Abbaszadeh, Maghsood (Innovative Petrotech Solutions) | Varavei, Abdoljalil (Innovative Petrotech Solutions) | Rodriguez-de la Garza, Fernando (Pemex E&P) | Villavicencio, Antonio Enrique (Pemex E&P) | Lopez Salinas, Jose (Rice University) | Puerto, Maura C. (Rice University) | Hirasaki, George (Rice University) | Miller, Clarence A. (Rice University)
An integrated methodology is presented for the development of a comprehensive empirical foam model based on tailored laboratory tests and representative numerical simulations that encompass processes of foam generation, coalescence, and shear thinning along with rheological characteristics and associated flow regimes. Steady-state and unsteady-state laboratory experiments of foam floods in a vertical column of sandpack with and without oil at different surfactant concentrations and at varied gas/surfactant-solution injection rates are designed, conducted, and analyzed. The logic and basis of these experiments are provided. Test results from experiments in the presence of oil provide information on the oil-induced foam/lamella coalescence functions. Unsteady-state experiments capture foam-generation and foam-dry-out phenomena, whereas steady-state experiments capture the effects of foam quality, foam velocity, and surfactant concentration. Process-based numerical simulations of these experiments are combined with basic governing analytical relationships of foam flow to provide a methodology for a comprehensive empirical foam model and to uniquely define the model parameters to preserve consistency with simulations of foam-flow processes. A procedure is presented to fully model the effect of surfactant concentration on foam strength and to quantify all concentration-function parameters, and, in particular, epsurf.
There are different methods to estimate the current water-oil contact (WOC) or gas-oil (GOC) contact depth in a reservoir. Reservoir engineers has commonly use PLT, RST logs, material balance and simulation models with this purposed but they implied cost, man-hours and to have a great understating of the reservoir. Previous published work
In this paper, a conceptual simulation model was built to prove the effect of the produced °API of the presence of a compositional gradient in the reservoir. Results will show that distribution of °API value in the reservoir will cause change, at surface level, in the measurement of this property during the exploitation cycle, decreasing or increasing depending on weather the reservoir is undergoing a WOC or GOC displacement. The results obtained with the conceptual simulation models present the same behavior describe by other authors and could be translated to real models, and more important prove that changes in the °APi values at surface level are a direct consequence of fluid displacement when the reservoir have a compositional gradient.
Finally the methodology used in the conceptual simulation model for °API monitoring was applied to two reservoirs, one with known aquifer influence and other with a secondary gas cap. Both reservoir had enough historical °API measurement to establish a comparison between simulated and real data. The results show that the numerical models are able to reproduce the historical °API behavior and reinforcing the practicality of predict the breakthrough of fluids using only °API measurements on surface.
Fluid allocation is a common challenge in the stimulation of naturally fractured reservoirs in offshore Mexico. Multiple or large pay zones with thief intervals can cause preferable fluid admission to such zones. Using distributed temperature sensing (DTS), fluid-treatment distribution can be monitored in real time for this type of reservoir, and modifications can be made on the fly to improve fluid coverage. Monitoring with DTS can help optimize treatment economics and improve productivity.
A reintervention to increase production in naturally fractured reservoirs involves improved stimulation schedules and the use of diverters to achieve fluid distribution across perforated intervals. Variable permeability and a potential for heterogeneous zones in the reservoir are a challenge for these types of wells. This document discusses a treatment performed to successfully stimulate a four-interval well using DTS measurements to monitor placement in real time. A gas-lift test was also performed during the monitoring operation to help identify the producing zone before the main stimulation began. The information gathered during the treatment helped the operator understand the production behavior of the well and acquire additional information for upcoming treatments.
During the well intervention, the following information was obtained to help determine the success of the treatment: Fluid allocation was verified during and after injectivity testing (including differential temperature gradient) to help determine initial admission zones. This information enabled an appropriate schedule to be designed for the acid treatment. A gas-lift mandrel was used, and the zone contribution was qualitatively evaluated during this test. The stimulation treatment and the diverter stages were monitored in real time. The percentage of admission was calculated for each open interval, and a correlation using previous production-logging-tool data was performed. Early flowback of the well was observed.
Fluid allocation was verified during and after injectivity testing (including differential temperature gradient) to help determine initial admission zones. This information enabled an appropriate schedule to be designed for the acid treatment.
A gas-lift mandrel was used, and the zone contribution was qualitatively evaluated during this test.
