Africa (Sub-Sahara) Algeria awarded four of 31 oil and gas field blocks on offer to foreign consortiums in its first auction since 2011. Shell and Repsol won permits for the Boughezoul area in the north of the country, while Shell and Statoil won permits for the Timissit area in the east. A consortium of Enel and Dragon Oil was awarded permits for both the Tinrhert and the Msari Akabli areas. Circle Oil's CGD-12 well, located onshore Morocco in the Sebou permit, encountered natural gas at different levels within the Guebbas and Hoot sands. Wireline logging analysis confirmed a net 9.7 m of pay. The first test, over the Intra Hoot sands, flowed gas at a sustained rate of 2.21 MMscf/D through an 18/64‑in. The primary target, the Main Hoot sands, flowed at a sustained rate of 4.62 MMscf/D through a 24/64-in.
Walls, Anne (BP) | O'Brien, Rob (BP) | Clarke, Jim (BP) | Pereira Costa, Sofia (BP) | Oliveira, Shirley (BP) | Smith, Ken (MBARI) | Priede, Imants (Oceanlab) | Vardaro, Michael (Oregon State University) | Rowe, Gilbert (Texas A&M) | Bailey, David (University of Glasgow) | Milligan, Rosanna (University of Glasgow) | Ruhl, Henry (NOC Southampton) | Sangolay, Bomba (INIP)
In early 2009, two Deep-ocean Environmental Long-term Observatory Systems (DELOS) were installed in around 1,400m water depth in Block 18, Angola. The intention is that they will provide a unique long-term (25 year) dataset of deep-ocean variability. Each station consists of a fixed platform structure into which serviceable modules containing oceanographic, acoustic and camera equipment are placed. One monitoring station is located near to subsea infrastructure, and the other is located at the same depth but distant from, and upstream of, any oil industry activities. This far-field platform also has a sediment trap module. This will enable both long term natural and anthropogenic changes in the physical, chemical and biological environment to be identified and investigated. The data will also allow an understanding of the pace of recovery from unforeseen impacts and provide a linkage between marine biodiversity and climate change.
An international scientific steering committee initially developed the DELOS concept and specified the equipment. It now oversees the research associated with data interpretation.
The modules are recovered approximately every twelve months, and the data downloaded, batteries changed and the equipment serviced before being returned to the seabed. This paper will discuss the pros and cons of the intermittent data collection and how the data are managed and interpreted, including sharing with our Angolan partners.
Laverde, Fabio (Schlumberger) | Pozo, Gerardo (PETROBRAS Energia Peru) | Miranda de Oliveira, Flavio (PETROBRAS Energia Brazil) | Carrillo, Gonzalo (Schlumberger) | Torres, Kevin Michael (PETROBRAS Energia Peru) | Sanchez, William (Schlumberger) | Alvarez B., Jose Luis (PETROBRAS Energia Peru) | Contreras, Fabio (Schlumberger)
Block X, located in the Talara Basin in northwest Peru, is one of the oldest producing basins in America. The reservoirs that have been studied are the Eocene Mogollon, Ostrea, Echinocyamus, and Helico units. The present structural model has benefited from previous jobs performed by Petrobras, where an old extensive fault system oriented northeast to southwest was affected by a later fault system trending northwest to southeast. Low-angle faults have cut the upper section of the Helico unit, consequently moving older sequences to the northwest. This structural setting controls the distribution of facies bodies, their interaction, size, and geometry, and the quantity of sand facies.
Based on an integrated facies analysis from numerous outcrops, 21 cored wells and more than 750 well-log motifs, a reliable stratigraphic framework was constructed that resulted in the identification of specific facies associations, stratigraphic or depositional surfaces, defining genetic units . Gross depositional fluvio-deltaic environments of the Mogollon succession were interpreted toward the southeast, shoreface at the Ostrea facies throughout the area, the deltaic and fluvial for the Echinocyamus in localized areas, and the tidal flat-beach-coastal plain toward the northeast, with the important development of fan deltas into submarine canyon-fills. This development was recorded within the Helico at the southwest of the study area. Because of the many years of production data available, the geologic model and facies distribution could be adjusted with dynamic data, such as pressure data, production tests and water cut. A possible way of achieving such conditions included adjusting the connectivity between sand bodies, their orientation and the vertical communication.
