|Theme||Visible||Selectable||Appearance||Zoom Range (now: 0)|
Passive low frequency seismic exploration is a technology for specifying the geological attributes of the earth's interior. Known examples of its application for tasks, for example, determining of the contour of hydrocarbon deposits (direct hydrocarbon indicator DHI) [
In this paper, we propose a physic-mathematical method for interpreting this phenomenon, based on the recognized approaches of extracting the Green function from passive observations [
It is assumed that the properties of the medium are known; it is necessary to determine the location of a small-thickness formation with anomalous absorption. Hydrocarbon deposits with high permeability are recognized with high absorption. Abnormal absorption at low frequencies occurs as a result of friction of the liquid phase of hydrocarbons on the skeleton of the rock during the passage of longitudinal waves [
The task is reduced to a one-dimensional partial task of the full-wave inversion, when the base model is generally known, and it is necessary to find individual deviations (oil-saturated reservoirs). A numerical simulation is performed with different possible placements of a search object. Field record spectra, after applying filtering procedures, are matched with synthetic ones. We solve this problem in the Born approximation of single scattering with regularization in the form of restrictions on the coefficients, this problem is solved by quadratic programming. The proposed method has been applied to solve problems of hydrocarbon prospecting [
Combining 1C (single component) sensors and 3C (three components) ones is considered as an evolution to solve problems concerning scarcity of passive LFS data due to our long-time reliance on 3C sensors only to collect such valuable data. Quantitative approaches will merge soon!
In a very brief amount of time (geologically speaking), the exploration and production energy business has dramatically shifted to an unconventional universe where geologic risk is low, completion technology is arguably as important as the geology, and where favorable economics are the well-honed byproduct of cost reduction, sweet spot definition, drilling and completion efficiency, and midstream transmission. Having spent our entire careers (more than 40 years each) in the upstream business, it is important to step back and look at the big picture every once in a while. We have seen many exploration paradigms broken--resulting in the birth of deepwater exploration, subsalt development and, most recently, unconventional shale development. We have also seen the demise of some false saviors along the way such as the Atlantic Tethyan reef play, Destin Dome off the Gulf Coast, Mukluk in the Beaufort Sea, the lowly Lodgepole play in North Dakota, and post-sanction exploration in Libya, to name a few. Whether successful or otherwise, all of these exploration concepts required creative thought and a willingness to invest capital into what could ultimately become a commercial venture. Incumbent with any success was the realization that whatever was discovered would need to be successfully commercialized via transmission to market.
The Cretaceous Eagle Ford of South Texas is a major unconventional play. Age equivalent rocks are present in the adjacent Burgos Basin, Mexico along with other unconventional targets in the Jurassic. The objective of this study was to map areas of unconventional potential from basinwide maturity predictions provided by 3D modeling. This study has identified oil, wet gas and dry gas areas of interest for the Cretaceous and Jurassic targets. These areas of interest can then be used to focus followup studies by companies or institutions evaluating joint ventures and/or lease sale blocks in the basin.
The 3D model for the Burgos Basin was made using publicly available information. Regional structure maps were made by integrating published structure maps and cross sections. Structure maps, temperature gradients from well logs and a tertiary erosion map were the key inputs used to model maturity. The Cretaceous Agua Nueva and the Jurassic La Casita/Pimienta Formations were the primary zones of interest. Rock maturity data was available for one Cretaceous and one Jurassic well. The model was also verified by comparing to Cretaceous and Jurassic unconventional well results.
Structural strike of the Eagle Ford in south Texas is southwest to northeast. Near the border structural strike abruptly changes to nearly north - south. In the Burgos Basin, the Mesozoic section dips eastward toward the Gulf of Mexico due to over 30,000 feet of Tertiary sand and shale deposition. Faulting in the Tertiary section generally soles out above the Mesozoic, so the Mesozoic is mostly tectonically undisturbed which is favorable for unconventional targets.
The prospective area for the Cretaceous and Jurassic is essentially coincident and is over 40 miles wide and 300 miles long. The prospective area was defined according to depth and modeled vitrinite reflectance equivalence (VRE). Measured depths of 5,000 to 15,000 feet and VRE greater than 0.8 were used. The rationale was that shallower than 5,000 feet would have low pressure and temperature and greater than 15,000 feet would have too high a well cost for horizontal wells. The oil prospective area is from 0.8 to 1.1 VRE, wet gas from 1.1 to 1.7 VRE and dry gas over 1.7 VRE. Oil spacing was assumed to be 100 acres and gas spacing 200 acres. Total recoverable resources are estimated at approximately 27 BBOE of which 15% are liquids (oil and condensate) and 85% are gas.
