When it comes to SAGD optimization, two of the biggest challenges are controlling subcool to achieve conformance (a uniform growth of the steam chamber along the complete length of the well pair), and maximizing an economic performance measure, such as net present value (NPV); both desirable outcomes are not necessarily associated with the same values of the operational parameters (e.g., injection rates). Overcoming these challenges is necessary for achieving optimum SAGD performance, but this may be difficult through common operating policies, e.g. injecting steam at a empirically specified constant rate, considering well-known features of SAGD processes, e.g., complex dynamics (nonlinear, slow, high order, time varying, potentially highly heterogeneous reservoirs), operational constraints, model uncertainty and measurement noise. In the context of this work, the aforementioned challenges are both formulated as optimization problems of adjusting injection rates in order to optimize a particular objective function (e.g. minimizing subcool error or maximizing NPV). To address these challenges, this paper presents a nonlinear model-based adaptive-predictive control approach, alternative to the classical Proportional-Integral-Derivative (PID), for subcool control and NPV optimization of SAGD processes under uncertainty. Using case studies with an idealized heterogeneity pattern (subcool control) and multiple geological realizations based on logs from the Orinoco Belt region (NPV optimization), the proposed approach was compared with a decentralized PID for subcool control, in terms of response speed (mean square error and reaching time), steady state behavior (settling time, measured subcool mean and standard deviation) and control energy spending. While the proposed approach offered a slower response (not a critical issue in terms of oil recovery), it significantly outperformed the PID control during steady state and in control energy spending. On the other hand, the effectiveness for NPV optimization under uncertainty was demonstrated against constant steam injection strategies considering mean NPV, steam injection, water produced, and SOR, and when modeling alternative risk aversion scenarios.
The design of wells into two sections (16? × 13 3/8? and 12 ¼? × 9 5/8?) in the Ecuadorian basin is a challenging effort of engineering. The success of the well depends on various techniques that will be analyzed in the following paper, which include precise casing seating depth, accurate fluid density for each section, appropriate formation bridging and sealing in the production zone (Napo), correct chemical selection as part of the fluid system to reduce formation damage on the producing reservoirs, plan a suitable directional trajectory if vertical section aloud (less than 2000') use "S" type design and appropriate BHAs for each section taking into account formation tendencies in terms to reduce slides in the case of PDM BHA is used. Other techniques applied that are going to be reviewed are include cementing production casing can be used slurries with higher densities to achieve better cement quality having less ECD during jobs; the two section design allows to run larger diameter guns and higher penetration bullets into productive sands, artificial lift systems can be set close to the producing reservoir. Using these techniques in the two sections design can provide several advantages compared with conventional three or four sections design in the Ecuadorian basin. This advantages are less cost for Drilling Event by time, by materials and equipment used, avoid adding risk when setting expandable 7? Liner Hangers, reduce risk of drilling tools and Wireline logs to get stuck related to higher clearance between them also Casings can run smoothly, improving production from reservoirs drilled through.
The result of first well drilled using these techniques will be presented in the following paper taking into account design facts, programs and procedures during the operation, and the results that will demonstrate the value of the design.
Ruiz, Y. Lopez (Schlumberger) | Betancourt, A. (Schlumberger) | Villanueva, G. (Schlumberger) | Vargas, A. (Schlumberger) | Tayo, M. (Schlumberger) | Burgos, J. (Schlumberger) | Vela, I. (Petroamazonas EP) | Egas, A. (Petroamazonas EP) | Loyola, R. (Petroamazonas EP)
Shushufindi field is the largest field in the Oriente Basin in Ecuador and is located 100 miles east of Quito. It contains 3.7 billion barrels original oil in place (OOIP) and represents 10% of country’s production. Determining reservoir properties using evaluation with hydraulic pumping for well testing has been a common practice in Shushufindi field since development in the early 1970s by Texaco Gulf Company and continuing in recent history with state company Petroamazonas.
Due to the high level of depletion and reservoir characteristics, obtaing good quality data from well testing is a challenge, and if a decision is made based on the wrong information, it could have a severe negative impact on the asset. Ambiguity in the results of well testing with a hydraulic pumping method can stem from failure on downhole shut-in that allows the development of wellbore storage, which in turn would lead to difficulties for well test interpretation, accurate flow capacity/ productivity evaluation, fluid sampling, etc.