The products of the integrated study included: 1) mapped areas and zones of potential reservoir connectivity, and 2) geological model building used in 3D geostatic modeling. Mapping of the sequences resulted in the proposal of new infill wells and potential workovers. The results of the 3D static model work were: a) realistic fine-scale geological models that were consistent with the observed data, b) calculations of uncertainties in the oil-in-place volume.
Improved remediation design and operation resulted from effectively using reservoir-aquifer characterization tools to identify hydraulic flow units and connectivity of sediments in contaminant-affected shallow aquifer-aquitard systems. The objective of this approach was to utilize an improved understanding of subsurface conditions to develop more effective remediation designs and operating plans. This was accomplished by developing an increased understanding of aquifer storage and flow properties, preparing geologic models, and identifying contaminant migration pathways and permeability barriers. Characterization methods practiced in petroleum exploration and production were applied to near-surface sedimentary sequences to describe the subsurface hydrogeologic setting. Stratigraphic analysis using continuous core, detailed core descriptions and analogous sedimentary environments of deposition was employed to develop deterministic geologic models of the subsurface. Predictive mapping was used to delineate contaminant-affected soil and groundwater, and interpretations were adjusted in an iterative manner with the acquisition of data.
This paper will discuss case histories of overall project characterization and remediation of two sites located in Southern California, USA. These case studies demonstrate the effect of subsurface soil heterogeneities and variation in contaminant distribution on remediation.
The method of reservoir-aquifer characterization uses analogous sedimentary environments to describe a type of sedimentary locality (e.g., meandering stream), in which the resultant deposits are determined based upon specific lithological characteristics of texture, composition and sedimentary structures.1,2 A litho-stratigraphic soil description was developed to supplement the typical soil description to create an input data set useful for stratigraphic analysis, correlation and mapping of stratigraphic units based on sedimentary environments of deposition.
Sedimentary sequences were described in terms of overall lithology and textures. Sands and silts were further described in terms of grain size range (Wentworth scale), median size, angularity, roundness, sorting and mineralogical composition (accessory minerals and fossils, and percent quartz, feldspar and lithic fragments) and sedimentary structures (bedforms, plastic deformation, tool marks, bioturbation, plant-root casts, etc.). Secondary porosity and permeability development in clay was identified by the presence of plant-root casts, carbonaceous plant fragments and caliche nodules. Continuous core sampling was conducted from the ground surface to total depths of 30 to 60 ft-bgs (feet below ground surface). Soil cores were checked for visible and detectable contaminants.
The lithology depth-profile served as the basis for well-to-well correlation and identification of vertical sedimentary sequences and bedding. Confidence in the well-to-well correlations was gained by the close similarity of lithology profiles between neighboring wells. Mapping was an iterative process based on comparison of lithology depth-profiles with similar and applicable sedimentary environments of deposition from which to develop a site-specific geologic model. Predictive structure and isopach maps and cross sections were constructed and refined after each phase of drilling. The maps and cross sections were used in depicting the extent of contaminant-affected subsurface sediments and for selecting future drilling locations.
It is an established fact that the Canyon Sand Formation in the Val Verde Basin must be fracture stimulated to exploit the reservoir's potential. However, in the past, the degree of stimulation required has been a judgement call at best. Due to recent results from an industry consortium dealing with conductivity, it became obvious that many past stimulation designs were inadequate. Change in fracturing fluids, as well as proppant selection, concentration, and placement, have led to an improved design.
Past treatments were insufficient in Past treatments were insufficient in fracture half-length and conductivity. These treatments have now been modified to double the fracture half-length, and to increase the conductivity six-fold. These design changes are necessary to overcome fluid damage and long-term conductivity deterioration. Computer simulated fracturing programs have been used to develop improved programs have been used to develop improved designs. When implemented in the field, these designs have proven to increase profitability through post-frac production profitability through post-frac production results.
