This challenging reservoir characterization case study is defined by the interaction between two reservoirs with different production mechanisms: a fractured basement reservoir and an overlying sandstone reservoir. The existing static geologic concept has been significantly enhanced by integrating pressure data from a unique three-year shut-in period to aid modeling of fractured reservoir connectivity. Previously, the seismic dataset was predominantly used to model the fault and fracture network and guide well planning. In the current approach, the full field data set, including all drilling parameters and new reservoir surveillance data were integrated to address uncertainty in the connected hydrocarbon volume and the relative importance of each production mechanism. The result is a reservoir management tool with which to test re-development concepts and effectively manage pressure decline and increasing gas/oil ratio (GOR) and water production.
To achieve a fully integrated history matched model, the first step was to make a thorough review of the existing detailed seismic interpretation, vintage production logging tool runs (PLT's), wireline logs (including borehole image logs (BHI)) and drilling data to find a causal link between hydraulically conductive fractures and well production behavior. In parallel, a material balance exercise was run to incorporate the new pressure data acquired during the field's shut-in period. The results of the material balance analysis were combined with seismic and well data to define the distribution of connected fractures across the field. Additionally, the material balance analysis was used to determine the connected hydrocarbon volume, the distribution of initial oil in-place and the relative hydrocarbon contribution from each production mechanism.
The field is covered by multi-azimuth 3D seismic and 43 vertical to highly deviated development wells, providing significant static and dynamic data for characterizing the distribution of connected fractures. Despite this high quality, diverse and field-wide dataset, prior modeling iterations struggled to sufficiently describe the production behavior seen at the well level. This has resulted in a major challenge to predicting the production behavior of new development wells and planning for reservoir management challenges. Capturing the complex interaction between production variables (including lithology, matrix versus fracture network, geomechanical stresses, reservoir damage and pressure depletion) at a field level instead of at an individual well level resulted in a unified static and dynamic model that reconciles all scales of observation.
This oilfield represents a unique reservoir characterization opportunity. The result is a key example of how iterative, integrated geological and engineering driven reservoir modeling can be used to inform the development in a complex, mature field. This case study provides an excellent analogue for the reservoir characterization of other fractured Basement fields and/or Basement-cover reservoir couplet fields in the early to late phases of their development.
Africa (Sub-Sahara) Bowleven has started drilling operations at the Moambe exploration well on the Bomono permit in Cameroon. Moambe is the second well in a two-well program, approximately 2 km east of the first well, Zingana. It targets a previously undrilled Paleocene Tertiary three-way dip fault block containing multiple sands and will be drilled to an estimated 1620 m in measured depth. Both wells will be logged. Bowleven is the operator and holds 100% interest. Asia Pacific Murphy Oil discovered gas at its Permai exploration well in deepwater Block H in the South China Sea offshore Malaysia. The find is Murphy's eighth consecutive success in the area around the Rotan floating liquefied natural gas project, which is planned to begin its first production in 2018.
Bessa, Fadila (Occidental Petroleum Corporation) | Sahni, Vinay (Occidental Petroleum Corporation) | Liu, Shunhua (Occidental Petroleum Corporation) | Tan, Jiasen (Occidental Petroleum Corporation) | Frass, Manfred (Occidental Petroleum Corporation) | Kessler, James (Occidental Petroleum Corporation)
Understanding and modeling the interaction between hydraulic fractures and natural fractures is important to predict shale production performance. This paper presents a workflow that incorporates natural fractures, rock properties, and stress regimes to understand fracture behavior during stimulation treatment. The methodology also integrates the predefined discrete fracture network (DFN) and 3D reservoir properties to build a comprehensive hydraulic fracturing model. Heat maps are also generated to help evaluate completion design and well spacing strategies.
Applying the integrated fracture characterization workflow to the study area revealed that the vertical and lateral fracture growth is a function of structural context, stress conditions, and rock mechanical properties. Stimulation parameters, including proppant volume and injection pressures, for one horizontal and six vertical wells were utilized to build a comprehensive fracture network for the study area. The resulting model shows: (a) the stimulation of predefined natural fractures, and (b) the generation of induced fractures in the maximum stress direction associated with re-activation of pre-existing faults and fractures. The modeling results were validated by interwell interference data.
Fractures play an important role in hydrocarbon production from organic-rich shale reservoirs (Gale, et al., 2014). This is evident from the higher than expected production rates typically observed from low-porosity and ultra-low permeability shale rocks. Moreover, many shale outcrops, cores, and image logs show an abundance of natural fractures or fracture traces. This study integrates natural fracture characteristics, directional stresses, and hydraulic fractures to characterize and better comprehend Permian Wolfcamp production performance.
Several factors influence the stimulated rock volume (SRV) geometry during a hydraulic fracturing stimulation treatment. These factors include: structural context, natural fracture networks, rock mechanical properties, lithology, and stress changes associated with tectonic events (Gale et al., 2014; Maity, 2018). Furthermore, natural fracture systems in shales are heterogeneous; they can enhance or reduce formation productivity, augment or diminish rock strength, and may have a tendency to influence hydraulic fracture stimulation (Doe et al., 2013). The flow of stimulation fluid through natural fractures and the generation of hydraulic fractures were modeled in this study.
Objectives and Scope: Natural fractures were observed in core and image logs from the Hydraulic Fracture Test Site (HFTS) in Reagan Co., Texas. This paper provides an analysis of these fractures, including their orientation, size, spatial distribution, and openness.
Methods: We measured kinematic aperture sizes of two sets of sealed, opening-mode natural fractures in a slant core taken through a stimulated volume, and we analyzed the population distribution using cumulative frequency plots. For the spatial organization study, in addition to fractures identified in the slant core, we used data from image logs from three nearby horizontal producing wells. The spatial organization of fractures was investigated using our statistical method, Normalized Correlation Count (NCC), and by calculating the Coefficient of Variation, Cv, which is a measure of clustering.
Results: In the slant core 197 Set 1 (NE-SW) fractures are present (154 kinematic apertures measured), and there are 112 Set 2 (WNW-ESE) fractures (62 measured). The aperture-size distribution for Set 1 fractures follows a negative-exponential function, whereas Set 2 fractures follow a weak power-law. Only two fractures, both in Set 1 and ~ 1 mm wide, were open in the subsurface, although many more are now parted, mostly in Set 2. Linear intensity, P10, for measured fractures ≥1 mm wide is 0.01 frac/ft (Set 1) and 0.006 frac/ft (Set 2). Both natural fracture sets in an FMI image log from a nearby well have spatial arrangement patterns of regularly-spaced fractal clusters and Cv greater than 3 (3.22 to 4.05). Fracture cluster widths are 100–200 m, and cluster spacings range from 350–600 m. Fractures in COI image logs in two other wells have lower Cv (1.59 to 2.32). Both sets in the 6U well and Set 1 in the 6M well show elevated intensity along the middle section of the well and NCC indicates broad, but weak non-fractal clustering, likely related to lithological control of fracture growth. In the slant core Upper Wolfcamp Set 1 fractures are indistinguishable from random; Set 2 show a log-periodic clustering but with Cv less than 2.
Significance: Incorporation of Discrete Fracture Networks (DFN's) into hydraulic fracture modeling and reservoir simulation requires high-quality natural fracture data from image logs and core. This paper provides such data and provides information on natural-hydraulic fracture interaction at the HFTS site.