most suitable deliquification technique for the present condition, all technically feasible methods have been evaluated and compared in order to get the maximum ultimate gas recovery possible.
After an extensive study, 3 wells were identified in the preliminary stage and SRP was selected as the most suitable Deliquification technique. Initially, two non-flowing wells, which had ceased due to liquid loading and were about to be abandoned, were selected. After SRP installation and sustained unloading of water for about 30 days, these wells started producing 12000 SCMD gas. In the third well, one of the top sands had earlier been isolated due to liquid loading and production history indicated that the isolated sand had a very good potential. Also, production from the well was declining in the current bottom operating sand as well due to liquid loading. Encouraged by the results that deliquification had yielded in the initial two gas wells, the isolated sand interval in the third well was opened again with the aim to revive production. The well was re-completed with SRP with both the reservoirs open. Before deliquification, the well was producing about 15000 SCMD gas from the bottom sand. After SRP installation and continuous deliquification, the well started producing gas at a stabilized rate of 45000 SCMD, thereby resulting in an additional gas recovery of 30000 SCMD for nearly one year as on date. The approach of putting in place continuous deliquification techniques has not only helped in enhancing production from the existing reservoirs, but has also opened up new avenues to revisit the earlier isolated / abandoned reservoirs for possible enhanced recoveries.
In recent years, an industry-wide demand for increased drilling efficiency has led to the development of technologies and methods focused on multi-well pad development and the minimization of the transportation of drilling rigs between locations. Studies have indicated the potential for improving drilling cycle efficiency through improvements in rig design and procedural documentation but have given limited consideration to the unitization and mobilization practices surrounding ancillary components such as mud pumps, light plants, bulk fluid storage and other systems that comprise modern land rigs. This study examines current unitization practices, as well as offers alternative methods of integrating ancillary system components to improve current transport configurations. Specifically, ancillary systems whose transport dimensions and weight exceed the federal and state requirements for commercial vehicles operating within the National Highway Freight Network (NHFN).
In this study, the application of transport logistics software is used to demonstrate that there exists the potential for significant reduction in land rig mobilization costs through revised unitization of drilling rig ancillary systems. Permit data from proposed wells located in the Permian, Bakken, and Marcellus are utilized to develop transport scenarios whose focus is to quantify the impact of ancillary system unitization on the total fee structure associated with rig mobilization between geographical regions. Within each scenario, ancillary systems from currently active rigs are compiled and itemized according to their weight, transport dimensions, and degree of component unitization. The resulting schedule is then processed through transport logistics software to identify fee schedules associated with oversize permits, overweight permits, civilian and police escorts, driver rate/fuel costs, and associated service fees for the individual loads. Following the conclusions derived from the analysis of the existing rig systems, the series of transport scenarios are repeated using revised component configurations. The revised system employs a combination of divisible and non-divisible loads whose components are either integrated as part of dedicated transport trailers or located within ISO containers loaded onto commercially available transport trailers. The fee schedules from active rigs, as well as the results from the proposed unitization, are explored in detail to identify critical areas for improvement regarding unitization practices for active rigs and future builds.
An Under Balanced Drilling (UBD) pilot project in the Heera and Mumbai High fields of Western offshore India was recently completed successfully. The objective of the project was to establish whether the technology can improve productivity performance in the reservoir section, avoid reservoir damage and thereby enhance oil production from the wells. This paper incorporates the drilling experiences and challenges faced during execution of this pilot project, the well design considerations and methodology, evaluation of the drilling fluid systems and also describes the tangible benefits of using this technology in the drilling of these sections and wells. In terms of the productivity gains from drilling these wells using UBD technology, through the sub-hydrostatic formations offshore Mumbai, the results were very positive. With the success and encouraging results from the pilot project, more wells are now planned, including wells in the losses-prone and depleted Mumbai High and Neelam fields, to incorporate the experiences of the learning curve.
