Weijermans, Peter-Jan (Neptune Energy Netherlands B.V.) | Huibregtse, Paul (Tellures Consult) | Arts, Rob (Neptune Energy Netherlands B.V.) | Benedictus, Tjirk (Neptune Energy Netherlands B.V.) | De Jong, Mat (Neptune Energy Netherlands B.V.) | Hazebelt, Wouter (Neptune Energy Netherlands B.V.) | Vernain-Perriot, Veronique (Neptune Energy Netherlands B.V.) | Van der Most, Michiel (Neptune Energy Netherlands B.V.)
The E17a-A gas field, located offshore The Netherlands in the Southern North Sea, started production in 2009 from Upper Carboniferous sandstones, initially from three wells. Since early production history of the field, the p/z plot extrapolation has consistently shown an apparent Gas Initially In Place (GIIP) which was more than 50% higher than the volumetric GIIP mapped. The origin of the pressure support (e.g. aquifer support, much higher GIIP than mapped) and overall behavior of the field were poorly understood.
An integrated modeling study was carried out to better understand the dynamics of this complex field, evaluate infill potential and optimize recovery. An initial history matching attempt with a simulation model based on a legacy static model highlighted the limitations of existing interpretations in terms of in-place volumes and connectivity. The structural interpretation of the field was revisited and a novel facies modeling methodology was developed. 3D training images, constructed from reservoir analogue and outcrop data integrated with deterministic reservoir body mapping, allowed successful application of Multi Point Statistics techniques to generate plausible reservoir body geometry, dimensions and connectivity.
Following a series of static-dynamic iterations, a satisfying history match was achieved which matches observed reservoir pressure data, flowing wellhead pressure data, water influx trends in the wells and RFT pressure profiles of two more recent production wells. The new facies modeling methodology, using outcrop analogue data as deterministic input, and a revised seismic interpretation were key improvements to the static model. Apart from resolving the magnitude of GIIP and aquifer pressure support, the reservoir characterization and simulation study provided valuable insights into the overall dynamics of the field – e.g. crossflows between compartments, water encroachment patterns and vertical communication. Based on the model a promising infill target was identified at an up-dip location in the west of the field which looked favorable in terms of increasing production and optimizing recovery. At the time of writing, the new well has just been drilled. Preliminary logging results of the well will be briefly discussed and compared to pre-drill predictions based on the results of the integrated reservoir characterization and simulation study.
The new facies modeling methodology presented is in principle applicable to a number of Carboniferous gas fields in the Southern North Sea. Application of this method can lead to improved understanding and optimized recovery. In addition, this case study demonstrates how truly integrated reservoir characterization and simulation can lead to a revision of an existing view of a field, improve understanding and unlock hidden potential.
Nugmanov, I. I. (Kazan (Volga Region) Federal University, RF, Kazan) | Starovoytov, A. V. (Kazan (Volga Region) Federal University, RF, Kazan) | Ziganshin, E. R. (Kazan (Volga Region) Federal University, RF, Kazan) | Kazakov, V. V. (Kazan (Volga Region) Federal University, RF, Kazan)
The PDF file of this paper is in Russian.
Article briefly describes results of experimental investigations of geomechanical properties for major lithogenetic types of carbonate rocks, constituting the typical sedimentary sequence for the Bashkirian stage of the middle Carboniferous. Feature of experimental work has been conducting laboratory tests on large-sized samples, close to a full-sized core rock (63 mm diameter, with height to diameter ratio in between 1:1 - 2:1). To account for anisotropy of elastic and strength properties for carbonates, sampling has been carried out in two orthogonal directions: along bedding and cross bedding. In absence of standard documentation to execution of researches for the samples of specified size, methodical sequence of laboratory experiments is offered, for receipt of maximum informativeness on mechanical and formation reservoir properties. Results showed significant difference for bioclast-zoogenic type I and type II limestones by physical and mechanical properties, but also on the character of development of deformation in zones weakness – shear fracture plane. Research methods and results include a few cutting-edge technical solutions in the context of "digital core". A result shows the efficacy of computed tomography to determine porosity. Using special algorithms for raw data processing of X-ray tomography allows to classify porous space by dimensions .Volumetric model with texture, carried out as a result of photogrammetry, applicable to highlight the natural fracturing of rocks. Correlation between p-wave propagation measurements in laboratory on core samples and derived from acoustic well logging has been noticed. As a rapid analysis method of the mechanical properties of carbonate rocks, authors recommends to use a Schmidt rebound hammer, as a cheaper and more affordable alternative to continuous profiling with a scratcher.
