The Bakken formation ranks as one of the largest oil developments in North America in the past 40 years. Various estimates place the total resources (recoverable and non-recoverable) with today's technology, from 2 to up to 24 billion barrels of oil (BBO). According to the North Dakota Industrial Commission (NDIC) there were 6,884 horizontal wells by end of 2012 in North Dakota with majority of these wells completed in the Bakken formation. The main target for exploitation has been the middle Bakken siltstone member which is sandwiched between Upper Bakken Shale and Lower Bakken Shale. However, targets below Lower Bakken Shale have shown commercial production notably from the Three Forks benches and sporadically occurring Pronghorn member. The close proximity of these targets coupled with the need for hydraulic fracturing, introduces uncertainty in the "source" of oil production in wells and hence in technically recoverable resource forecasts. In this paper, we discuss models built to replicate well performance under various completion configuration and depletion pattern to demonstrate the challenges in estimating technically recoverable resource early in to the life of a well or group of wells. These challenges may arise from the stimulated reservoir volume (SRV) not contained within a single reservoir but straddling more than one reservoir at a time. Connectivity between multiple reservoirs and the wellbore may vary with time due to change in stress contrast related to fluid production or by hydraulic fracture conductivity degradation; such varying connectivity can further complicate production allocation from multiple reservoirs. A lack of understanding of SRV distribution and subsequent drainage from multiple reservoirs may lead to significant uncertainty in technically recoverable resource estimation - especially when using short-term production data. This paper also highlights the effects of completion interference between a well and its infill offsets on uncertainty in estimating technically recoverable resource. We intend to emphasize the issues previously mentioned to the broader audience with the intention to promote further technical discussion on the role that well completion plays in resource evaluation of unconventional plays such as the Bakken Shale.
This paper was selected for presentation by an SPE Pmgmm Committee following review C4 information contained in an abstract submitted by the author(s). contents of the Pawr, as presented, have not been reviewed by the S&ety of Petroleum Engineers and are subject to comdim bythea!dhor(s), The material, 'as presented, does not necessarily reflect any p&tion of the Scciety of Petroleum Engineers, its offisers, or members Papers presented at SPE nwetings are subject to publication rw'ew by Editorial Committees of the Society of Petroleum Engineers, Electronic reproduction, distribution, or storage of any part of this paper for commercial pups without the written consent of the Sociely of Petroleum Engineers is prohibited. Permission to mprcduce in print is mstristed to an abstract of not more than 300 W1-dq WrsMhs may d be copied. The abstract must sontain mnspicuous acknc?.viedgnwrt of where and by whom the paper was presented. Write Librarian, SPE, PO, Box 333833, Richardson, TX 75083-38S6, U.S. A,, fax 01-972-952-9435, AbstractA Ml fieldreservoir simulation model was constructed for the31 S StructureStevens reservoirs, The size of the model is 29,070 grid cells with 26,889 active cells. Results from history matching the medel show that all the Stevensreservoirs on the 3 I S Structure are in communication. This paper illustrates the use of reservoir simulation technology as a tool to diagnose the performance of a systemof comple~multiple and conjugate reservoirs and quantt he extent of fluid migration that may have occurred among them.
The results of a reservoir performance evaluation of a giant mature heavy oil field are presented here. This field began production in 1927. By 2002, cumulative production had surpassed half a billion barrels of low-gravity oil from Miocene sandstone formations produced under natural depletion, water and gas injection, and cyclic steam injection from more than 400 wells. As a result, several interdependent flow models including black-oil full-field, thermal single-well, and thermal large-sector models were built for field analysis and optimization. The long and complex production history, as well as the various recovery mechanisms, presented a number of challenges in constructing and calibrating the models to past historical performance. The optimization work was done in the following three stages. First, a coarse-grid black-oil model was constructed to study the field performance prior to steam injection, following the successful geological modeling phase of this project (presented in Márquez et al., 2001 1). The second stage involved single-well and sector-model thermal simulation analysis. The thermal models were used to match the field historical pressure and production data over the natural depletion, water injection and cyclic steam injection periods.T hird, we investigated the field performance under different development scenarios. Optimization results with the single-well thermal models were incorporated into the sector models, which were used for processing runs to examine infill drilling; recompletion of active wells; waterflooding; huff ‘n’puff steam injection; steam drive; and horizontal well drilling. The project resulted in the identification of more than 100 infill or recompletion candidates, and an estimated three million barrels of oil (MMBO)of additional recovery during the first 2 years of this project. As a result there were significant performance improvements and more are anticipated through the implementation of the field development strategies recommendedhere. The modeling approach led to significant time savings and provided an effective reservoir management tool for future field development. Introduction Schlumberger Data and Consulting Services (DCS), in Denver, Colorado, initiated a project for preparing the numerical 3D predictive model of theLL-04 Miocene reservoirs in Lake Maracaibo. The objectives of the reservoir performance evaluation were toprovide Petróleos de Venezuela, S.A. (PDVSA), the Venezuelan state-owned national oil company, with an updated geologic model that could be used to select new drilling and workover candidatesprovide PDVSA with a dynamic flow model that could be used as a tool to improve ultimate recovery from a number of operating strategies, and to monitor the field performancemake recommendations that would help PDVSA maximize production, maximize oil recovery, and to determine the best operating strategy for the field. This paper describes the reservoir simulation part of the reservoir characterization and simulation project. The Reservoir The LL-04 field is located on the northeast side of Lake Maracaibo along the Bolivar Coast of Venezuela (Fig. 1). This was one of the first fields discovered in Lake Maracaibo with production dating back to 1927. Production is from shallow (2000 to 3000 ft) unconsolidated sands in the Miocene La Rosa, Lower Laguna and Lower Lagunillas formations. Because production from the field is from highly unconsolidated sands, very limited core was available. Complicating the reservoir performance is the subsidence that has occurred. This has been accounted for by using very high rock compressibility in the simulation model.
This paper describes and quantifies the benefits of residual oil vaporization in a gas injection project. Vaporized oil is recovered as natural gas liquid (NGL) when the injected gas is produced. In the reservoir application studied, 20% of the liquid hydrocarbons produced were being recovered as NGL.
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