The effectiveness of secondary and tertiary recovery projects depends heavily on the operator's understanding of the fluid flow characteristics within the reservoir. 3D geo-cellular models and finite element/difference-based simulators may be used to investigate reservoir dynamics, but the approach generally entails a computationally expensive and time-consuming workflow. This paper presents a workflow that integrates rapid analytical method and data-analytics technique to quickly analyze fluid flow and reservoir characteristics for producing near "real-time" results. This fast-track workflow guides reservoir operations including injection fluid allocation, well performance monitoring, surveillance, and optimization, and delivers solutions to the operator using a website application on a cloud-based environment. This web-based system employs a continuity governing equation (Capacitance Resistance Modelling, CRM) to analyze inter-well communication using only injection and production data. The analytic initially matches production history to determine a potential time response between injectors and producers, and simultaneously calculates the connectivity between each pair of wells. Based on the inter-well relationships described by the connectivity network, the workflow facilitates what-if scenarios. This workflow is suitable to study the impact of different injection plans, constraints, and events on production estimation, performance monitoring, anomaly alerts, flood breakthrough, injection fluid supply, and equipment constraints. The system also allows automatic injection re-design based on different number of injection wells to guide injection allocation and drainage volume management for flood optimization solutions. A field located in the Midland basin was analyzed to optimize flood recovery efficiency and apply surveillance assistance. The unit consists of 11 injectors and 22 producers. After optimization, a solution delivering a 30% incremental oil production over an 18-month period was derived. The analysis also predicted several instances of early water breakthrough and high water cut, and subsequent mitigation options. This system couples established waterflood analytics, CRM and modern data-analytics, with a web-based deliverable to provide operators with near "real-time" surveillance and operational optimizations.
Yang, Junjie (Baker Hughes, a GE Company) | Karam, Pierre (Baker Hughes, a GE Company) | Cozyris, Kristian (Baker Hughes, a GE Company) | Hustak, Crystal (Baker Hughes, a GE Company) | Doherty, James (Riley Exploration – Permian, LLC) | Allen, Carmen (Riley Exploration – Permian, LLC)
As a well-known tight oil dolomite reservoir in Texas, San Andres formation has attracted broad attention about horizontal drilling and development strategy. To optimize the oil recovery and asset’s economics, the aim of the study was to use an integrated approach to understand reservoir heterogeneity and performance, determine optimal landing zone and its impact on production, understand fracture geometry using different pumping schedules, and the optimal cluster spacing. In addition, the potential benefit of a refrac and infill drilling program was also investigated.
To tackle the optimization problem, an integrated reservoir modeling workflow was developed. Starting with a 1-D geomechanical model which captures the in situ stress profile and rock mechanics, hydraulic fracture modeling was developed to history match the treatment process, and therefore a comprehensive fracture geometry can be estimated. In the interim, a geological model with populated reservoir properties was established based on the offset data including petrophysical logs, imaging logs and cores. After calibration, the dynamic reservoir model was built to test multiple sensitivity runs for an optimized field development strategy.
Geological modeling separated the field into two models to study the variation of properties on the east and west side. The east section shows a higher porosity and lower saturations. Those water saturations increase below the main pay zone indicating a potential water source. In addition, special core analysis shows a strong oil-wet nature of the reservoir rock. In the east section, sensitivity runs included infill development and variations in landing depth. It is noted that the production is not sensitive to landing zone because fracture geometry is primarily controlled by vertical stress profile. In the west section, sensitivity runs included refrac, infill drilling, and a greenfield development plan with variations on well spacing and completion design. The observation shows tighter well spacing or cluster spacing accelerates the oil production in early time, while yielding similar long term oil recovery and shows a combination of refrac and infill drilling yields a 21% incremental oil production beyond the base case.
This study provides valuable information about the workflow to develop tight oil plays by describing a detailed case study. The result also sheds light on the optimized field development strategy for analogous fields.
This study presents a novel, integrated workflow to maximize recovery using PVT compositional modeling, history matching, and numerical reservoir simulation in a tight oil sand formation, the Second Bone Spring. Advancements in unconventional resource development have enabled the Delaware Basin to become highly significant. However, optimizing the development of each formation is still lacking in understanding. This study is one of multiple future studies over tight reservoirs in the Delaware Basin and exhibits a comprehensive approach. Properties that will be optimized are well spacing, reservoir parameters, and EOR feasibility.
To determine the behavior and optimize the development of each of these reservoirs, data from multiple sources was necessary. The data compiled consisted of reports from PVT analysis, completions design, petrophysical analysis, daily production and pressure, deviation surveys, structure and isopach maps, and well design. This data was then implemented into a 3D numerical reservoir simulator (CMG-GEM), first to confirm PVT output in a compositional simulation (CMG-WINPROP), then to simulate up to 20 years of production, and finally to use uncertainty analysis (CMG-CMOST) to optimize reservoir input parameters. Once a base case scenario was established, we then furthered our investigation of well spacing and EOR feasibility by setting up multiple different scenarios for each and running them for 20 years. EOR scenarios included 1-3 month huff-and-puff CO2, as well as low salinity water injection. Results are normalized per foot of completely lateral length and lab data is implemented in EOR simulations.