Представлены результаты экспериментальных исследований геомеханических свойств основных литогенетических типов карбонатных пород, составляющих характерный разрез отложений башкирского яруса среднего карбона Аканского месторождения. Особенностью экспериментальных работ являлось проведение лабораторных испытаний на образцах большого размера, приближенных к полноразмерному керну (диаметр - 63 мм, отношение высоты к диаметру от 1:1 до 2:1). Для учета анизотропии упругих и прочностных свойств отбор образцов осуществлен в двух ортогональных направлениях: по напластованию пород и вкрест. В отсутствие нормативной документации на проведение исследований для образцов указанного размера предложена методическая последовательность лабораторных экспериментов для получения максимальной информации о физико-механических и фильтрационно-емкостных свойствах. Установлено, что карбонатные породы разного литогенетического типа существенно различаются не только по физико-механическим свойствам, но и по характеру развития деформации в зонах потери прочности – трещинах сдвига. Методы исследования и результаты включают ряд новых технологических решений в контексте направления «цифровой керн». В статье показана эффективность применения компьютерной томографии для определения пористости. Использование специальных алгоритмов обработки исходных данных рентгеновской томографической съемки позволяет классифицировать пустотно-пористое пространство по геометрическим размерам. Трехмерные геометрические модели с текстурой, созданные при помощи фогограмметрической съемки, могут использоваться для выделения естественной трещиноватости горных пород. Установлена сходимость скоростей распространения продольной волны при лабораторных измерениях на образцах и по данным акустического каротажа. В качестве экспресс-оценки механических свойств карбонатных пород рекомендованы испытания склерометром вследствие их более низкой стоимости и большей доступности по сравнению с непрерывным профилированием скретчером.
Galiev, T. (Alrep) | Zelentsov, A. (Alrep) | Golitsina, E. (Alrep) | Khabibullin, R. (Alrep) | Nifontov, N. (Alrep) | Nurullin, A. M. (AO Tatnefteotdacha) | Gaynetdinov, R. F. (AO Tatnefteotdacha) | Burdin, K. (Schlumberger) | Starodubtseva, K. (Schlumberger) | Gromovenko, A. (Schlumberger) | Nuriakhmetov, R. (Schlumberger) | Kovalevsky, A. (Schlumberger) | Lisitsyn, A (Schlumberger)
The Bashkirian Formation within the Stepnoozerskoe oil field is represented by carbonate rocks with a complex geological structure characterized by high lateral and vertical heterogeneity. The reservoir temperature is about 23 deg C, the pressure does not exceed hydrostatic, the viscosity of oil in the reservoir conditions exceeds 200 cP, porosity and permeability of the reservoir vary widely.
In 2016, a pilot project to drill 2 multilateral wells on the Bashkir Formation was carried out; each well has 4 sidetracks (fishbones). Development of the reservoir with multilateral horizontal wells based on the simulation results allows to accelerate oil production, significantly improving the project economics, and the presence of horizontal sidetracks mitigates the risks associated with high lateral heterogeneity and ensures maximum contact of the wellbore with the reservoir.
To stimulate the inflow into the wells, it is necessary to conduct acid treatments. Two unique works were carried out in Russia with the use of a multilateral reentry system for detection and selective access into different boreholes. This system made it possible to orient and successfully enter the multilateral well with 4 open horizontal sidetracks for subsequent acid treatment. The treatment of the bottomhole zone was carried out with the help of self-diverting acidic compositions. In one of the wells, a buffer of hydrocarbon solvent, followed by steps of retarded hydrochloric acid injection and self-diverting acidic composition based on surface active agents was used. In another well, a dispersion of acid and solvent and a viscoelastic diverting acid on a polymer free base were used as a buffer.
In this paper, the authors describe the experience of stimulating multilateral horizontal wells and a comparative analysis of the results obtained.
Sinclair, Steven W. (Pioneer Natural Resources) | Crespo, Luis (Pioneer Natural Resources) | Waite, Lowell (Pioneer Natural Resources) | Smith, Kevin (Pioneer Natural Resources) | Leslie, Caitlin (Baylor University)
Any complete resource assessment of unconventional resources in a basin must include accurate delineation of marginal areas. In the northern Midland Basin, organic-rich Late Pennsylvanian/Early Leonardian mudrocks are bounded to the east, north, and west by predominantly shallow-water carbonate platform and reef deposits comprising the Eastern shelf and Glasscock Nose, Horseshoe Atoll, and Central Basin Platform. Allochthonous deep-water carbonate and siliciclastic gravity flow deposits derived from platform areas also limit hydrocarbon reserves as well as act as potential drilling hazards in certain areas. These bounding platform regions and associated deep-water flow deposits contain a complex structural and stratigraphic history that complicates resource assessment in marginal areas. A detailed mapping project of marginal regions of the northern Midland Basin utilizing available digital well logs closely tied to available 2D and 3D seismic data was therefore initiated in order to more accurately assess the resource potential of Late Pennsylvanian – Early Leonardian mudrocks of the basin.