The stimulation treatment and the diverter stages were monitored in real time. The percentage of admission was calculated for each open interval, and a correlation using previous production-logging-tool data was performed.
Early flowback of the well was observed.
The production expected from the treatment was 800 BOPD. The stimulation treatment was considered successful, with an initial production of 1,050 BOPD (a 31% increase from the target). The information gathered during this treatment can also help modify upcoming treatments in the wells of this field with similar characteristics. Combined pre-treatment production monitoring and monitoring stimulation treatments in naturally fractured reservoirs using DTS helps identify the main producing zones and improves stimulation fluid distribution into lower-permeability intervals. This technique allows for performing treatment changes on the fly to attempt to achieve better zonal distribution and increase the productivity index in the wells.
There are many methods and tools for estimating the current water/oil (WOC) or gas/oil contact (GOC) in the reservoir. PLT and RST logs can timely monitor the production of each phase in the well and estimate fluid contacts. Material balance or numerical simulation models allow to estimate or predict the depth fluids contacts. In all cases, these tools involve a large amount of human and financial resources and in most cases their accuracy depends on the time expend to calibrate them. This work proposes a methodology to determine the current depth of the fluid contacts, using surface measurements of the specific gravity of oil ( API) in wells. The proposed methodology is based on the principle of the compositional variation of the fluid in the reservoir and its effect of the properties of the produced fluids. Two diagnostic plots are proposed: (1) for estimating the current depth of the fluids contact at well level and (2) for predicting water breakthrough time. Some real examples of wells showing the behavior outlined in this paper will be presented to support all presented theories. Finally the proposed methodology and diagnostic plots were applied to a reservoir with proven compositional gradient to validate the proposed work.
Commonly when a conventional gas reservoir is produced always the recovery factor expected is between 80-90%, but when the water appears always the plans are subjected to changes, different considerations and several questions raises regarding how the reservoir will be affected. The most common questions are if the recovery factor will be affected, if the current production strategy will change, if we need to consider critical rates per well, if the plateau will change, reserves, production facilities, etc. The presence of water influx can alter the way the gas is produced by the reservoir as the water invades the gas reservoir, the displacement is not 100% efficient (
The methodology presented on this paper appraises the evaluation of four different exploitation scheme, trying to understand and determine the best exploitation strategy using a reservoir simulation model applied to two different reservoirs of the Veracruz Basin with different static and dynamic properties, and quantify the benefits to use the proper one to maximize the recovery factor. A detailed description of each reservoir will be review and results will be compared to emphasis that there is no rules to create exploitation plans for gas reservoirs it will depend on several factors.
One of the main difficulties that arise when analyzing mature fields is high volume wells presenting. Analyze the information of hundreds or thousands of wells to identify opportunities to optimize the production of wells operating or reactivate closed wells can become virtually impossible for man hours that they would require. This paper presents a new methodology for identifying, selecting and ranking short term production opportunities, to optimize operating wells and reactivate closed wells through a practical analysis of different diagnostics plots. The main objective to develop this methodology was to stabilize oil production decline of a mature NFR by incorporating profitable activities that can be implemented in a short term (less than 6 months). The methodology can focus on two analyses: y Operating wells: Identify opportunities for optimization y Closed wells: Identify opportunities to reactivate wells This methodology (MIPO) is the first step before any multidisciplinary analysis is implemented. This methodology is a kind of screening criteria with available well data and its application is very practical and simple. MIPO application is recommended when there is a considerable number of wells (20) and has the flexibility to meet the needs of the field under study.
The process of incorporating and reclassifying new oil reserves in the Gulf of Mexico area is part of a strong strategy of the operating companies that apply to compete and achieve good results. Allowing them to conduct business and enhance their prospects for a long-term success. That's why the wells drilled must comply with economic potential oil committed to expanding area of opportunity and continue with successful business processes. Drilling of exploratory wells represents a challenge for the present and future development of the technical and operational capabilities. Due to the complexity, high technical and professional level required to execute and monitor it in real time.
There are many mature fields in Latin America. Beyond the definition of maturity applied, the common factor to all of them is that surface facilities and field operation have been running for many years. This is one advantage to generate profits.
However, operations are governed by old practices for defining profitability of wells and in some cases do are not specifically developed or evaluated for these wells, therefore, underestimate the economic return generated.
Another characteristic of these fields is the dispersion of production per well. Production may vary from very low to moderate on a mature field. It is also known that in order to optimize equipment some resources such as surface artificial lift equipment is moved from low production wells to higher production wells.