Our results confirm that reservoir parameters, once established after uncertainty analysis, have a large impact on both optimizing well spacing and EOR feasibility in the Second Bone Spring formation. With each well having very similar cluster spacing, proppant amount and type, and fracturing fluid and type, up to 250 feet of inter-well spacing is unaccounted for. Optimized models show that closer spacing of at least 150 feet can increase EUR estimates an average of 11.25%. An increase of 5-17% recovery is observed once a smaller spacing is implemented. EOR models showed that CO2 and low salinity water injection are viable candidates for the formation (7.25-9% increase for CO2, 6.25% for LSWI).
This integrated study refines our reservoir parameter estimates and helps identify potential to maximize recovery. It suggests that a tighter spacing is necessary to cover a larger portion of the reservoir, as well as showing that EOR is feasible. An improved understanding of the entire reservoir leads to better production and economic estimates.
The effects of horizontal well geometry remain debatable in most production modeling works. Most of recent reports fail to mention the effects of well geometries, especially in severe slugging cases. This study presents a qualitative comparison between different well geometries and their impacts in production performance of horizontal wells.
The study utilizes a transient multiphase simulator to mimic the production from a horizontal well over a 12-hour period. The well has a 2-7/8″ ID tubing with TVD of approximately 5000 ft and MD of 10000 ft and maximum inclination angle of 10º within the horizontal section. The trajectories of horizontal section in the well include 5 cases, 5 undulations, hump (one undulation upward), sump (one undulation downward), toe-up and toe-down. These configurations are the representative examples of horizontal wells. A reservoir with a given deliverability equation and several perforation stages is used to provide well inflow. The impacts of reservoir deliverability, GOR, pressure and temperature are studied for all well geometries.
The simulation results offer some valuable insights into the effects of well trajectory on production performance, including borehole pressure profile, liquid holdup, gas and liquid rate variations with time, and cumulative gas and liquid production. At high production rates, severe slugging is not observed, and thus, the well geometry effects are minimized with a consistent production at the surface. However, toe-up configuration exhibits a slightly better performance than the others.
As the productivity and pressure reduces throughout the life of a well, the impacts of well trajectories become clearer. The presence of severe slugs and blockage of perforations near the toes causes a noticeable drop in production. During severe slugging, the pressure profile reveals longer fluctuation cycles, resulting in extreme separator flooding issues. The slugging frequencies are compared among different well geometries. Toe-down case exhibits lower slugging severity. As a result, toe-down well produces the highest cumulative liquid and gas rates. The presence of liquid blockage is observed in lateral and curvature sections. The toe-up and hump configurations exhibit the most severe slugs with minimum cumulative gas and liquid productions. The differences in productions among well trajectories exceed 30% under different well configurations.
With the augmented growth of production from unconventional reservoirs, horizontal well technology has grown in oil and gas industry, yet study of well geometry in production system remains to be limited. This study is a unique effort to optimize well configuration and perforation placement in order to alleviate multiphase flow problems in the wellbore. Providing the practical potential on simulation works, this study provides a predictive guidline to connect well geometry selection and production optimization.
The paper discusses a petrophysical evaluation method for complex tight gas formations in a mature and partially depleted gas condensate field in Oman, allowing a full petrophyscial evaluation as well as geomechanical modeling from a source-less petrophysical dataset, thus reducing operational data acquisition risk in partially depleted reservoirs without compromising on hydraulic fracturing design. The developed methodology includes the volume of shale estimation from correlation with Poisson's ratio for the feldspathic rich tight formation. This methodology was used in deep tight fields in Oman for more than 3 years in both vertical and highly deviated wells greatly reducing the risk, logging cost and complexity of operations.
Engineers commonly expect symmetric fracture wings in multiple transverse fracture horizontal wells (MTFHWs). Microseismic surveys have shown asymmetric hydraulic fracture grow away from the recent fractured wells and grow towards previous produced wells. It might be caused by the elevated stress around the recently fractured well and the reduced stress near the depleted wells. This paper presents the asymmetric fracture growth observed by the microseismic events and develops a simple model to simulate the fracture propagation and its impact on the well productivity. Motivated by the microseismic observations, we developed a simple fracture model to simulate asymmetric fracture wings that can capture the behavior of fracture hits between two adjacent horizontal fractured wells. Also, we developed a model to estimate the productivity of a well with asymmetric fractures. The newly developed fracture model shows that the fracture can grow asymmetrically if the horizontal well is located where stress field is different between its two sides.