To clarify all well testing concepts and results, a new procedure was developed for well testing in this field that uses a combination of drillstem testing tools, coiled tubing, and nitrogen lifting. With the developed method, the test is combined and continually conducted to test flow rate and drawdown buildups including downhole shut-in, providing reservoir and fluid parameters for a better evaluation and for artificial lifting design.
This paper will present a study of the implementation of this new method, covering the areas of well evaluation and the outstanding results in accelerating well response. The procedures are generally easy to follow and to understand and have an impact in reducing rig time and nonproductive time and result in a faster return of the well to production (workover). The pilot showed excellent results in obtaining reservoir property measurements that were validated by reservoir modeling and production history. The process is robust, repeatable, and applicable to other fields with similar characteristics.
Bourge, J. -P. (Schlumberger) | Bolaños, M. J. (Schlumberger) | Lafournère, J. -P. (Schlumberger) | Naranjo Leon, M. A. (Schlumberger) | Vega Torres, J. (Schlumberger) | Archard, G. (Schlumberger) | Suter, A. (Consorcio Shushufindi-Schlumberger) | Castillo, F. (Petroamazonas EP)
The main aim of geological modeling is to include all available data, such as seismic data, well logs, and core data, and to combine these data with more descriptive information, such as the geoscientist's understanding of the conceptual geological model and their experiences in similar environments, to predict the reservoir properties between the wells. However, in many cases, when the static model is passed to the reservoir engineer for history matching, the detailed geological knowledge and uncertainty is not fully utilized. This can lead to a model that may match the production data but actually has very little predictive power.
Depositional maps provide very useful constraints on model building. By giving a visual representation of the geological context, they can incorporate well and seismic information and the dynamic characteristics recognized from the production data, tracer information in cases of water injection, and pressure information. However, there always remains a degree of uncertainty with respect to the geometries and orientations of the geobodies, so the tuning of the maps is, by definition, an iterative process. This coupling between static and dynamic modeling is critical to achieve true discipline integration, aiming to retain the key information from each domain.
This paper presents an iterative technique to update these depositional maps in the areas of uncertainty between the wells. The required changes to honor production data and reservoir pressure trends during the history match are translated into facies modifications that are validated in terms of being consistent with both the control well data and with the conceptual depositional model.
This methodology was applied to the modeling of Shushufindi field, Ecuador. The long-term field development plan is being guided by a fine-scaled geocellular model that was designed to capture the geology at a high resolution. The workflow adopted required the collaborative efforts of the geology, geophysics, petrophysics, and reservoir engineering team members throughout the entire process.
Short-term optimization of an oil field has been used to increase economic value of oil recovery as compared to reactive control (shutting the well when water cut limit is reached, for instance), especially in the case of short-term production strategies. One way to improve the management of a field involves adjusting the production flow rates over a short time, maximizing the overall NPV during the life cycle of the field. Using intelligent wells (IW), the challenges include not only the optimization of well flow rates, but also the simultaneous adjustment of flow in each valve, controlling each aperture in a given production time. These optimal control strategies are often difficult to be realized in practice due to the large number of control variables involved in the optimization process, especially with larger number of wells and valves. To this end, this work proposes an efficient optimization framework employing a fast genetic algorithm (FGA) in order to adjust simultaneously the flow rates of wells and the valves aperture. We have used a commercial reservoir simulator whereby the flow rates of wells were optimized with an option available that calculates well rates when there is production constraint on the wells (platform capacity or other operational constraint) using production parameters in real time; and at the same time the flow in each valve was controlled through a keyword associated with the control of the aperture of valves by monitoring the pressure drop around of them. The FGA optimization algorithm employed is a global optimization method, which is robust and efficient for sweeping the solution space with many variables, and it is able to work with continuous and discrete variables simultaneously. We demonstrate the power of the FGA strategy by applying the methodology to a heterogeneous reservoir model based on Brazil's Namorado field, with four horizontal producers and four horizontal injector wells. Two producers were tested as intelligent, using two valves of continuous variation type. The rate of wells was determined using water cut values while there were constraints on the production of the platform. The valves were adjusted each 60 days, during the first four years of production, closing in the optimal time at the end of production. The results showed an improvement in reservoir management, increasing 3.7% of NPV, with additional gains around US$ 20 million (already discounted the costs of intelligent completion), increasing oil production and reducing water production. The combination of the tools available in a commercial simulator jointly with global optimization algorithm showed advantages of the operation of the wells and valves simultaneously.
