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Rosland, Habil Akram (Halliburton) | Peytchev, Peter (Cairn Energy India) | Sarkar, Shibatosh (Cairn Energy India) | Mukherjee, Supriya (Cairn Energy India) | Govind, Balu (Cairn Energy India) | Malik, Sumit D. (Cairn Energy India)
Abstract This paper discusses the approach of Cairn Energy India Ltd. (CEIL) in the use of a state of the art technology that integrates all relevant data scenarios for designing and planning development wells in the Mangala field of Western Rajasthan, India. To improve the quality of the well planning process, CEIL has realized the importance of a collaborative well planning environment, which was implemented by means of its world-class 3D visualization center that enables multidisciplinary well planning workflows to take place in the subsurface environment. The environment includes physical infrastructure, new technology, and data. A fully functioning collaborative well planning environment enables the drilling team to plan wells using engineering tools, including drilling target definition and refinement, well pad positioning, and wellbore position uncertainty, based on company anti-collision policies, with geosciences team capacity to validate those designs against their subsurface data. The Mangala field development process has established the success of CEIL with rapid, multisolution iterations well planning to the entire asset team and improved wellbore positioning based on potential engineering constraints. This process takes the optimum reservoir drainage into account with possible geological hazards and reduces the operational cost by complementing technical expertise across the broad disciplines. The workflow aids wellbore and drilling optimization and improves decision making and collaboration throughout the field development sequence. The paper explains the detailed aspects of collaborative well planning and optimization of well placement methodology used for Mangala field, which includes 11 horizontal wells that were largely designed as shallow extended reach drilling (ERD) wells. It demonstrates how this method significantly improved the mutual workflow between departments and increased efficiency. This paper also describes the interactive design that dramatically decreased the cycle time in planning more than 160 wells in the field, which contributed to effective development plans and well placement based on geological, drilling, and completion requirements.
Abstract In an unconventional reservoir, a thorough understanding of the spatial distribution of the physical properties of rocks, in terms of facies, porosity, and permeability, is essential for realistic dynamic reservoir simulation and history matching. This paper provides a practical solution for enhanced reservoir performance analysis, combining the results of geological interpretation, 3D geostatistical electrofacies modeling, and flow simulation in an unconventional Eagle Ford shale play. The first step of the integrated approach is the application of hierarchical clustering methods to identify electrofacies groups using log curves. Next, electrofacies are converted into lithofacies through an analysis of core data. The 3D lithofacies and petrophysical distribution model is then created using stochastic geostatistical techniques. In the reservoir simulation step, the discretized facies model is constrained to assign geomechanical properties. Thus, a realistic fracture model is generated with a proper definition of fracture characteristics to control flow simulation and to enable better history matching. The solution presented in this paper provides an objective means of using the integrated approach in an accurate definition of fracture properties, in terms of length and orientation, for reservoir simulation and production forecasting in unconventional reservoirs.
Abstract After a successful pilot application in the Haynesville Shale, Shell Upstream Americas is currently taking steps to conduct all of its directional drilling, MWD/LWD and geosteering operations in the Americas and beyond from remote drilling centers. The main drivers for the use of these centers are: More wells can be directionally drilled with the involvement of the most knowledgeable / most experienced directional drilling / MWD/LWD / geosteering staff, while at the same time new staff can be trained and developed effectively from a central location. Safety is improved by having less staff commuting back and forth to the rig site (i.e. reducing the number of driving-related accidents), and by reducing occupational exposure through the decrease in number of people "in harm's way" present at the rig-site itself. Remote geosteering at a central facility allows for efficient communication between geologists and interpreters, with a single geosteering expert and a single geologist being able to handle a large number of geosteering operations at the same time, while at the same time greatly improving the speed of decision-making. Staying within the shale target zone and reduction of the number of geosteering corrections and doglegs while landing the horizontal section, resulting in noticeably improved wellbore quality, which yields immediate benefits in the ease of running production casing and will ultimately translate in higher hydrocarbon recovery. The learnings and best practices associated with the ongoing implementation of the remote drilling centers for unconventional shale drilling operations in the Americas are compiled. This includes a review of the technologies involved, the new workflows that were implemented, how the "people issues" were addressed, and what results - including a 90% improvement in the speed of decision making, clear improvements in wellbore placement and quality, and the drilling of best-in-class directional wells in the Eagle Ford Shale - were obtained. In addition, the future of remote directional drilling and its extension into drilling automation is briefly discussed.
