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Saini, Dayanand (California State University, Bakersfield) | Wright, Jacob (California State University, Bakersfield) | Mantas, Megan (California State University, Bakersfield) | Gomes, Charles (California State University, Bakersfield)
A critical analysis of the key geological characteristics, completion techniques, and production behaviors of the Monterey Shale wells and their comparisons with analogous major US shale plays—namely, the Bakken and the Eagle Ford—may provide insights that could eventually help the petroleum industry unlock its full potential. The present study reports on such efforts.
The Monterey Shale is very young and geologically heterogeneous compared with the Eagle Ford and the Bakken. Oil viscosity in the Monterey Shale is significantly higher, and one can also notice that Monterey oil production has declined over the years. The Monterey Shale has a field-dependent completion strategy (pattern spacing and fracturing stage), while a horizontal, uncemented wellbore completion is common in the Bakken and the Eagle Ford. In the Monterey, nonhydraulically fractured zones of horizontal and hydraulically fractured wells appear to be making approximately equal contributions to the well’s cumulative production. The ongoing water-disposal operations in overlying injection zones, up to a certain extent, have affected the productivity of both types (long and short production histories) of wells. The geology also appears to have an effect on the production behaviors of horizontal and hydraulically fractured wells.
A preliminary economic analysis suggests that exploitation of the Monterey Shale is still a profitable venture. However, for sustainable development in a current price regime of USD 50/bbl of crude oil, it is necessary that production costs be reduced further. Also, compared with the Bakken and the Eagle Ford, the Monterey sits in regions of extremely high water stress (i.e., frequent occurrences of drought or drought-like conditions). However, oilfield-produced water associated with current steamflooding-based oil- and gas-production operations in the region as a base fluid suggests that it can potentially meet most of the water demand for future fracturing jobs. Also, combined use of a centralized water-management system; a less-costly, more energy-efficient, and high-capacity solar-powered desalination system; and a final sludge-management and/or residual-brine-disposal mechanism might assist the petroleum industry in managing flowback and produced waters while keeping water-handling costs low.
A combination of new enhanced-oil-recovery (EOR) methods for releasing the remaining oil from both nonfractured and fractured zones of horizontal wells and the use of oilfield-produced and recycled water for completing hydraulically fractured horizontal wells might prove to be a significant change for the future exploitation of California’s Monterey Shale resource, which is subject to the toughest hydraulic-fracturing regulations in the nation and is in a region of extremely high water stress.
A new workflow for fracture prediction and modelling based on geological time-step DFN has been used to better constrain the fracture distribution and timing of generation in the Motatan Domo Sur field of Venezuela. Using the Fault Response Modelling module in Move™, simulations of fracture generation under two tectonic transpressive events with SHmax of 280° and 310° were modeled to find the best-fit fracture forming event as compared with the observed data. These events are of Paleocene-Eocene and Miocene age, respectively. This workflow includes a DFN built from borehole images of five wells whose fracture properties are spatially modeled taken into account structural and petrophysical indicators of sub-surface fracture systems. A comparison between measured and modeled fractures is discussed to evaluate the influence of each tectonic event.
Modeling the location of discontinuities (faults and fractures) in the subsurface associated with a given tectonic event requires a geomechanical model, which incorporates stress boundary conditions and mechanical properties. In this paper, we outline a new workflow which allows fracture forming events to be simulated and used to predict fracture distributions across reservoirs; the results of these simulations can supplement petrophysical, geomechanical and subseismic indicators to produce more representative fracture models. This workflow is applied to the south dome of the Motatan reservoir, which is located in the tectonically complex Maracaibo basin of Venezuela.
This workflow consists of two phases: 1) the building of present day discrete fracture network (DFN) through the integration of petrophysical, geomechanical, structural and subseismic indicators of fracture systems (e.g. curvature and bore hole image data); and 2) the simulation of slip on faults, calculating the resulting strain field and comparing predicted fracture orientations for different tectonic events with the observed fractures. The combination of these two phases provides a better understanding of natural fracture systems and provides information about the development of reservoir fracture systems through time.