The big losers of these practices are wells that have low but stable production. Those big losers should be a marginal benefit to the ongoing production system.
This paper presents the benefits of applying alternative technologies to return to production low production wells in fields with available gathering system. This work also makes a significant contribution to identify profitability potential in low production wells and recommends management models for implementing, surveillance and maintaining low rate active wells.
It is also necessary to define the optimization processes for these wells because most companies do not have staff available to address these designs of low productivity. This profitability approach allows to redirect resources, including human resources to increase benefit.
Villasenor, R. Ostos (Pemex E&P) | Paz, P.L. Velasco (Pemex E&P) | Trujillo, E. Sampayo (Pemex E&P) | Garcia, L. Lombardo (Schlumberger) | Franco, F.M. (Schlumberger) | Useche, M.A. (Schlumberger) | Narvaez, S. (Schlumberger) | Karimi, H. (Schlumberger) | Rossi, D.J. (Schlumberger) | Pitts, K. (Schlumberger)
The midstream business group in Pemex has invested in the development of Digital Oilfield and Asset Optimization technology and processes through two projects. The objective is to improve the use of online data for analysis and decision-making related to the key midstream business of hydrocarbon transport, export and delivery. The two projects have implemented a nationwide data foundation (SIAPPEP) along with an Online Monitoring and Optimization (MOL) system to recognize and manage anomalous conditions in the hydrocarbon transport system. This paper focuses on the MOL project, which was initiated in 2012 and builds on an underlying SIAPPEP data foundation that was developed earlier. The MOL project covers 7,000 kilometers of hydrocarbon pipelines in Mexico, and comprises five subprojects that with SIAPPEP collectively make up the Pemex midstream Digital Oilfield (DOF) system: (1) MOL Monitoring to consolidate information from a large number of "islands of SCADA" distributed throughout Mexico to form a comprehensive view of midstream activity; (2) Collaboration Environments to create communication, visualization and collaboration infrastructure that links centralized operational teams in each region to remote operational groups; (3) MOL Optimization to assess the best monitoring and modeling technology investments with high potential to improve business workflows and operational performance; (4) MOL Modeling to create and calibrate simulation models for the main oil and gas trunk lines and pipelines; (5) Online Transient Modeling Assessment to evaluate the informational readiness to implement online transient simulation along key strategic pipelines in the country, to assure safe midstream operations and to meet hydrocarbon quality specifications.
Maximizing the return on investment (ROI) of drilling and operating wells is one of the primary objectives of the extra-heavy oil exploitation project in the Neogeno Samaria field. This project pioneers the application of cyclic steam injection as an enhanced oil recovery method in Mexico. One of the keys to achieving this goal has been the acquisition of injection and pressure-temperature profiles logged during phases of the well’s operating cycle (initial, injection, soak, production). This data has provided a better understanding (and thus, a more accurate assessment) of the effective distribution of the injected steam in the different sand bodies that make up this fluvio-deltaic depositional environment. In this area, each drilled well might cross several zones with different potential and characteristics, which affect the well’s capacity for injected steam admission when the zones are simultaneously stimulated.
Although there are precedents for such operations performed in other countries, the operating conditions of the Samaria project present new technological challenges. Not only does the area have higher temperatures (reaching up to 315°C [600°F]) than other areas where similar projects are run, during this project, steam is injected through the tubing where the tool is run in hole, which affects the performance of the surface pressure control equipment. These problems were addressed with the development of new devices. The logs allowed adjustments to the well completion designs to achieve better distribution of the injected steam and extend the duration of the producing stage. The logs also aided selection of the optimal number of sands to be produced in each well, evaluation of well performance through several cycles of injection, identification of some effects of interference between wells and water/steam channelings, and more applications. This paper reviews some of these applications.
Increased global oil demand and the reduction of conventional oil resources have encouraged the search of deeper reserves both offshore or in deep water. Although this increases operating costs, the initiative is still supported by strong oil prices. The development of heavy and extra-heavy oil resources is becoming more important and profitable as a key to helping reduce the gap between demand and production.
However, unlike the conventional oil that represents lesser reserves volumes that are easier to characterize and develop, the heavy oil reserves are larger, but they are more difficult to develop, even for appraisal. The current worldwide heavy oil reserve is estimated at approximately 1.1 trillion barrels, 67% of the total oil reserves. In Mexico, the situation is almost the same; heavy and extra-heavy oil comprises 61% of the proved reserves, which is approximately 6.151 MMBLS (PEMEX, 2013).