Although previously reported laboratory work has addressed the topic of in-situ fracture conductivity, these findings were not substantiated with actual production results. Therefore, a case study of twenty four wells located in Sutton County, Texas was performed to determine the actual effect of fracturing fluid type on well performance. Comparison of post-frac performance. Comparison of post-frac well production indicates that different fracturing fluids can dramatically effect a well's producibility. This case study supports the consortium's findings, that different fracturing fluid types create varying levels of permeability impairment.
Located within the Val Verde and Midland Basins, the Canyon Sand formation has provided commercial gas production for over 30 provided commercial gas production for over 30 years. The area of this producing horizon covers over 10 counties in sout central Texas. The information presented here concentrates primarily in Sutton, Crockett, and Edwards counties.
Past fracturing treatments in this area Past fracturing treatments in this area have varied greatly in both size and type. Many different fracturing fluids and proppants have been used in trying to find an proppants have been used in trying to find an ideal stimulation treatment. The volume of fluid and proppant used in these treatments often varied due to individual perceptions as to what fracture height would be obtained and what fracture length was necessary. The producing intervals within the Canyon Sand are often separated by small-to-medium shale barriers, which may or may not act as a barrier to contain fracture height. Some fracture treatments were designed to pump into each individual zone, while others attempted to fracture stimulate many zones at once, hoping to overcome the horizontal stresses of the shale intervals.
The fluids used in these stimulation treatments have also varied widely, and have included gelled oils, linear gelled water, 3% gelled acid, crosslinked gelled water, and foams of either nitrogen or carbon dioxide.
The ability to effectively enhance production through hydraulic fracturing is dependent on an accurate description of the reservoir production mechanism(s) . Fracture designs may dif f er greatly depending on the production mechanism (s) . The complex nature of hydraulically fractured reservoirs in which the predominant production mechanism is a set of interconnected, naturally occurring fractures is investigated in this paper. The paper integrates general reservoir simulation results with actual field data from a naturally fractured reservoir in the Piceance Basin, Colorado.
The study investigates a variety of natural fracture/matrix properties and compares the productivity (of these naturally fractured reservoirs to homogeneous reservoirs with the same average flow capacity. The paper also investigates the influence of natural fracture anisotropy on hydraulic fracture design. The effect of damage to the natural fracture system is illustrated and compared to analogous homogeneous reservoirs. The economic considerations associated with many of the reservoir production mechanisms are presented.
The results of the reservoir simulations indicate that optimum fracture lengths for isotropic, naturally fractured reservoirs are identical to those estimated for homogeneous reservoirs having the same average flow capacity. Therefore, accepted fracture design considerations to determine optimal fracture length and conductivity can be used in isotropic, naturally fractured reservoirs based on the average flow capacity of the reservoir. However, fracture design considerations are more complex when the effects of natural fracture damage and anisotropy are encountered.
The basic fracture design criteria for homogeneous reservoirs has been discussed in detail by several authors. This literature also illustrates the interrelationship of fracture length, fracture conductivity and well productivity, and the economic impact of many fracture design considerations. However, fracture design considerations in more complex, naturally fractured reservoirs are not widely available in the literature. This paper presents reservoir simulations and field data that illustrate many fracture design considerations in naturally fractured reservoirs.
The initial requirement for designing a hydraulic fracturing treatment is an accurate description of the reservoir, including the predominant production mechanism (s) . Reservoir production mechanisms and characteristics can be obtained from log, core, geological, well test and production data. In many cases, a limited amount of data are available, and reservoir characteristics and production mechanisms are inferred from pre- and postfracture well performance. There are many uncertainties associated with inferring reservoir properties based on a limited amount of data because reservoirs with vastly different production mechanisms can produce very similar pressure /production profiles. The reservoir simulations presented will illustrate the similarities in production and pressure buildup behavior for homogeneous and naturally fractured reservoirs that have the same average flow capacity.