In shale development, picking optimum lateral landing points, and accurately predicting the height to which a hydraulic fracture will grow, requires knowledge of the vertical stress profile for both the target reservoir and the bounding layers. Stress profiles can be estimated using modern sonic logs in conjunction with geomechanical models but they require calibration with direct measurement of stresses from diagnostic testing, such as micro-fracture testing.
The organic-rich middle Miocene to lower Pliocene Monterey Formation is the main producing reservoir rock in the Southern California Offshore area. The most desirable reservoir rocks are the lower calcareous and massive chert zones due to the abundant presence of natural fractures which are necessary for these zones to be economically productive. The Antelope shale, the Monterey equivalent in the San Joaquin valley, may hold the same production potential. However, due to low permeability and less natural fracture density, the economic development of the Antelope shale will require stimulated completions.
This paper discusses the first case study on microfracture testing in the Antelope Shale. Results show that direct stress measurements can be successfully acquired at multiple intervals in a few hours and the vertical resolution nearly corresponds to log scale. Therefore, microfracture testing is an appropriate choice for calibrating log derived geomechanical models and obtaining a complete, accurate, and precise vertical stress profile. Further, these calibrated models helped to identify potential fracture boundaries across wellbore and evaluate fracture growth using 3D frac simulator. This resulted in optimized perforation and frac placement in multi-stage frac completion.
Microfracture tests were compared with leak off tests across adjacent wells to give more confidence in mud weight window for safe drilling. The closure stress calculated from calibrated sonic logs served as a yardstick for comparing with Leak off Test (LOT) and Formation Integrity Test (FIT) data. The closure stress along with corresponding formation pressure was used to adjust upper and lower boundaries of mud weight window for safe drilling. The case study demonstrates the effective integration of microfracture testing with sonic logs in the Antelope shale.
A large number of California's Central Valley, coastal, and offshore oilfields produce from the Miocene Monterey shale formation. Example oilfields with productive Monterey intervals include offshore and inland fields such as Hondo, Point Arguello, Lost Hills, Elk Hills, Belridge, and North Shafter/Rose. Example productive formation members that produce from the Monterey shale would include the Antelope Shale, McLure shale, McDonald Shale, and the Reef Ridge. The Monterey shale is both a reservoir and hydrocarbon source rock. There are large variations in reservoir properties and general interval behavior due to differences in the lithology, diagenetic state, mechanical properties, and the stress state. Generally the Monterey shale has a low matrix permeability of 0.01-1.0 md, but effective permeability can be higher due to natural fracture conductivity. Porosity spans a huge range - from as low at 10% to as high as 70%.
One illustrative example is in Southeast Lost Hills, where vertical wells are drilled and hydraulically fractured to target thick Opal-CT and the deeper cherty/quartz-phase Monterey pay intervals. The design and placement of multiple fracture treatment stages with appropriate conductivity and half-length is a requirement for a successful field development. In contrast, offshore Monterey developments have usually targeted intersecting the conductive natural fracture network in quartz-phase intervals. For this flavor of the Monterey, an acid job can effectively stimulate production by removing the drilling/completion damage and dissolving the calcite filling in natural fractures.
A significant thickness of Monterey siliceous shale is present across a large area in California. The oil industry has learned much from unconventional shale reservoir development elsewhere in the country. Is it possible that Monterey siliceous shale will be transformed into the California version of an ‘unconventional' shale resource? The key will be to identify the Monterey intervals with the most potential, and apply the proper development drilling and completion strategy, with changes made to accommodate the low-mobility multiphase liquid flow. General Monterey development challenges include: a) defining the structure, b) identifying the target pay intervals within the thick depositional intervals, c) understanding the lithology and the reservoir / rock properties of the different pay zones, d) understanding and designing the optimum stimulation treatment(s) and e) determining the optimum well development pattern and completion strategy to incorporate all the above requirements. Is there a "silver bullet?? strategy that will enable success in the pervasive Monterey siliceous shale? The purpose of this paper is to stimulate industry thought and discussion.
The diatomite reservoirs in the Belridge giant oil field in the southern San Joaquin Valley of California provide an ideal location for following the growth in understanding and application of horizontal wells through time. Details are presented that cover geology, drilling, completion, and production from four projects totaling 230 of the field's 246 hydraulically stimulated horizontal wells drilled transverse, longitudinal, and oblique to the azimuth of the preferred natural fracture plane.
