Africa (Sub-Sahara) Cairn Energy has flowed oil from its SNE-2 well offshore Senegal. Drillstem testing of a 39-ft interval achieved a maximum stabilized but constrained flow rate of 8,000 B/D of high-quality pay. A flow rate of 1,000 B/D of relatively low-quality pay was achieved from another zone. Drilled to appraise a 2014 discovery, the well lies in the Sangomar Offshore block in 3,937 ft of water 62 miles from shore. Drilling reached the planned total depth of 9,186 ft below sea level. Cairn has a 40% interest in the block with the other interests held by ConocoPhillips (35%), FAR (15%), and Petrosen (10%).
Mandal, Dipak (Oil & Natural Gas Corporation Ltd) | Baruah, Nabajit (Oil & Natural Gas Corporation Ltd) | Jena, Smita Swarup (Oil & Natural Gas Corporation Ltd) | Nayak, Bichitra (Oil & Natural Gas Corporation Ltd)
Hydrocarbon gas injection into the reservoir is one of the most effective EOR processes. In case of a dipping and light oil reservoir, immiscible gas injection can give further impetus to the oil recovery. Since, average current gas saturation in the subject reservoir has become high due to depletion rendering water injection at this late stage is found to be ineffective, scope of gravity assisted immiscible gas injection as an alternative has been evaluated to assess its impact on reservoir pressure and ultimate recovery.
The present study pertains to a high permeable clastic light oil reservoir with reasonable dip, belonging to an old field of South Assam Shelf of India under production since 1990 with current recovery of 22% of STOIIP. The reservoir being undersaturated with no aquifer support, shows significant decline in reservoir pressure (260 ksc of initial pressure to current level of 50 ksc). Simulation study has been carried out on a fine scale geo-cellular model. Multiple realizations have been created considering combinations of oil producers and gas injection wells assigning varied rates to study the different development scenarios and impact on recovery improvement. The study indicates an incremental oil recovery of about 14% of STOIIP by immiscible gas injection.
Based on the study, immiscible gas injection has been initiated in the reservoir on pilot scale basis through two gas injectors with continuous monitoring. After gas injection during last one year, reservoir pressure increased about 25 ksc and consequently per well productivity also increased. Non-flowing well starts producing and currently sand is producing nearly 25% higher than earlier production before gas injection. Based on the encouraging result from pilot gas injection, decided to expand the process at field level and subsequently drilling of new oil producers after jacking up of reservoir.
The study has brought out that the gas injection into shallower portion of the reservoir yields better sweep efficiency to displace the oil to the deeper portion of the reservoir due to the gravity effects and hence, appropriate locales of the reservoir are targeted for additional input generation to augment the oil recovery.
Baruah, Nabajit (Oil & Natural Gas Corporation) | Mandal, Dipak (Oil & Natural Gas Corporation) | Jena, Smita Swarupa (Oil & Natural Gas Corporation) | Sahu, Sunil Kumar (Oil & Natural Gas Corporation)
This paper examines the prospect of Gas Assisted Gravity Drainage (GAGD) process in improving recovery from a sandstone reservoir by injecting produced gas back into the crestal part of the reservoir. Besides recovery improvement, immiscible gas injection ensures near Zero Flaring strategy. The process has been found to be ideal in reservoirs with high permeability and reasonable dip to maximize oil production wherever a sufficient gas source exists. Based on the study, gas injection is recommended at the crestal part of the reservoir under study at the rate equivalent to the produced gas to maintain pressure, arrest gas cap shrinkage and improve recovery.
In a very brief amount of time (geologically speaking), the exploration and production energy business has dramatically shifted to an unconventional universe where geologic risk is low, completion technology is arguably as important as the geology, and where favorable economics are the well-honed byproduct of cost reduction, sweet spot definition, drilling and completion efficiency, and midstream transmission. Having spent our entire careers (more than 40 years each) in the upstream business, it is important to step back and look at the big picture every once in a while. We have seen many exploration paradigms broken--resulting in the birth of deepwater exploration, subsalt development and, most recently, unconventional shale development. We have also seen the demise of some false saviors along the way such as the Atlantic Tethyan reef play, Destin Dome off the Gulf Coast, Mukluk in the Beaufort Sea, the lowly Lodgepole play in North Dakota, and post-sanction exploration in Libya, to name a few. Whether successful or otherwise, all of these exploration concepts required creative thought and a willingness to invest capital into what could ultimately become a commercial venture.