Gamma ray spectral logging devices, in addition to total gamma ray counts, record the individual contributions of potassium-40 isotope, uranium series nuclide bismuth-214, and thorium series nuclide thallium-208. Application of these data to identify fractured shale reservoirs and source-rock characteristics of argillaceous sediments is discussed.
Highly radioactive, black, organic-rich, and gaseous shales are encountered in several U.S. geologic provinces. Such organic-rich shales are not only potential source rocks but frequently owe their localized but significant production potential to natural fracture systems in an otherwise impermeable rock. These natural fracture systems normally are concentrated in the interbedded brittle, calcareous, cherty, or silty zones. Conventional logging and interpretive techniques are not adequate to evaluate satisfactorily the complex and frequently fractured shale reservoirs. Novel applications of gamma ray spectral logging data for characterizing these shale formations as to their reservoir properties and source-rock potential (SRP) are discussed here. Calcareous and silty zones, both characterized by low values of potassium and thorium but excessively high values of uranium, are located easily with natural gamma ray spectral information obtained from highly sensitive scintillation spectrometer logging tools. These interpretive concepts already have assisted in many successful gas- and oilwell completion and recompletion attempts in the more permeable and/or fractured intervals of such shale formations. Such logging information also allows a continuous monitoring of the SRP of shales in open and cased boreholes. Hence, both vertical and lateral SRP variations can be studied using appropriate mapping techniques. Gamma ray spectral data also assist in detailed stratigraphic correlations, because in addition to total gamma ray counts, individual gamma rays emitted by potassium-40 (K(40)), the uranium series nuclide bismuth-214 (Bi(214)), and the thorium series nuclide thallium-208 (TI(208)) are measured. K(40) emits gamma rays at 1.46 MeV, Bi(214) emanates gamma rays at 1.764 MeV, and TI(208) emanates gamma rays at 2.614 MeV. These nuclides are of particular interest to the oil industry because all are found, in various amounts, in subsurface formations as constituents of potential reservoir rocks. Based on an extensive literature search and on recent field observations, a data compilation has been published to document potassium, uranium, and thorium distributions in various rock types. This discussion focuses on the use of gamma ray spectral logging to interpret the reservoir pore structure present in shales.
Until the past few years, the U.S. supply of natural gas has always exceeded demand. Enough natural gas was available from conventional reservoirs that it was neither necessary nor economic to develop low productivity reservoirs. The current situation in the U.S., however, necessitates that additional supplies of natural gas be developed to meet the nation's demand. Since 1974, advance in technology and improved economic incentives have resulted in a dramatic increase in the exploration and exploitation of tight gas basins.
Tight gas reservoirs are often termed as "unconventional" reservoirs. The exact definition of conventional and unconventional reservoirs is vague. In economic terms, a conventional reservoir is one in which a reasonable profit can be made at low gas prices and without requiring large volume stimulation prices and without requiring large volume stimulation treatments. Likewise, an unconventional reservoir can be described as one which requires the higher gas prices and large volume fracture treatments before a prices and large volume fracture treatments before a reasonable profit can be made.
In engineering terms, the best way to classify reservoirs is by permeability. Of course other factors are important, such as porosity, net gas pay and reservoir pressure; however, permeability is normally the dominant parameter when evaluating tight gas reservoirs. Considering the current gas price and the level of stimulation technology, it is the opinion of these authors that the "permeability cut-off" for conventional reservoirs is approximately 0.1 md. Normally, if the permeability is greater than 0.1 md, an undamaged well will recover 70-80 percent of the gas in place. When the permeability is about 0.01 md, large fracture treatments are required to recover 40-60 percent of the gas in place. In reservoirs where the permeability ranges from 1 to 5 microdarcies, large fracture treatments are required to recover about 10 to 30 percent of the gas in place. As mentioned above, other parameters such as reservoir pressure, well spacing porosity, etc will affect the pressure, well spacing porosity, etc will affect the recovery efficiency; however, in general terms, the recovery efficiencies given above are realistic.
Substantial quantities of natural gas exist in these unconventional, low permeability reservoirs. The location of the basins which contain a majority of these tight gas reservoirs have been known for many years. Most of these basins are found in the western portion of the U.S. Figure 1 illustrates the location of the most important basins.