The diatomite reservoirs are layered biogenic silica deposited in the Miocene Monterey and Reef Ridge formations. They have continuous vertical oil columns ranging up to 1,300 ft (400 m) along the crest of the anticline. However, the permeability is 0.1 to 10 millidarcies which requires all producers to have multiple sand-propped hydraulic fractures to produce at economic rates. Tight spacing and accurate fracture placement are essential to recovering reserves in this massive reservoir. Normal field development is via closely-spaced vertical producers with vertical water injectors for pressure support. However, when pay zones thin-out on the flanks or become less vertically continuous, horizontal wells become the preferred method of development.
Each of the four projects targeted different areas of the field, and had wells drilled in different geomechanical stress regimes. The largest project has 188 horizontal wells completed with multiple longitudinal hydraulic fractures: after an initial pilot study of four wells, Phase 1 consisted of 75 ft (23 m) spacing between the horizontal sections of the wellbores; Phase 2 evaluated and developed 50 ft (15 m) spacing in a less prospective area; and Phase 3 consisted of infill drilling at 37.5 ft (11.5 m) spacing in the Phase 1 area while at the same time converting every fourth horizontal producer to a water injector.
The unconventional petrophysical properties of the diatomite and the variety of stress regimes allow an almost textbook-like look into knowledge capture plus the utilization of successes and learnings for subsequent projects. From first attempts in 1995 to the current ultra-tight spacing, the learnings from this case study are readily applicable to many other fields, especially to shale reservoirs in resource plays, where tight spacing of the hydraulic fractures and a manufacturing assembly-line approach to development may be needed to get hydrocarbons efficiently out of the matrix.
Dang, Cuong Thanh Quy (HCMC University of Technology) | Nguyen, Ngoc Thi Bich (Sejong University) | Bae, Wisup (Sejong University-Korea) | Jung, Byounghi (Ministry of Knowledge Economy) | Lee, Jeonghwan (Korea Gas Corp.)
Natural fractured petroleum reservoirs represent over 20% of the world's oil and gas reserves. It plays an obvious role in oil exploration and makes a large contribution toward oil and gas production worldwide. The research tendency for natural fractured reservoir NFR has become more apparent in the last five to ten years because more fractured reservoirs are being developed as production from conventional reservoirs is declining. However, characterization of fractured reservoir is complex and presents unique challenges in comparison with conventional reservoir. There are several uncertainties in NFR characterization in exploration and field development strategies, especially in the early stages when little or even no data is available. Thus, it is urgent and necessary to collect the experiences from previous successful research to reduce risky level in such reservoir.
White Tiger is the biggest fractured basement reservoir up to now on the continental shelf of Viet Nam This reservoir has a complicated geological structure, very high heterogeneity, high temperature (more than 2750F) and closure stress (more than 8,000 psi); the collector model is quite different from that of conventional oil reservoirs in sediments rocks. The total OIIP of this field reached nearly 4 billions barells with 2000 meters of the oil bearing thickness and has been produced by more than 100 wells, tens of which flow at the rate of approximately one thousand barrels per day. Thus White Tiger has become one of the rarest oil fields worldwide. A huge volume of science researches has been done with great success. Many specify software, and calculation models, simulation geophysics and seismic interpretation have been successfully studied and applied to the basement reservoir. Based on experiences from White Tiger, a significant number of other oil fields in the fractured basement were discovered such as Rang Dong, Phuong Dong, Ruby, series of Black Lion, Yellow Lion, Brown Lion, Yellow Tuna, Southern Dragon and Turtle. The discovery of the oil reservoir in White Tiger fractured basement has changed the concept of oil and gas prospecting, exploration and development in Viet Nam and the region, being a considerable contribution to the world's oil and gas science.
This paper reviews significant events in geological development and achievements in improved oil recovery by special methods for fractured granite basement reservoirs such as slant directional drilling, acid formation treatment, hydraulic fracturing of formation, polymer and surfactant flooding etc. With rich experience in exploration and production of hydrocarbon in fractured granite basement rocks over the past 20 years, it is worthy case study for both current and future development planning of NFR in the world.