Pore pressure prediction is essential part of wildcat well planning. In India, Tripura sub – basin is characterised by huge anticlines, normal faults and abnormally pressured formations. These factors push the wildcat well planning in this area into wide margin of uncertainty. Pore pressures were predicted from seismic velocities by using modified Eaton’s method over the synclinal and flank part of Atharamura to understand the pressure succession towards the anticline. These predicted pore pressure on the flank part lead to a reasonable match when plotted with offset well measured pore pressures. To reduce the uncertainty fracture pressure were established by various methods such as Hubbert & Willis method and Matthews & Kelly method from predicted pore pressures. But the fracture pressures were predicted with available horizontal stress correlations due to lack of Poisson’s ratio curve for the study area. The mud pressure required to drill the well is calculated using median line principle and hence drilling mud window is established by assuming virtual tight conditions. The plot of Equivalent Circulation Density (ECD) versus depth suggest that well can be drilled with two casing policy. But it is found that adding one more casing pipe will ensure the safety of well. Casing pipes were designed on the basis of collapse pressure, burst pressure and tensile load. Finally a well plan which includes pore pressure, fracture pressure, drilling mud policy, casing policy, kick tolerance graph were proposed to give clear picture on well planning on the top of the anticline in pore pressure point of view.
In a very brief amount of time (geologically speaking), the exploration and production energy business has dramatically shifted to an unconventional universe where geologic risk is low, completion technology is arguably as important as the geology, and where favorable economics are the well-honed byproduct of cost reduction, sweet spot definition, drilling and completion efficiency, and midstream transmission. Having spent our entire careers (more than 40 years each) in the upstream business, it is important to step back and look at the big picture every once in a while. We have also seen the demise of some false saviors along the way such as the Atlantic Tethyan reef play, Destin Dome off the Gulf Coast, Mukluk in the Beaufort Sea, the lowly Lodgepole play in North Dakota, and post-sanction exploration in Libya, to name a few. Whether successful or otherwise, all of these exploration concepts required creative thought and a willingness to invest capital into what could ultimately become a commercial venture. Incumbent with any success was the realization that whatever was discovered would need to be successfully commercialized via transmission to market.
Khambra, Isha (Schlumberger) | Kumar, Ajit (Schlumberger) | Verma, Vibhor (Schlumberger) | Sarma, Rajiv (Oil India Ltd.) | Baruah, Neelimoy (Oil India Ltd.) | Prasad, C. B (Oil India Ltd.) | Bora, Pradyut (Oil India Ltd.)
The Upper Assam Basin is a matured Petroliferous situated in the northeastern part of India (
The major challenges faced in these reservoirs are high resistivity zones within sands, thereby creating an ambiguity due to very fresh water environment and a complexity in evaluation of the developed prospects between the hydrocarbon bearing and water bearing sand; Low shale density and sand matrix density contrast; Presence of gas across the sands is not effectively evident, especially in the secondary gas cap reservoir scenarios; changing reservoir dynamics due to production from decades, led to an uncertainty in identifying the current fluid contacts and last but not the least identification of mobile oil that could not be produced by existing wells under production from 60-70 years and have been left undrained. Therefore, in order to cater these challenges of old reservoirs and diminishing few unresolved uncertainties involved in redevelopment of the brown fields, reservoir saturation monitoring was carried out successfully in 50 wells in various fields which added immense value both technically and economically.
This paper has the detailed discussion about how this technique proved to be very beneficial and led to the substantial hydrocarbon gain in old wells. The reservoir saturation monitoring was carried out mainly in old wells which helped in taking the informed decision of identifying the sweet spot for hydrocarbon production. It has also helped in overcoming the uncertainty involved in the open-hole data interpretation (especially low resistivity and density contrast). This approach resulted in better understanding of the reservoir characteristics which led to ascertain potential reserves that can be characterized as the "Reserve growth".
The results of this approach also corroborated with the dynamic simulation models of various fields and enhanced the confidence on the predictive field development planning. Last but not the least it also contributed in achieving the annual hydrocarbon production target, considering other economic benefits, it led to reduced rig time spent for workover during the well life with low operational cost.
The future of Intelligent Energy (IE) is tied to the success of our Major Capital Projects (MCPs). As exploration pushes into more remote and challenging environments, IE provides technology and processes that can help make these projects viable. However, the largest MCPs have a project lifecycle of several years, and it is hard to find the right moment to introduce IE concepts – too early, and there is too much uncertainty about the overall project philosophy and scope; too late, and the project schedule, design, and budgets have already been frozen.
We present a structured approach for IE engagement that has been developed using learning from the early IE initiative at Chevron and is now used successfully to help MCPs manage challenges associated with designing for a future that can be five or more years away. This allows MCPs to maintain flexibility and avoid being locked in to aging technologies, while managing risk and avoiding expensive scope or schedule changes. IE concepts are introduced early to help influence the operating philosophy and design and to allow for consideration of research and development activities. This results in a structured program to deliver the selected IE solutions at the right time – some of which may be before first production.