Figure 1, was reproduced from a Department of Energy report which was published earlier this year. That report presented a comprehensive study concerning the "enhanced recovery of unconventional gas". Four sources of unconventional gas were considered:
(1) tight gas basins (2) The Devonian shale (3) geopressured aquifers (4) methane from coal seams
To determine the potential of each of these unconventional sources of gas, geologic data, engineering analyses and economics were combined to estimate the recoverable gas from each source.
A portion of that study - the tight gas basins and the Devonian shale - required the use of numerical reservoir simulation to predict well performance. A single phase, two dimensional, finite difference reservoir model was used for this purpose. The model has been described in an earlier publication.
The objectives of this paper are to present the techniques used to model each of these reservoirs and to demonstrate how computer history matching can be coupled with geologic information to develop a realistic interpretation of insitu reservoir conditions.
The first use of the numerical model in this study was to perform a sensitivity analysis using "typical" tight gas reservoir parameters. Computer runs were made to isolate the effects of formation permeability and fracture length upon recovery permeability and fracture length upon recovery efficiency for this average data set.
This paper was prepared for the 1972 Deep Drilling Symposium of the Society of Petroleum Engineers of AIME to be held in Amarillo, Tex., Sept. 11-12, 1972. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon requested to the Editor of the appropriate journal, provided agreement to give proper credit is made. provided agreement to give proper credit is made. Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers Office. Such discussions may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.
Abstract. The Delaware-Val Verde Basin is a marginal foreland basin genetically related to the Ouachita over-thrust belt and its associated subduction zone. Proximal structures to the overthrust belt evidence compressional folding and faulting indicative of a horizontal maximum principal stress, but the dominant principal stress of the principal stress, but the dominant principal stress of the more distal and productive structures is vertical. A similar tectonic style is evidenced for the Permian Basin as a whole. Isopachs indicate that structural growth began early and continued intermittently throughout the Paleozoic. The largest early structure is found in the Paleozoic. The largest early structure is found in the Puckett field in Pecos County, Texas. It has numerous Puckett field in Pecos County, Texas. It has numerous diameters and/or unconformities in the Ordovician-Silurian-Devonian interval and there was 1500' of closure by the time the Devonian was deposited. Other large structures such as the nearby Gomez field show minor early Paleozoic growth, and early structural trends are not Paleozoic growth, and early structural trends are not always concordant with later vertical uplifts. Maximum instability occurred during the Mississippian, Pennsylvanian and wolfcampian with concurrent uplift of producing structures and subsidence of the intervening grabens. This period of instability is coincident with the period of maximum activity along the Ouachita subduction zone. It is believed that thermal and isostatic activity related to the subduction zone caused this differential vertical uplift and subsidence. The stress system appears to be caused by fluid movements in the crust or subcrust. As lighter material was subduced to mantle depths there was some partial melting and diapiric rise of these lighter materials. The complete process is not fully understood. Rigid basement blocks were tilted and uplifted along basement faults. The overlying sediments behaved plastically and basement faults die out rapidly upwards plastically and basement faults die out rapidly upwards in the section. Faulting is rarely encountered in the bore hole but steep to overturned beds are common. Where minor faulting is encountered in the producing fields, it appears to have served as a conduit for rising hydrothermal fluids which cause some secondary cementation and loss of porosity and permeability. This has caused some well located wells structurally to be dry or non-commercial. The tectonic style of the Delaware-Val Verde basin is similar to that of many other foreland basins throughout the world. The Wyoming province of the Rocky Mountain foreland is a case in point. The largest producing fields in the world, Ghawar in Saudi Arabia, and producing fields in the world, Ghawar in Saudi Arabia, and Burgan in Kuwait, are differentially uplifted structures which occur on the Arabian foreland shelf in front of the Iranian subduction zone. The tectonic style of differential vertical uplift has been poorly understood in the past and, even today, is seldom mentioned in structural geology textbooks. Yet it is a most significant mode of deformation as regards the petroleum industry.