Oilfield Review - Summer 2012

Journal of Petroleum Technology, 1993

Summary Under currently known reservoir drive mechanisms, initial exploitation of a new field usually leads to drilling in several regions of the field for optimum production. As the field matures, it often is necessary to drill new wells to recover oil reserves trapped because of undetermined reservoir heterogeneity and not acknowledged during initial field development. Targeting new wells in a mature field is challenging because it calls for consensus among interdisciplinary groups (reservoir and production engineers, geoscientists, and drilling and facility engineers). The challenges usually involve estimating the cost and production of the new wells and finding convincing arguments that the existing wells will not drain the trapped reserves adequately. This paper provides a team approach to confront these challenges to target new wells in the mature Prudhoe Bay field. The field example shows that additional oil recovery was obtained with infill drilling. Introduction The large, ...

SEG Technical Program Expanded Abstracts 2011, 2011

Surface seismic data has proven to be an invaluable asset for organizations producing hydrocarbons from unconventional resource plays. Initially, one of the primary benefits of surface seismic was the ability to locate and avoid drilling into zones with faults, fractures and karsting which adversely affected the ability to complete the well successfully. More recent advances in pre-stack seismic data analysis yield attributes that appear to be correlated to formation lithology, rock strength and stress fields. Knowledge and proper utilization of these attributes may prove valuable in the optimization of drilling and completion activities. In this article we show an integrated seismic approach based on pre-stack azimuthal seismic data analysis and well log information to identify "sweet spots", estimate geomechanical properties and in-situ principal stresses.

This is an integrated analysis of the La Luna Formation in the Chuira pop-up structure, located in the Middle Magdalena Basin (MMVB). A structural trap originally mapped with 2D seismic and later with a 3D seismic volume, was interpreted using a conventional time structure maps and depth conversion methods. In 2009, the first well drilled a sequence of calcareous rocks which produce oil in stable natural flow but with a low rate. In order to understand this potential discovery, multidisciplinary studies were conducted including a detailed geology of the La Luna Formation information from outcrops, the integration of seismic attributes, log analysis, and an exhaustive reservoir research from existing samples. Stratigraphic studies of this Upper Cretaceous sediments show differences on their depositional environment regarding variations inside a carbonate platform, water column, oxygen content and an anoxic event of long extent and maximum depth of Coniacian age. A structural evaluation conducted on near outcrops, defines the orientation of fractures. These features were compared with subsurface information including crossed dipole sonic, nuclear magnetic resonance, and microresistivity image logs. Geophysical studies on the seismic volume, including AVO, Seismic inversion, and interpretations on seismic attributes like coherence, and curvature incorporated to this study the regional orientation and intensity of fractures and faults patterns, all of them tied to existing logs. All information was integrated to define well locations ranked by the best fracture productive zones obtained from this proposed method. This approach illustrates a methodology that will represent an increment of production and reserves in this kind of natural fractured reservoirs.

Journal of Petroleum Science and Engineering, 2020

For maximum productivity enhancement when targeting low permeability formations, horizontal wells must be made to induce multiple transverse fractures. An orientation criterion for fracture initiation is developed using analytically-derived approximations for the longitudinal and transverse fracturing stresses for perforated wellbores from the literature. The validity of the criterion is assessed numerically and is found to overestimate transverse fracture initiation, which occurs under a narrow range of conditions; pertaining to low breakdown pressure and low formation tensile strength. A three-dimensional numerical model shows that contrary to existing approximations, the transverse fracturing stress from perforated horizontal wells becomes more compressive as wellbore pressure increases. This shrinks the "breakdown pressure window," which is the range of wellbore pressures over which transverse fracture initiation takes place. This creates a second constraint for transverse fracture initiation, which is the "critical tensile strength" value. This determines the maximum formation tensile strength at which transverse fracture initiation is possible for a given in-situ stress state and perforation direction. Sensitivity analyses are performed based on data from seven unconventional shale reservoirs (Barnett, Bakken, Fayetteville, Haynesville, Niobrara, Marcellus and Vaca Muerta) for horizontal wells drilled parallel to S hmin. The frequent longitudinal fracture initiation occurrence indicated suggests fracture reorientation in the near-wellbore region to be a common event, through which the propagating fractures become aligned with the preferred fracture plane (perpendicular to the least compressive principal stress). This induces near-wellbore fluid tortuosity, which in turn can lead to completions and production-related problems, such as early screenouts and poststimulation well underperformance.

The geological use of wireline logs in formation evaluation has long been neglected, mainly due to their predominant role as hydrocarbon indicators. Though this petrophysical use cannot be under-stated, with a little more insight, much more geological information can be obtained from these logs.

Proceedings of SPE Annual Technical Conference and Exhibition, 2005

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The use of the dual-porosity approach for the modeling of naturally fractured reservoirs has become widely accepted in the oil industry. The original idealized model assumes that the fracture is the primary conduit for flow, whereas the matrix acts as a group of distributed sources and sinks. More recently, several improvements and/or refinements have been proposed. The dual-permeability model was introduced when it became evident that, for some fractured reservoirs, the continuity of the matrix is an important consideration. Additional research has addressed more accurate representation of matrix-fracture fluid transfer. In particular, the representation of gravity and capillarity effects, capillary continuity or discontinuity of matrix blocks, and the modeling of the reimbibition phenomenon have received much attention. It is important to point out that these models have many adjustable parameters that needs to be tuned, in order to obtain a history match with the field production data. As a consequence, it is possible to establish a set of parameters for the model that reproduce the production data, but incorrectly represent the reservoir. This paper describes a methodology for the characterization of fracture systems, in order to calculate the parameters needed for a dual porosity reservoir simulation model. This methodology is used to integrate fracture data from various sources and to provide not only a qualitative but also a quantitative evaluation of the fracture network properties. One of the fundamental assumptions of the methodology is that faults observed at the seismic scale can be used to derive a fracture model at the scale of interest for a reservoir simulation model. This method is feasible because many properties of faults and fractures are scaleinvariant. Also, the curvature of the horizons of each interval, the types of facies and the direction of geomechanical stress are taken into account. The loading of the fracture model allows to include information obtained from well cores and logs, analog outcrops, borehole-image data, geomechanical stress studies, and fault data. Such a model has been constructed for a Venezuelan reservoir.

Canadian Unconventional Resources and International Petroleum Conference, 2010