Development of a sequence stratigraphic framework for the basin margins offers a framework that simplifies some complex basin margin relationships. Mapping and correlation of flooding surfaces, some of which correspond to existing Wolfcamp lithostratigraphic tops, and closely tying these stratigraphic surfaces to seismic response provides a more complete picture of the nature, timing, and extent of the “mid-Wolfcamp” unconformity in the Midland Basin. Seismic analysis combined with correlation of closely-spaced well logs indicates a complex history of the Glasscock Nose including periods of rapid progradation, mass wasting, erosion, and delivery of large quantities of clastic and carbonate material to slope and basin. The Central Basin Platform margin displays variable geometry in time and space but was generally aggradational during Penn-Wolfcamp time, sourcing extensive debris flows within the upper Wolfcamp interval. Seismic data augmented by well control shows clear evidence of both structurally- and stratigraphically- controlled thinning and truncation of upper Wolfcamp units along the western and eastern margins of the basin. Detailed isopaching of these units, together with mapping of carbonate percentage maps utilizing normalized gamma-ray log curves, greatly helps refine the assessment of total hydrocarbon resource in areas proximal to the shelves.
Ampomah, W. (Petroleum Recovery Research Center) | Balch, R. S. (Petroleum Recovery Research Center) | Cather, M. (Petroleum Recovery Research Center) | Rose-Coss, D. (Petroleum Recovery Research Center) | Gragg, E. (Petroleum Recovery Research Center)
This paper presents a numerical study of CO2 enhanced oil recovery (EOR) and storage in partially depleted reservoirs. A field-scale compositional reservoir flow model was developed for assessing the performance history of a CO2 flood and optimizing oil production and CO2 storage in the Farnsworth Field Unit (FWU), Ochiltree County, Texas.
A geocellular model was constructed from geophysical and geological data acquired at the site. The model aided in characterization of heterogeneities in the Pennsylvanian-aged Morrow sandstone reservoir. Seismic attributes illuminated previously unknown faults and structural elements within the field. A laboratory fluid analysis was tuned to an equation of state and subsequently used to predict the thermodynamic minimum miscible pressure (MMP). Datasets including net-to-gRose ratio, volume of shale, permeability, and burial history were used to model initial fault transmissibility based on the Sperivick model. An improved history match of primary and secondary recovery was performed to set the basis for a CO2 flood study. The performance of the current CO2 miscible flood patterns were subsequently calibrated to historical production and injection data. Several prediction models were constructed to study the effect of recycling, addition of wells and/or new patterns, water alternating gas (WAG) cycles and optimum amount of CO2 purchase on incremental oil production and CO2 storage in the FWU.
The history matching study successfully validated the presence of the previously-undetected faults within FWU that were seen in the seismic survey. The analysis of the various prediction scenarios showed that recycling a high percentage of produced gas, addition of new wells and a gradual reduction in CO2 purchase after several years of operation would be the best approach to ensure a high percentage of recoverable incremental oil and sequestration of anthropogenic CO2 within the Morrow reservoir.
While marine organic-rich mudstones (aka black shales) have been effectively described in recent years, developing depositional models has lagged. Without depositional models, predictability of facies and properties remains a major problem.
Sequence stratigraphy provides an answer. Sea level change controls sedimentation and circulation. Failure of masking sedimentation determines where marine black shales are expressed, and explains why they preferentially occur in carbonates and in the Paleozoic. In basinal organic-rich mudstones, which lack subaerial exposure surfaces, sequences can be identified by recognition of systematic variation in the rate of deposition. Episodicity and nondeposition are important considerations; and several different environments may be expressed within a black shale. But methods beyond simple observation of “unconformities” are necessary. Several parameters directly reflect rate of deposition, and together can be a powerful indicator of the depositional framework. Each comes from a different aspect of reduced sedimentation. The abundance of phosphatic fossil debris is a function of dilution by sedimentation. Illite crystallininty is a function of the length of time it is exposed to bottom water, regardless of oxidizing conditions. The relative abundances of organic matter type is a function of the length of time exposed to oxidizing conditions and the reciprocal rate of burial in reducing conditions. Other lines of evidence may also contribute to the model. While individually they may be ambiguous, the ability to correlate different signals from different processes reinforces the interpretation. The depositional model is testable against sequence models and against sequences recognized on adjacent shelves, constraining the intensity and frequency patterns of the sequences identified in the basin.