As a result of the creation of a hydraulic fracture, transient geomechanics forces are exerted on the formation, which modify the stress landscape near the wellbore and the fracture plane. It has been observed that the potential exists for temporary reversal in the minimum stress direction, enabling a brief time interval in which a second hydraulic fracture can be created in a completely different direction. This provides hydraulic fracturing connectivity to previously unattainable locations in the formation, which can significantly improve initial hydrocarbon production and economic ultimate recovery from the formation.
This paper presents a computational validation of this multioriented hydraulic fracturing (MOHF) process. A unique transient 3D computational geomechanic fracture simulator was developed to perform this study, as traditional hydraulic fracture simulations are derived using static formation properties and steady-state assumptions. The new model incorporates cohesive zone elements to represent the fracture plane and friction elements to account for plastic energy storage of the multiple formation rock layers in the model. Time lapse stress fields show distinct windows of opportunity wherein new fractures can be influenced to extend in alternate directions.
This new stimulation method enhances the state-of-the-art in hydraulic fracturing. However, a deeper understanding of the transient geomechanic response in the treatment area is necessary to successfully design and perform the stimulation operation. Unfortunately, it also creates new complications with respect to industry standard hydraulic fracture models being incapable of modeling the transient response of the system. Furthermore, the availability of data related to the dynamic behavior of rocks is limited, and unique testing equipment and procedures must be developed to obtain such data.
Sanchez, Jose Luis (Schlumberger) | Carrizo, Hector (Schlumberger) | Salgado, Janine (Schlumberger) | Ordoñez, Mario (Schlumberger) | Rey, Fernando (Schlumberger) | Hazboun, Nidal (Schlumberger) | Laguna, Alfonso (Schlumberger) | Rodriguez, Rogers (Schlumberger) | Larez, Aquiles (Schlumberger) | Ramirez, Henry (Schlumberger) | Astudillo, Pedro (Schlumberger) | Sierra, Fabricio (Petroamazonas) | Teran, Nayda (Petroamazonas) | Bastidas, Marisol (Petroamazonas) | Camacho, Gustavo (Petroamazonas) | Bastidas, Alejandro (Petroamazonas) | Chancay, Armando (Petroamazonas) | Barona, David (Petroamazonas) | Carrion, Carlos (Petroamazonas)
Excellent results from a reentry campaign developed in 2014 in Ecuador have proven the benefits of implementing new drilling technologies for reentry drilling. In this campaign, rotary steerable systems (RSS) were drivers for directional control, and logging-while-drilling tools acquired critical information while drilling. Together these tools open up possibilities for giving new life to aging oil fields and to produce from unexploited drainage zones by enabling reentry drilling.
Drilling the reentry wells in Ecuador involve using the 9.625-in. casing to open an 8.5-in. window and drilling to the geological objectives in just one hole section. For this purpose, the combination of a point-the-bit RSS system, a multi depth laterolog resistivity tool with high-resolution images, and a sourceless tool that delivers density, porosity, spectroscopy, and sigma provided 100% of directional control while acquiring comprehensive formation evaluation information in real time.
Because of the casing configuration in most of the wells in Ecuador, the most commonly used reentry option is to make the window in the 9.625-in. casing and drill the 8.5-in. hole section from the Tena formation (claystone) and Napo formation (several intercalations of claystone, limestone, unstable shales, and pay zones of sandstone). This particular configuration of formation layers is a challenge for directional control and for running wireline logs.
The use of the bottomhole assembly (BHA) with the RSS and tools described above enables successfully drilling the reentries in just one 8.5-in. run, reaching the geological targets with 100% directional control, in spite of the complexity of the well trajectory, and avoiding risks such as packoff, geometrical sticking, and differential sticking. The smoother well profile obtained by use of the point-the-bit RSS and verified through the LWD measurements guaranteed the successful run of the 7-in. liner in all of the reentries drilled in the campaign.
Reentry wells provide operators with the opportunity to have new production at less than half the cost of a completely new well and in less than half of the total execution time.
Building on this reentry campaign, continued reentry drilling will be improved with implementation of the new generation of hybrid RSS (push - and point-the-bit RSS), which will enable drilling engineers to plan trajectories to deliver greater dogleg severities (DLS). This will, in turn, enable developing deeper reentries, further reducing cost and execution time.