The continental shelf of Viet Nam was undergone many deformation stages. Since then, some basins were formed in which oil was accumulated in both sedimentary and granite basement rock reservoirs. Figure 1 shows the distribution of basins in the Viet Nam continental shelf and field location of Cuu Long basin. Authors mainly study a basement rock reservoir in Cuu Long basin, especially White Tiger and Dragon oil field which was produced with the huge oil amount.
This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 116007, "Development and Use of High-Density Fracturing Fluid in Deep Water Gulf of Mexico Frac and Packs," by L. Rivas, SPE, G. Navaira, SPE, and B. Bourgeois, SPE, Chevron, and B. Waltman, SPE, P. Lord, SPE, and T. Goosen, SPE, Halliburton, originally prepared for the 2008 SPE Annual Technical Conference and Exhibition, Denver, 21-24 December. The paper has not been peer reviewed.
There has been an increase in the number of wells drilled to depths greater than 20,000 ft in the Gulf of Mexico (GOM). Because of the high fracture gradient and friction in the wellbore tubulars, a conventional 1.0- to 1.04-specific-gravity (SG) fracturing fluid would require surface treating pressures greater than 15,000 psi, which exceeds the limit of the flexible treatment line. To solve this problem, a borate-crosslinked high-density fracturing (HDF) fluid with SG of up to 1.38 was developed to reduce the amount of surface treating pressure required to achieve adequate bottomhole fracturing pressure.
The Tahiti field is in the GOM in the Green Canyon area where water depths range from 4,000 to 4,300 ft. The discovery well was drilled in 2002. Total depth was more than 28,000 ft. Initial evaluation indicated approximately 400 ft of net pay in the high-quality reservoir sand that was encountered. Subsequent appraisal drilling over the next 2 years resulted in confirmation of the size of the Tahiti field and its status as one of the most significant net-pay accumulations ever discovered in the GOM. The discovery well was re-entered in 2004, and a well test was performed to verify deliverability, dynamic well data, and reservoir properties. A stacked frac pack in the Miocene M21A and M21B sands was planned for the well test. The Tahiti M21A sand averages 60 to 80 ft thick, and the M21B sand averages 120 to 150 ft thick. Permeability ranges from 600 to 800 md. The decision was made to complete both intervals with a single, high-rate frac pack. At the time, at a depth in excess of 25,800 ft, it was the deepest successful well test and frac-pack completion ever carried out in the GOM. The HDF fluid was a key component of the successful Tahiti well test. The well-test results led to the development of the Tahiti field, which began in February 2006.While planning the Tahiti well test, several factors influenced the decision to develop a suitable HDF fluid that would minimize surface treating pressures and allow the fracture job to be pumped at pressures below the 14,000-psi limit. Uncertainty regarding Miocene-pay-sand fracture gradients, and required treating rates, coupled with high friction losses in the treating string led to the desire to find an HDF fluid that would allow the fractures to be pumped at 40 to 45 bbl/min while staying within surface-treating-pressure limitations.
Inikori, Solomon O. (Shell Intl. E&P Inc.) | Spring, Laurent Yann (Shell Intl. E&P Co.) | Ageh, Ebenezer (Shell Nigeria E & P, Co.) | Van der Bok, Jaap W. (Shell Nigeria Exploration and Production Company)
Bonga field in deepwater Nigeria produces hydrocarbons from classic deepwater turbidites reservoirs in channel settings. The reservoirs consist of series of amalgamated channel complexes with varying degrees of compartmentalization. This configuration presents significant uncertainties in connected volumes, well placements and sweep efficiency between water injector/producer well pairs. However, due to the high costs of deepwater developments, well count needs to be as low as practical, and production rates must be sustainably high to ensure economic robustness of the project. High rates and high ultimate recoveries are the foundations of successful deepwater projects, where constant pressure maintenance is a key component. Several research studies conducted recommended that water injection wells be designed for fractured injection in order to sustain the required high rates as opposed to matrix injection. This paper presents the results of these research efforts leading to this conclusion and the implications on reservoir management.
Also presented is an overview of the challenges of developing these complex channel deposits as well as the new approach to modeling of high rate wells in deepwater turbidites.