A sequence-based depositional model can help to identify lateral and vertical changes in rock properties within the basinal shales, particularly as they apply to distribution of organic matter type and content (which determine “sweet spots”), porosity, cements and bedding properties. Both actualistic and probabilistic models may be developed and may be helpful with risk analysis. While detailed analysis of every well is impractical, the application of models derived from key sections can greatly enhance predictability.
Samples from several cores from the late Pennsylvanian Cline Shale and an age equivalent unit have been examined to determine what pore systems are present. All mudrock samples have a mix of organic-matter, intraparticle, and interparticle pores. Development and mix of pore types varies greatly from sample to sample. However, overall the Cline Shale samples contain dominantly organic-matter pores. The most porous samples have the best developed organic-matter pores. The samples from the age-equivalent unit have few organic-matter pores and are dominated by intraparticle pores, to the extent that they have pores.
Problem and Objective
The nature and origin of pores in mudrocks are incompletely understood. Advances in technology have enhanced the direct imaging of mudrock pores (e.g. Loucks and others, 2009). The objective of this study was to characterize the pore systems (Loucks and others, 2012) of a set of samples from three cores in the late Pennsylvanian Cline Shale of the Midland Basin and one core in mudrocks that are age-equivalent to the Cline (Fig. 1).
The Cline Shale of the Midland Basin, west Texas is an organic-rich mudrock unit up to 450 feet thick (Roush, 2015) that is also referred to as the “Wolfcamp D” (McGlue and others, 2015). The unit has been explored for hydrocarbon production (Skaar, 2012, Jacobs, 2013). The Cline occupies a stratigraphic position above the Strawn and below the Wolfcamp (Fig. 2). A micropaleontological study of conodonts and foraminifera (Wahlman and others, in prep.) indicates that the unit is late Pennsylvanian in age. Roush (2015) proposed a stratigraphic division of the unit into a thin lower Cline member, overlain by thicker middle and upper members. Samples for BIB milling were obtained from four well cores (Fig. 1): the Amoco Bevers #1 well in Garza Co., the Gulf Glass B3 well in Martin Co., the Pan Am Powell #1 well in Glasscock Co., and the Pan Am O.L. Greer #2 well in Reagan Co. Three of these cores are in the Cline Shale itself, one of them (the Amoco Bevers #1) is in rocks age-equivalent to the Cline Shale from north of the Horseshoe Atoll (Fig. 1). Five BIB samples were taken from the Bevers #1 core. Six BIB samples were taken from the Glass B3 core, all from the Middle Cline. Five BIB samples were taken from the Powell #1 core, all from the Upper Cline. Three BIB samples were taken from the Greer #2 core, two of these are from the Upper Cline and one is from the Middle Cline. A lack of available core from the Lower Cline somewhat limited this study.
The Cline shale in the Midland Basin is an organic rich mudrock comprising the Cisco and Canyon Groups which has recently become an exploration target and production interval. The Cline is interpreted to have been deposited in a deep water environment by hemipelagic suspension and mass transport processes varying from debris flow to turbidity flow. Based on core description, thin section observation, and bulk compositional XRD data carried out on seven cores, seven lithofacies have been identified including various types of mudstone, carbonate and sandstone. Over 500 wireline logs were used to correlate and divide the stratigraphy of the Cline Interval. Regional stratigraphic sections show that the Cline dips towards the Central Basin Platform and ranges from 117 ft to 530 ft in thickness.
Gamma-ray log patterns can indicate sea level fluctuation and lithology stacking patterns by responding to clay content and organic matter. Two types of stratigraphic cycles are identified in the Cline Shale of the Midland Basin: shallowing-upward cycle and deepening-upward cycle, which are illustrated by two types of gamma-ray patterns: upward-increasing trend and upward-decreasing trend. Fifteen stratigraphic cycles have been distinguished from a typical basinal core, where eight are in the Lower Cline and seven are in the Upper Cline. These cycles are laterally continuous across the basinal area. More stratigraphic cycles can be recognized near the toe of slope, because not all depositional events extend across the basin floor. We infer from cyclicity correlation that high-frequency sea-level fluctuation and regional tectonism affected depositional processes on the platform and controlled sediment deposition in the basin.