Hjeij, Dawood (Division of Sustainable Development, College of Science and Engineering, Hamad Bin Khalifa University) | Abushaikha, Ahmad (Division of Sustainable Development, College of Science and Engineering, Hamad Bin Khalifa University)
This paper investigates the performance of the mimetic finite difference (MFD) discretization scheme for modelling fluid flow in anisotropic porous media. We apply numerical benchmark studies on the MFD scheme to measure its accuracy when the horizontal permeability is much larger than the vertical one in a diagonal permeability tensor. We also run full-field simulations to investigate the modelling capability of this method and compare it to other advanced discretization schemes.
Zhu, Haiyan (Chengdu University of Technology) | Zhao, Ya-Pu (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation) | Feng, Yongcun (Institute of Mechanics, Chinese Academy of Sciences) | Wang, Haowei (Institute of Mechanics, Chinese Academy of Sciences) | Zhang, Liaoyuan (University of Chinese Academy of Sciences) | McLennan, John D. (University of Texas at Austin)
Summary Channel fracturing acknowledges that there will be local concentrations of proppant that generate high-conductivity channel networks within a hydraulic fracture. These concentrations of proppant form pillars that maintain aperture. The mechanical properties of these proppant pillars and the reservoir rock are important factors affecting conductivity. In this paper, the nonlinear stress/strain relationship of proppant pillars is first determined using experimental results. A predictive model for fracture width and conductivity is developed when unpropped, highly conductive channels are generated during the stimulation. This model considers the combined effects of pillar and fracture-surface deformation, as well as proppant embedment. The influence of the geomechanical parameters related to the formation and the operational parameters of the stimulation are analyzed using the proposed model. The results of this work indicate the following: 1. Proppant pillars clearly exhibit compaction in response to applied closure stress, and the resulting axial and radial deformation should not be ignored in the prediction of fracture conductivity. Introduction In conventional hydraulic-fracturing treatments, it is presumed that proppant is distributed uniformly in the fracturing fluid and generates a uniform proppant pack in the fracture (left-hand side of Figure 1). The propped fracture serves as a high-conductivity channel facilitating fluid flow from the reservoir to the well. Channel fracturing is a new fracturing concept, and replaces a nominally homogeneous proppant pack in the fracture with a heterogeneous structure containing a network of open channels (Figure 1, right) (Gillard et al. 2010). This channel-like structure is achieved by using fiber-laden fluids or self-aggregating proppant together with a pulsed-pumping strategy. In channel fracturing, the interaction between the proppant and fracture surfaces is a "point" contact, in contrast to the "surface" contact assumed to exist in conventional fracturing.
Our objective in this paper is to highlight the potential of the Eagle Ford (Cretaceous) and Pimienta (Upper Jurassic) shales in Burgos Basin (Mexico) through a comparison with the Eagle Ford Shale in Texas. The comparison is a case study focused on real data and their interpretation, north and south of the border, including geochemistry, geology, production, and reservoir-engineering data.
Our overall approach includes the description of Eagle Ford data in Texas, as well as Eagle Ford and Pimienta data in the Burgos Basin. The geologic comparison is carried out using cross sections of the various formations and geophysical data. Geochemical and petrophysical data are compared using specialized crossplots. Production data are compared through rate transient analysis and by investigating the different flow periods observed in wells in both sides of the border. Reservoir-engineering aspects are compared using material-balance methods developed specifically for analyzing multipurpose shale petroleum reservoirs.
Results indicate that there are many similarities but also some differences between the Eagle Ford Shale in Texas and shales in Mexico. The geologic and seismic cross sections show that there is continuity of the Eagle Ford on both sides of the border. However, structural geology in Mexico tends to be more complex than that in Texas. The geological and geochemical descriptions also show important similarities in the rock mineralogy, and the quantity, quality, and maturity of the organic matter. Well-log data show the same pattern of distribution on modified Pickett plots, developed originally for evaluation of the Eagle Ford Shale in Texas. Production data in the Burgos Basin shales are characterized by long periods (several months or even years) of transient linear flow, something that compares well with the Eagle Ford in Texas. Specialized material-balance calculations, which consider multiple porosities, have been used in the Eagle Ford Shale in Texas and are shown to have similar application in the Burgos Eagle Ford and Pimienta shales. On the basis of the Eagle Ford Shale performance in Texas, and the similarities with Burgos shales, the conclusion is reached that there is significant potential in the Mexican Eagle Ford and Pimienta shales.