Key to a successful understanding of reservoir behaviour (connectivity) and early indications of future reservoir performance is through a systematic undertaking of interference tests at production start-up.
After about 2 years of production, the results from the Bonga wells demonstrate that sustained high oil rates could be achieved with adequate pressure maintenance. Average oil production rates of vertical/deviated wells range between 15,000 to 22,000 bopd and that of horizontal wells range between 25,000 to 35,000 bopd. Estimated Ultimate recovery (EUR) range from 20 to 100 mmstb for phase 1wells and from 10 to 30 mmstb for phase 11 development wells with several opportunities for infill drilling of low EUR wells. Nameplate capacity of 225,000 bopd is achieved and sustained with just 9 producers and 6 injectors. In order to maintain reservoir pressures from these high uplift rates, world-class water injection rates of between 40,000 to 70,000 bbls per day per well have been sustained since first oil.
The fracture injection approach is applicable both for onshore and offshore reservoir development but more significantly for deepwater reservoir development where sustained high rates and economic considerations are paramount.
The Bonga development consists of four major Lower to Upper Miocene turbidite reservoirs (A, B, C & D) with varying degrees of amalgamation.. The Bonga reservoirs lie on the western flank of the shale-induced Bonga Main structure and are stratigraphically/structurally trapped in mud-rich, unconfined turbidite systems in mid-lower slope setting. The reservoirs consist of highly unconsolidated fine-grained turbidites with core permeabilities ranging from 200 to over 5,000 mD. Pre-first oil production test interpretation results suggested permeabilities in the 2,000-7,000 mD range, and production indices (PI) in the 70-140 bbls/day/psi range for vertical/deviated wells and over 350 bb/d/ay/psi range for horizontal wells. The reservoirs are mainly hydrostatic to slightly over-pressured, with undersaturation (reservoir to bubble point pressure) spreads of 500-2,000 psi, requiring water injection for pressure maintenance from day one. Table 1.0 shows typical rock and fluid properties of the reservoirs. Consequently, achieving high oil production rates was not a challenge in this field. The challenges, however, were:
Item 2 was handled by effective sand control measures requiring Frac and Pack (F&P) for vertical/deviated wells and Open-Hole Gravel Pack (OHGP) for high angle/horizontal wells with adequate wellbore integrity modeling. PI reduction of over 25 bbls/day/psi in vertical/deviated wells and over 150 bbls/day/psi for horizontal wells at production start-up.
Leshchyshyn, T.H. (BJ Services Canada) | Beadall, K.K. (Strategy Consultant) | Meier, P.E. (ConocoPhillips Canada) | Hagel, M.W. (Optimus International Technologies) | Meyer, B.R. (Meyer & Associates, Inc.)
Rock tables giving values for fracture closure gradient, Young's modulus, and Poisson's ratio have been developed by the authors using lithologies determined from well logs, cores and mud logs, and substantiated by numerous mini-fracs. Log curves are layered and analyzed for lithological intervals as thin as one foot. The various rock types are arranged in the table as a function of increasing closure gradient, giving a basic order of sandstone, siltstone, claystone, shale, and the group limestone-calcite-pyrite-anhydrite, dolomite and coal, all below the weight of overburden. Included in the tabulation are mixtures of the various lithologies derived in similar manner from formation logs. An example would be a carbonaceous-limy-sandy-shale having a closure gradient of 0.93 psi/ft (21 kPa/m), a Young's modulus of 2.18×106 psi (1.5×107 kPa), and a Poisson's ratio of 0.33. By comparison, clean sandstone has a closure gradient of 0.66 psi/ft (15 kPa/m), a Young's modulus of 3.33×106 psi (2.3×107 kPa), and a Poisson's ratio of 0.23. Over seventy identifiable lithologies or lithology-mixtures are listed in the table. All values were developed through a combination of rules-of-thumb and interpolation. This empirical data set is analogous to a seven-component, programmed log evaluation. A normal log analysis done manually will yield about fifty layers of rock with distinct compositions per fracture height equivalent to 100-165 ft (30-50 m) of depth. Layer-specific formation characteristics are then assigned to a fracture model for deriving initial shut-in pressure (ISIP) and closure. Next, the calculated results are compared to actual mini-frac data. If corresponding values show little similarity, then there exists some stress difference from normal behavior in the reservoir under study, the most common cause being pressure depletion. Variance is also attributed to such factors as dilation around the wellbore (cracks in the rock), tectonic strain, compressibility changes, density increase from silica diagenesis, and reservoir gas over-pressurization observed in mountainous regions of North America. In-situ stresses can be adjusted to properly model these particular situations. A separate set of rock tables was compiled for southern California siliceous formations where Young's modulus for diagenetically-altered diatomaceous rock ranges from 0.2×106 psi (0.14×107 kPa) to 1.0×106 psi (0.69×107 kPa). Unconverted diatomite, a regional lithology susceptible to depletion-induced compaction, exhibits a Young's modulus as low as 0.04×106 psi (0.028×107 kPa). Diagenetic sequences such as siliceous shale and porcelanite require special application of the California Rock Tables for depths to 8,000 feet (2,440 m), after which the standard Canadian Rock Tables for post-Precambrian formations can be employed.