Throughout the paper, we will use examples from MCPs in the Chevron portfolio to illustrate how this approach has been successful in engaging early, selecting appropriate solutions and delivering value.
We explain how the approach is aligned with the MCP project management process, assurance and documentation requirements. In each phase, there are specific requirements and deliverables, including a rigorous deployment program for the selected solutions and structured handover to the operating asset.
This paper aims to cover importance of Stakeholder Management in business continuity and its linkage with different business segments. Stakeholder Management looks at the relationships between an organization and others in its internal and external environment. Stakeholder could be a person or a group that can affect or be affected by business activities. Stakeholders can come from inside or outside of the business. Examples include customers, employees, stockholders, suppliers, non-profit groups, government, and the local community, among many others. Effective stakeholder management is very crucial to a company’s success. The core idea is that organizations that manage their stakeholder relationships effectively will survive longer and perform better than those organizations that don't. All community relations issues must be fully addressed prior to and during the development of facilities via participation and consultative mechanisms promoting active communication involving all key stakeholders.
Ensuring awareness of cultural differences, respecting diversity and adjusting our ways of working in different situations as well as recognizing and responding to government and community related expectations and concerns about our activities are crucial to companys business. Leading a structured stakeholder dialog and managing the stakeholder relationship is connected with all operations and starts from local communities, notables, political influential to district, division, provincial and federal authorities. In order to succeed and be sustainable over time, companies must keep the interests of customers, suppliers, employees, communities and shareholders aligned and going in the same direction. However, in some countries like Pakistan where industry faces difficult social and political environments where governments may lack the capacity, infrastructure or enforcement of legislation and regulatory frameworks, Stakeholder Management could be very challenging.
Through this paper a model shall be proposed based on best practices of leading Oil & Gas companies in Pakistan, as how different topics such as Sustainable Social development, Community Engagement, Managing Social Risks and their impacts, Human Rights, Local Content & Related Security could be aligned to create the possible much value for Stakeholders and ensuring social license to operate.
Alkali metal silicides have ability to enhance oil recovery in a variety of light, medium and heavy oil reservoirs. These chemicals, which include the silicides of sodium (Na), potassium (K) and lithium (Li), are free-flowing granules or very fine powders that are applied downhole in hydrocarbon dispersions. When introduced into a formation through an appropriate non-aqueous carrier fluid, these materials rapidly react with the water in the reservoir pore space, releasing hydrogen gas and heat, and converting into alkali silicates. The silicide-water reaction combined with the flooding process provides multiple mechanisms in the reservoir to enhance oil recovery. Enhanced oil recovery mechanisms include: energy addition through the generation of hydrogen; oil viscosity reductions due to hydrogen solubilization, temperature increase and solvent dilution from the carrier fluid; interfacial tension reduction due to in-situ surfactant generation from interaction of the crude oil organic acids in the reservoir oil with the alkalinity from the produced silicates; and potential improvement of water wettability in carbonate reservoirs. This one chemical combines the effects of thermal, drive energy and chemical mechanisms.
In this work, a field-scale numerical simulation study was conducted to investigate the feasibility of cyclically injecting an alkali metal silicide into the wormhole structures of a post CHOPS (cold heavy oil production with sand) reservoir. The Computer Modeling Group’s (CMG) STARS simulator was used to perform the simulations; the model consists of six vertical wells with wormhole structures developed using proprietary wormhole growth models that are based on actual field production histories from a representative CHOPS field in Canada (the Lloydminster, Alberta and Saskatchewan region). Multiple simulation cases were run to investigate the effects of injected cycle volume, cycle time, injection rate and silicide concentration. A sensitivity analysis was performed on parameters affecting the slurry model and dispersion rates of the silicide in the reservoir. The preliminary economics of the process were calculated and used to identify an optimized and cost-effective injection strategy, which can subsequently be used as a basis to design a field trial application.
The study results showed that the cyclic injection of sodium silicide in a post CHOPS reservoir can in fact improve the recovery of oil in place. The study shows that the predominant recovery mechanism is likely the pressure maintenance of the reservoir that provides energy for continued oil production. This, coupled with secondary oil viscosity reductions, enable the cyclic injection of silicide to increase production for an additional 5 to 10 years, thereby adding 25 to 50% to recoverable reserves under favorable economics. This paper discusses the impacts of the in situ generation of heat, hydrogen and alkali silicate for post CHOPS augmentation and summarizes the key findings of the simulation study and economic modeling.