The Cline shale is an unconventional resource play containing Type I, Type II and Type III kerogen. Total organic carbon (TOC) ranges from 0.13% to 9.88%. The Cline is currently at the oil window, and some areas have entered early condensate gas window. Lab-measured dry helium porosity averages at 5.75%. Massive argillaceous and siliceous mudstones contain relatively higher TOC and porosity and may act as both source rocks and reservoir rocks. These two facies are more prevalent and continuous in basinal areas within shallowing-upward cycles, providing indications for locations of potential pay zones.
The Grove field is located in the Southern North Sea and has been in production since 2007. The Grove A well lies within block 49/10a and was originally planned by Centrica as an infill well, drilled horizontally in the central fault compartment of the Grove field structure. The well targeted the relatively undepleted basal "A" sandstone unit of the Late Carboniferous, Westphalian reservoir, also known as the Barren Red Measures (BRM).
The well objectives were to 1) target the Grove A sand from the G1 "donor" well, 2) establish a suitable completion strategy for field development, 3) assess the performance of a multiple stage (four to five) hydraulically fractured horizontal well, 4) acquire sufficient log data to fully evaluate the reservoir, and 5) acquire reliable permeability and reservoir pressure measurements to assist in reservoir simulation.
The A sand reservoir unit has a porosity of approximately 10% and permeability between 0.05 to 1 md, with a reservoir with true vertical thickness (TVT) of approximately 140 ft at the heel and 40 ft at the toe. The reservoir unit is poorly drained by the other wells, and the Grove infill well is the first horizontal gas well in the field to be stimulated by means of multistage hydraulic proppant fracturing. The hydraulic fracturing treatment used sand plug isolation to separate consecutive fracture stages, and the fracture stimulation operations were performed with the rig in place by means of a converted stimulation vessel. The stimulation treatments successfully used a modified sand plug methodology that employed aggressive breaker schedules and fluid injections rates that were determined to be more efficient than previous treatments based on employing strict "sand plug setting" criteria. The findings are presented, as well as analyses of both prefracturing and fracturing data for the treatments together with results of the well post-completion and hook-up production.
This work should be of interest to offshore operators world-wide performing multiple hydraulic fractures in both horizontal and vertical wells using sand plug isolation technology.
Ross-Coss, D. (New Mexico Institute of Mining and Technology) | Ampomah, W. (New Mexico Institute of Mining and Technology) | Cather, M. (New Mexico Institute of Mining and Technology) | Balch, R. S. (New Mexico Institute of Mining and Technology) | Mozley, P. (New Mexico Institute of Mining and Technology) | Rasmussen, L. (New Mexico Institute of Mining and Technology)
This paper presents a field scale reservoir characterization for a late Pennsylvanian clastic reservoir at the Farnsworth Unit (FWU), located in the northeast Texas Panhandle on the northwest shelf of the Anadarko basin. The characterization is undertaken as part of a Phase III project conducted by the Southwest Regional Partnership on Carbon Sequestration (SWP). The target unit is the upper most Morrow sandstone bed (Morrow B Sand). Extensive data acquired from FWU was used to improve previously constructed static and dynamic models.
The Morrow B reservoir was deposited as fluvial low-stand to transgressive clastic fill within an incised valley. It is predominantly, subarkosic, brown to grey, upper medium to very coarse sands and fine gravels with sub-angular, to sub-rounded poorly sorted grains either planar to massively bedded. It was shown that primary depositional fabrics have less effect than post depositional diagenetic features do on reservoir performance, although subtle variations in deposition may have had some effect on later diagenetic pathways.
Three new wells were drilled for the purpose of field infilling and characterization. Cores and advanced wire-line logs from these wells were analyzed for stratigraphic context, sedimentological character and depositional setting in order to better predict porosity and permeability trends within the reservoir. Structural modeling was conducted through the integration of depth-converted 3D seismic data with well log data to create the framework stratigraphic intervals. This information, together with additional core, UBI image logs and an improved hydraulic flow unit methodology (HFU) was used to characterize and subsequently create a fine scale lithofacies based geological model of the field.
Core and log analysis allowed subdivision of the target interval into Hydraulic Flow Units (HFUs). The HFU approach enhanced core analysis and was used to elucidate porosity–permeability correlations. This methodology proved to be an exceptional approach to assigning permeability as a function of porosity during petrophysical modeling.
The integrated approach of combining seismic attributes with core calibrated facies and the HFU methodology was able to better constrain uncertainty within inter-well spacing and accurately quantify reservoir heterogeneity within FWU. The approach illustrated in this study presents an improved methodology in characterizing heterogeneous and complex reservoirs that can be applied to reservoirs with similar geological features.