In the Mexico marine region, gas breakthrough is common in naturally fractured carbonate oil reservoirs. Increasing the gas production reduces crude oil production, and eventually the wells become uneconomic and are shut-in in spite of the remaining recoverable reserves. A typical example is the Akal field, a large fractured 300-to 1000-m thick carbonate reservoir whose permeability varies between 0.3 and 5 darcy. The gas-oil contact zone moves by as much as 8 m/month as the natural gas and nitrogen gas from gas injection moves through the natural fractures and invades the oil zone. This condition results in production decline, reservoir pressure decrease, and oil remaining in the matrix.Efforts to selectively shutoff the gas have been unsuccessful due to the low-reservoir pressure and high-permeability contrast. When pumping water-based fluids, the increased hydrostatic pressure causes the treating fluid to travel down the natural fractures and away from the gas cap. This condition led to abandoning the gas-invaded intervals and recompleting lower in the reservoir, leaving some recoverable reserves.To selectively shutoff gas entry in fractured reservoirs, a stable foam-delayed crosslinked fluid was proposed for use by service company. The fluid with a high-foam quality (FQ) and low density rides over the crude and into the natural fractures/fissures, communicating with the gas cap. Once set, the fluid creates an impermeable seal with high-extrusion resistance.The stable foamed fluid has been successfully used to selectively shutoff unwanted gas production in wells that have been, in some cases, shut-in for several years due to excessively high gas/oil ratios (GOR). Following the treatment, the oil production was restored to the same level as prior to the gas breakthrough.The success of the initial campaign demonstrated that it is possible to restore the production levels of shut-in wells and recover otherwise lost reserves. This result has a very significant positive impact on the economics of operating the field. The current plan is to extend the use of the technique to other fields.

Linear and nonlinear stability analysis of flow instabilities gas-lift wells with water coning was performed in this paper. A new gas-lift stability criterion, which takes into account water coning, was developed. The criterion was used to analyze flow instability in an offshore gas-lift well. The effect of the water-coning performance on the conditions of the onset of instabilities was investigated. The nonlinear analysis showed that one of the most important instability modes in gas-lift wells is associated with two types of density waves: liquid and water holdup waves. Flow instability in gas-lift wells may result in that the maximum instantaneous liquid flow rate may be several times larger the average liquid flow rate for long periods of time (tens of minutes) in one cycle of oscillation. It was shown that water coning has a strong destabilizing effect on the flow in gas lift wells with a large vertical distance between the injection point and perforations. In some cases heading in such wells cannot be eliminated by increasing the wellhead pressure. One of the most important instability modes in gas-lift wells is associated with two types of density waves: liquid and water holdup waves.

