The Zuata Field, located on the southern flank of the Eastern Venezuela Basin, produces heavy oil from porous unconsolidated sandstones of the Lower Miocene Oficina Formation. The Oficina Formation is composed of multiple depositional sequences which display complex erosional geometries. This creates an intricate reservoir architecture as younger fluvial systems down-cut, erode and re-distribute the sediments of earlier-deposited systems within each depositional sequence. Superimposed on this intra-sequence complexity is the downcutting and interconnection of sands of different depositional sequences. The Oficina Formation within the study area can be subdivided into eleven depositional sequences. Each depositional sequence has been characterized in terms of environments of deposition and mapped, which has allowed visualization through time of the facies and reservoir geometries. Within sequences, environments of deposition include a mix of fluvial, distributary channel, estuarine, tidal channel, delta plain and coastal plain, resulting in variable net to gross ratios and variable kv/kh. Productive sands are located within incised valleys, usually within the basal part of each depositional sequence, while sediments in the inter-valley areas comprise a combination of older (pre-incision) deposits and thin delta plain / coastal plain deposits. These are variously intercalated siltstones, fine-grained sandstones and coals, and are generally non-productive. Introduction Petrozuata Petrozuata, S.A. is a joint venture company with Conoco (50.1%) and Petróleos de Venezuela, S.A. (49.9%). Built from the ground-up in less than three years, Petrozuata has drilled 306 horizontal laterals and 145 vertical wells and is currently producing approximately 120,000 bbls oil per day. Each of the horizontal wells is custom designed and then "geo-steered" during drilling to access the reservoir in the most efficient manner. Petrozuata produces extra-heavy crude oil (9 to 10 API) from the Zuata Region of the Faja Petrol fera del Orinoco (the Orinoco Oil Belt). The heavy oil is diluted with naphtha to yield a 15–17 API blend, which is transported via a 200 km pipeline to the north coast of Venezuela. There, a delayed coking-based upgrader facility converts the diluted crude to synthetic crude oil, along with associated by products of LPG, sulfur, petroleum coke and heavy gas oil. With over 20 billion bbls of oil in place, the Petrozuata joint venture has a 35-year operating life. This will require the drilling of up to 750 horizontal wells to ultimately recover 2 billion barrels of extra-heavy crude. Location and Geological Setting The Faja (Orinoco Oil Belt) is located on the southern flank of the Eastern Venezuela Basin (Fig. 1), and contains about 1.2 trillion bbls of in-place oil, stratigraphically trapped in Miocene-age fluvial- and marginal-marine reservoirs. PDVSA has subdivided the Orinoco Oil Belt into four areas (Machete, Zuata, Hamaca and Cerro Negro). Petrozuata is currently developing part of the Zuata area.
This study investigated the feasibility of coupling a subsurface numerical reservoir simulator (POWERS) with a surface network modeling simulator, to assist in making better field management decisions according to business need. Coupled simulation models have two advantages over uncoupled models. First, interdependence of the reservoir and surface facilities are properly modeled in coupled simulation models to accommodate rapid variations in production strategies. Coupled simulation models are likely to give more accurate production forecasts compared with modeling the reservoir or the surface separately. Second, given that most surface network modeling tools have a built-in optimizer, it is possible to allocate rates among wells based on a user's objective optimizing function, -e.g., reducing or maintaining a watercut level for a given production target -taking into consideration any system production constraints applied on a well, a group of wells or trunkline levels. To improve the quality of simulation results, a new algorithm is implemented in POWERS to calculate the inflow performance relationship (IPR), based on drainage pressure, i.e., a reservoir pressure calculated as the average of several neighboring cells in the simulation model as opposed to the single cell pressure. The current study shows that it is feasible to run coupled POWERS-surface network models and gain the benefit from the optimization algorithm of the surface network modeling tool.
This paper was prepared for presentation at the 1998 SPE International Conference on Horizontal Well Technology held in Calgary, Alberta, Canada, 1-4 November 1998.
TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractWe will discuss issues in developing a production-injection surface facility model to optimize both oil production and water injection strategy in a mature giant oil field. Surface facility modeling was done using commercially available software, which was coupled to Saudi Aramco's in-house reservoir simulator POWERS 1 . Multiple integrated strategies for analyzing production can be considered with such models. In this paper, we evaluate a facility optimization perspective where many wells are rerouted between multiple gas-oil separation plants (GOSPs) to maintain adequate reservoir pressure to deliver required oil production volumes at the lowest operating cost. We also consider cases where the objective is to evaluate injection allocation strategies, which honors surface constraints, especially surface flow lines' maximum operating pressure restrictions. Results presented in this paper include a subsurface reservoir coupled surface facility model where proposed strategies are designed to reroute wells from five existing GOSPs producing at high water cuts to two remaining GOSPs for production consolidation. Such strategy allows for an immediate cost savings, since it reduces the number of plants while at the same time producing the required volumes of oil, at reduced water cut, while at the same time maintaining reservoir sweep and recovery since wells which otherwise might have been shut-in are kept on active production. Simultaneously with the option of optimizing oil production, rerouting offers the opportunity to examine water disposal strategies since water can be injected near locations where there might be either a need for additional sweep or simply for reservoir pressure control and redistribution without compromising overall oil production.We built a surface facility model consisting of five active GOSPs with a few hundred producers and injector (disposal) wells. The surface model is coupled to an over a million-cell reservoir model, containing a sub-set of all the wells available in the POWERS simulation model. Previous work had relied on describing exclusively the production system, leaving the injection system to be handled by POWERS' well management rules and not subject to optimization or reconfiguration based on reservoir strategies. In this study, both the production and injection model have been constructed and calibrated using the latest available field data and history matched to field performance current at the time of calibration. Model calibration has been assisted by using automated scripts that transfer the relevant production and technical data from a corporate database to the individual model well files and which provide initial estimates for appropriate calibration parameter, such as productivity index, gradient curve matching or reservoir pressure at the time of a rate test, to current or historical field data. Those initial matches are later reviewed and validated on a well by well basis prior to use for prediction runs.
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