Weijers, L. (Pinnacle Technologies) | Griffin, L.G. (Pinnacle Technologies) | Sugiyama, H. (Teikoku Oil Company) | Shimamoto, T. (Teikoku Oil Company) | Takada, S. (Teikoku Oil Company) | Chong, K.K. (Halliburton) | Terracina, J.M. (Halliburton) | McDaniel, B.W. (Halliburton) | Wright, C.A. (Pinnacle Technologies)
In the summer of 2001, the first multi-stage completion in a deep, hot, and naturally fractured volcanic rock of the Minami-Nagaoka Field, Niigata Prefecture, Japan, was successfully completed using six propped fracture treatment stages.
Successful proppant placement in the northern part of the Minami-Nagaoka Field in Japan has proved to be extremely difficult in the past 1-2. During two propped fracture treatments pumped more than a decade ago, treatments failed miserably with only about 20% of the designed proppant placed before job termination due to premature screen-outs. Post-frac evaluation showed extremely high levels of net pressure of order 4000 psi prior to pumping any proppant - indicating that proppant placement problems were mainly occurred due to simultaneous propagation of very narrow multiple hydraulic fractures. Detailed pressure build-up tests and production data analysis confirmed the diagnosis of narrow multiple hydraulic fractures, which resulted in extremely poor propped fracture conductivity and non-economic gas production.
As successful development of the northern part of the Minami-Nagaoka reservoir could significantly impact Japan's domestic natural gas production, another attempt at propped fracture stimulation was justified. In the summer of 2001, the first multi-stage completion in a deep, hot, and naturally fractured volcanic rock of the Minami-Nagaoka Field was successfully completed using six propped fracture treatment stages. The new treatments in Minami-Nagaoka focused on the ability to mitigate the adverse effects of multiple hydraulic fracture propagation and the accompanying severe near-wellbore fracture tortuosity. A major equipment mobilization was required for this treatment to be possible as part of this concerted effort. Many unconventional changes, including completion changes to obtain highest possible injection rates to enhance proppant placement, aggressive proppant slug strategy, extensive fluid testing, real-time fracture treatment analysis, careful perforation placement, quality control, extreme overbalance perforating, and use of small-grained proppant, resulted in successful stimulation and favorable production response. This paper discusses all these design changes in detail, and provides final results regarding the fracture geometries obtained and post-fracture production response.
Deep-seated volcanic rocks of the Middle Miocene Age form a gas reservoir (Minami-Nagaoka gas field) onshore Japan. The reservoir has a total thickness of more than 2,600 ft present at depths from 12,500 ft to over 16,000 ft, with an initial reservoir pressure of 8,100 psi and temperature of 350°F. As a consequence of repeated volcanisms, rhyolite eruptions were deposited one after another forming a thick formation with a rapid change of rock facies, divided into hyaloclastite, lava, and pillow breccia. Large scale natural fractures are developed in lava and pillow breccia facies.
In the Minami-Nagaoka gas field, which provides about 25% of Japan's domestic natural gas production, there are 17 wells completed, and 12 of them are producing. The remaining five wells are poor in productivity and have, therefore, not been put on production. It is believed that the matrix permeability is too low to deliver sufficient production and the productivity depends on the natural fracture system.