This paper explores the results of one operator's successful implementation of a workflow-based solution to real-time production surveillance and optimization of a large offshore field. In particular, we will provide an overview of one of the more complex workflows addressed, real-time model-based gas lift optimization for the asset. Details of the workflow and total value proposition are examined, demonstrating the possibilities and ROI potential of new data integration and workflow technologies. With a system characterized by large pressure fluctuations in the surface network, previous attempts to achieve model-based optimization using manual processes had struggled with the high frequency of updates needed to maintain the models in an "evergreen" state. Utilizing a combination of techniques such as surveillance-by-exception, automated model validation, and assisted model updates, the new approach allows the operator to re-optimize gas allocations to the field's more than 200 producing wells and 70 platforms, at a 12 hour frequency. This frequency of re-optimization is sufficient to maintain the system at a maximum stabilized production rate. The solution is currently in operation, and has provided a sustained production improvement to the field. Operational data is made readily available to users to support decisions, while workflows derived from operator best practices guide users to ensure that analysis is structured, streamlined, and repeatable. The work is significant as a successful implementation of a large-scale production optimization solution configured to established operator best practices. In an age when operators are faced with declining production rates, smaller discoveries, and a "graying" workforce, such solutions allow operators to do more with less and deliver maximum asset value. A History It is widely accepted that there is much inherent, but as-yet untapped value to the data and systems installed as part of recent initiatives to upgrade to what we term OilField 2.0. Previous work1 has already served to highlight the value proposition of introducing modern Engineering Workflow Platforms to the oilfield. It is our belief that such platforms will serve as the long-awaited capstone to this initiative, finally bridging the gap between the present and promise of the Digital Oilfield. To briefly summarize our position, it is our opinion that the modern Engineering Workflow Plat from must provide 3 distinct capabilities:Data Integration (Pre-configured and/or 'Ad hoc')Workflows supporting 3rd Party Application Integration (Pre-configured and/or 'Ad hoc')Visualization (Pre-configured and/or 'Ad hoc') While at first glance these capabilities may seem commonplace, it is the inclusion of the term 'Ad hoc' to each which we feel serves as the key differentiator to our requirements. Without belaboring the issue, it is our experience that it is absolutely critical to recognize not only the unique nature of each asset's, but also each operator's own individual and more importantly, ever-evolving challenges to maximizing the value of their producing assets. Our fundamental premise is simple: In the oilfield, 'one size fits all' IT solutions to engineering problems are rarely, if ever, enough. Our premise should not be interpreted as an effort to detract from corporate-level efforts at standardization of IT systems. Rather, we agree wholeheartedly that standardization is the only means for an operator to capture associated economies of scale across its IT infrastructure2. Instead, what we are advocating for is merely the recognition that best-in-class software solutions must be capable of supporting a happy medium between the two extremes of complete absence of corporate controls and total standardization. And while it is the sole prerogative of the operator as to where they choose to position themselves on the continuum of IT governance, the astute vendor must be prepared to support them all.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractAn integrated analysis of technical information from 459 wells that were shut in or having production problems within five Integrated Business Units in the Southern Region of PEMEX E&P, identified production increase opportunities of more than 145,000 STB/D of oil and 323 MMscf/D of gas. This paper presents the applied methodology and the results obtained from a project based on well management to optimize the recovery of hydrocarbons of the identified opportunities within these business units with minimum investments. The successful implementation of this project was based on the careful selection of highly qualified technical personnel that formed the nucleus of the working multidisciplinary teams that contributed to the increase of well productivity from the selected fields. The implementation of the concept of team work coupled with the application of selected technologies to identify and exploit potential opportunities made it possible for these business units to increase the production of crude oil over 67,635 STB/D and gas to over 111 MMscf/D from workover of 179 wells within 9 months thus achieving a production increase of 7.95 MMSTB of oil and 12.8 Bscf of gas. This increase in production made possible for this region to maintain a production plateu of 500,000 STB/D and 450 MMSCFD, offsetting natural production decline and loss of production due to a strong water invasion of wells. A profit/cost ratio of 15.1 has been obtained. In addition to the value added of production increase through this visionary management approach, the following benefits were obtained: learning and applying the team work approach of well productivity, adaptation to a new cultural change of working as teams to solve difficult problems, training and transfer in diverse methodologies, and software technologies from the interdisciplinary teams to the technical personnel of PEMEX E&P, and specific well data information certified that can be used to evaluate diverse reservoirs studies.

This paper aims a solution to improve dynamic connectivity between regions in compartmentalized reservoirs. The proposal is to drill horizontal wells whose main objective is to communicate the zones where compartmentalization has been detected. The fluid flow between compartments will occur due to the potential difference existing between them. The flowrate will depend on the petrophysical properties of reservoir, physicochemical properties of fluids and the design of horizontal well. The work develops a mathematical model that represents the potential behavior of each compartment over time when they are communicated through a horizontal well. It considers the special application for gas cap systems and it presents an example, which demonstrates the impact and benefits of this solution. The implementation of this proposal will help exploiting the hydrocarbons reservoir through the existing infrastructure in adjacent regions, thus, reducing or eliminating the requirement of new infrastructure and extending the lifespan of existing infrastructure, thereby maximizing the value and recovery of the fields, which can represent great economic benefits for many oil companies.