We present a comparison of the interpretation of real geoscience and engineering shale data collected on both sides of the border. The comparison is meaningful and suggests that the potential of shale reservoirs south of the border will be quite significant. Mexico should benefit from the lessons learned from the Texas Eagle Ford Shale.
Study made from the results observed over a particular application objective with one of the recently developed proppant fracturing techniques known as Channel Fracturing. This technique was used in this application to place a proppant fracturing treatment in a tight gas reservoir which pushes the installed well completion to reach its mechanical limit capabilities. Channel (or pillar) fracturing was applied in multiple cases with the intention to constrain the pressure increase commonly observed during a fracture job execution.
Zhao, Kai (Xi’an Shiyou University and Shanxi Key Laboratory of Advanced Stimulation Technology for Oil & Gas Reservoirs) | Li, Xiaorong (University of Texas at Austin) | Yan, Chuanliang (China University of Petroleum, East China) | Feng, Yongcun (The University of Texas at Austin) | Dou, Liangbin (Xi’an Shiyou University) | Li, Jing (China University of Petroleum, East China)
Fault reactivation caused by reservoir depletion has been an important issue faced by the oil and gas industry. Traditional views suggest that with reservoir depletion, only normal faults can be activated and fault stability either monotonically decreases or increases, which are not consistent with field observations. In this paper, a fault-sliding-potential (FSP) model was developed to analyze fault stability during reservoir depletion for different types of faults. The evolution trend of fault stability with reservoir depletion and the corresponding judging criteria were obtained by calculating the derivatives of FSP. The influences of reservoir depletion on nonsealing and sealing faults were investigated. Case studies were performed to analyze FSP for different types of nonsealing and sealing faults with different fault properties and attitudes. The results show that reverse and strike faults might also be reactivated with reservoir depletion. The fault stability might not monotonically decrease or increase; instead, four evolution patterns of fault stability might occur, with reservoir depletion dependent on the parameters of the faults. Reservoir depletion usually leads to a higher sliding risk for sealing faults than for nonsealing faults. The results also indicate that fault stability is a strong function of fault attitudes, including the dip and strike of the fault.
An engineering approach is discussed for identifying a potentially unconsolidated reservoir in an exploratory area and controlling sand flowback by fracturing using a liquid-consolidation additive as the binding agent.
A vertical gas well targeting an exploratory reservoir was completed and hydraulically fractured to help enhance productivity. A petrophysical evaluation was performed with openhole logs, and results showed a potentially unconsolidated pay zone that posed the risk of producing formation sand.
After identifying the issue, precautionary measures were taken to help prevent sand production. An engineered solution to hydraulically fracture the reservoir using a liquid-consolidating additive as a binding agent, opposed to the conventional resin-precoated proppant, was successfully performed.
The fracturing technique enhanced well productivity and allowed sand-free high production rate of hydrocarbons. Orienting the perforations toward the maximum horizontal stress direction helped reduce tortuosity and placement of the fracturing treatment.
This paper presents petrophysical analysis, treatment design, and application, including production analysis to evaluate the effectiveness of the treatment.
Evaluation of the openhole logs and understanding the criteria for potential sand-producing formations can help identify sand flowback in the early stages of well completion to promote the application of solutions that will substantially reduce/eliminate problems associated with sand flowback during the life of the well. This technique helped achieve sand control without using screens, simplifying wellbore equipment while enhancing reservoir production. Early identification of the problem minimized production losses and non-productive time (days) for the operator and potential formation sanding problems.
I. Yucel Akkutlu is a professor of petroleum engineering and William Keeler faculty fellow at Texas A&M University in College Station. Yucel holds the Flotek Industries, Inc. Career Development Professorship. He holds a degree in chemical engineering and received his Ph.D. in petroleum engineering from the University of Southern California, Los Angeles. His main research interest is fluid flow, transport and reactions in porous media.