Abstract World energy demand is increasing. The next trillion barrels will be harder to access, harder to find and will be in ever smaller accumulations. New discoveries will undoubtedly be more difficult to produce and will have to be done with fewer and dwindling experienced resources. The industry has begun to accept change due to their desired demand for improved efficiencies. These efficiencies include integrating the workforce (both service and operating groups), improving quality and efficiency of workflows, and improving the technologies that are feeding into the "Digital Asset™" service. Such technologies are better formation evaluation measurements, better geological models, and faster reservoir simulators, better able to integrate production data for comparison to the geological models. Connecting people and improving technology and workflows allow the right decisions to be made at the right time while spending the least amount of effort. Today, necessity drives new and more dynamic integrated operations; and more efficient working relationships are evolving. This paper will discuss the challenge of doing more with less, exploiting more difficult reserves while lowering costs, increasing profits while reducing risk, and speeding up work processes while cutting non productive time. The answers lie with in a series of steps towards cultural change: utilizing real-time collaborative environments allowing simple workflow methodologies to be applied and feeding improved measurements into improved models while continuous optimization occurs while simultaneously actual operations occur. Introduction While there is currently significant debate as to the future of oil demand, the consensus is that the current crisis will be relatively short-lived and that oil demand will return to moderate growth globally. The demand for energy as a whole will follow this same pattern. Although other forms of energy will be brought on line at varying times and intensities, none are expected to have a significant impact for the next 20–35 years. Studies suggest that currently 70% of the world's oilfields are greater than 30 years old, and the replacement rate is slightly less than 2% per year. Finding, developing, producing and refining of oil will remain a significant part of our lives for the next quarter century. We as an industry are entering a new age characterized by new and innovative ways of finding and developing reserves. Operators and service companies are identifying opportunities to do more with less and to establish the best and right time decisions for finding, planning, drilling and completing wells /fields today. Recently published industry data suggest the median age of geo-scientist, petroleum engineers and geologists is between 48 and 50. New geo-science entrants to the industry peaked in the early 90's and the number has reached a plateau. The industry is not hiring enough individuals to fill the seats of the aging subject matter experts who will be retiring in the next dozen years, although some will continue working in some capacity as contractors in the industry. We are also facing challenges with reduction of bed space for offshore installations while having to deliver expertise to more rigs with fewer expert resources. These remarks assume that the reductions in force and rig count are short-lived. However, if the low energy demand cycle is long-lived, the reduced workforce and reduced rig counts will call for a still greater need for improved efficiencies. The industry will undoubtedly have to adopt better ways to find, drill, complete, and produce hydrocarbon reservoirs. The industry has choices in how prospects are generated, how assets are developed, and how to drill and complete, while evaluating the risk compared to the financial outcome of producing fields to their maximum potential. Note that the choices are not limited to the drilling process but includes formation evaluation, prospect generation, and development of the prospect, monitoring drilling, running and design of bits, fluids, stimulation, completions, and intervention — in other words all aspects of well construction, placement, completion and production processes.
Shale development has been highly successful in North America. This has been accomplished by driving changes in every aspect of field development engineering and execution processes. In order for a shale development to succeed in countries outside the U.S. and Canada, change management must occur in many areas. Three major challenges will be discussed in this paper: 1) National, regional, and local governments must establish tax and energy policies that encourage development while protecting health, safety, and the environment as well as providing a regulatory framework; 2) the shale resource meeting minimum criteria to meet economic development standards quickly; and 3) a sustained production delivering long-term economic viability.
The first challenge includes the following
• Establishing simplified government regulations – to generate the energy company desire to develop and to satisfy people’s health, safety, environment and jobs requirements. How to generate goodwill among the parties through
• Ownership – surface/subsurface mineral rights and development taxes
• Public education on hydraulic fracturing – so the public will understand that use of hydraulic fracturing will not result in contamination of drinking water aquifers nor will water be waste. An incorrect perception and understanding of hydraulic fracturing has resulted in opposition to shale development.
• Environmental and human safety are delivered through advanced automation
• Infrastructure requirements for development.
The second challenge applies new advancements made in the last three years related to shale developments for the determination of quantitative asset economics
• Gathering the resource data needed to develop a comprehensive holistic engineering model that can successfully deliver production from an individual well perspective to a total optimized asset using the answers to the following questions.
? Where to drill
? How to drill
? Where to frac
? How to frac
? Determine the economic viability of the resource play.
The third challenge involves responses to the following questions regarding sustaining the production for longterm economic viability with highlights of lessons learned in the last three years:
• Understanding the heterogeneity of the reservoir using geophysics, geomechanics, mineralogy, and petrophysics in a systematic, accurate, and rapid manner.
• Multidisciplinary collaboration to understand and identify the “sweetspots” within the reservoir and define a development plan.
• Deliver drilling operations with minimal NPT and drill using optimized geosteering to land the lateral in the “sweetspot” to maximize the recovery potential.
• Precision fracturing with real-time monitoring to maximize hydraulic fracture area and fracture conductivity for strong initial and sustained production.
• An optimized stimulation design and proppant delivery method, using custom chemistry and proppants that prevent formation damage and ensure all perforation clusters receive effective stimulation for sustained production.
• Innovations involving water recycling, reduced use of biocide, and adoption of dual-fuel equipment have improved shale economics and reduced the environmental impact.
This paper focuses on examples of new innovations introduced over the past few years that are yielding the “best in class” rates of return through efficient execution and sustained production.