An algorithm has been evaluated to offer a fast and simple design of a primary crude dehydration system consisting of a low capacity wash tank train, installed as Early Production Facilities (EPF) to achieve a crude oil specification not greater than 0.5% Basic Sediment and Water (BS&W) with average water cut at inlet of 30%.
The estimation method allows to perform routine calculations to determine the crude oil residence time available for water separation inside the equipment, water droplet diameter and water cut within the oil pad at different heights using a short-circuit factor (F) always greater than 1. As a result, short-circuit factor of 1.4 is verified to be a good value to ensure separation of phases in low-capacity tanks. In addition, tank dimensions are given based on API-12F specification for a nominal capacity of 500 bbl. for the 12 ft diameter and 25 ft height. Moreover, the designer must take into account different tank internal configurations to improve its efficiency.
Different dehydration configuration can be arranged using 500 bbl. low-capacity wash tanks installed in series. One (01) train consists of two (02) wash tanks, and as the required processing fluid capacity is higher, similar trains in parallel must be added to increase the dehydration system throughput.
Retention time and settling theory were used and applied to the system described above and determining that the oil quality is related to the maximum size of water drops carried-out over O/W interface and being smaller as the oil reaches the outlet connection which is close to the top of the tank. These sizing techniques allowed the BS&W and water droplet diameter being estimated as a function of the oil-column height, residence time and temperature.
Different effective heights through the wash tank oil pad are checked at various operational temperatures which allow the dispersed water droplets to settle out from the oil with different velocities and, hence, being able to evaluate several water cuts (%BS&W). EPF conformed by two trains of 4 low-capacity tanks each; working in parallel, provided a processing capacity of 12000 BFPD to meet a desired 0.5 %BS&W specification for given oil and water physical properties. Initial investment, operational costs and implementation time were favourably reduced during the early production stage until the permanent facilities were installed, thereby avoiding sophisticated technologies that could result in expensive and late industrial project deployments.
There are several techniques to optimize production and avoid reservoir damage caused in the different phases of the development of oil wells (perforation, completion, production and workover), ranging from the control of water, chemical stimulation, mechanical stimulation, fracture, re-perforation of producing areas, etc.
In the case of phase completion, holes are perforated through canyons to connect the reservoir with the wellbore and get well production, however this technique, often not doing its job, because it does not exceed the damaged area, produced in the drilling phase, when applying sludge systems or the primary cementing is performed, brings further cause damage to the compacted in the vicinity of each hole area.
Abrasive perforation technique was used in 1958 approximately and thanks technological advances in the field of materials and chemistry, has had substantial improvements, has created new expectations for avoid formation damage and hence an improvement in the production of oil producing wells.
In order to analyze and predict the well Productivity, it is necessary to perform an appropriate perforating analysis; this can be achieved integrating Petrophysics, Geomechanics, Reservoir and Production Domains. For an advanced Perforating design a clear understanding of rock characteristic, depth of damaged zone and reservoir behavior is used in the Perforating simulation. This enhances the right selection of charges and ensures they will overpass the altered zone.
Abrasive perforation technique has been used to optimize production from oil wells and avoid the reservoir damage to the drilling and completion phase, replacing conventional techniques shooting. This methodology was implemented in Coca Field. This helped to optimize and predict the productivity of the wells.
Asphaltene precipitation is a challenging and complex problem in all sections of the oil industry including oil production, transportation and processing. Asphaltenes can plug pumps, valves, tubing and flow lines, cause fouling in surface handling facilities and even act as coke precursors and catalyst poisons. For these reasons, the occurrence of asphaltene deposits may result in productivity losses and sometimes even production shutdowns. For many years, much effort has been done on modelling asphaltene precipitation because experimental investigation is a hard task. Thermodynamic models based on Flory-Huggins theory have been used by several oil companies to predict the asphaltene onset conditions due to the depletion or gas injection. However, the main requirement to accomplish a successful calculation of asphaltene precipitation is an accurate solubility parameter. A variety of models to calculate asphaltene precipitation based on the solubility parameter is available in literature but most of them are complex due to inherent assumptions that are built-in. In this work, a new simple and accurate method to calculate the asphaltene solubility parameter is proposed, which requires only SARA (saturate, aromatic, resin, and asphaltene) analysis, the oil composition and the reservoir temperature. Once it is sufficient to know up to C7+ fraction, a much detailed analysis of the oil composition is unnecessary. Soave-Redlich-Kwong (SRK) (