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.
Albertini, Cristian (Eni Spa) | Bigoni, Francesco (Eni Spa) | Francesconi, Arrigo (Eni Spa) | Lazzeri, Riccardo (Eni Spa) | Vercellino, Alberto (Eni Spa) | Borromeo, Ornella (Eni Spa) | Gabellone, Tatyana (Eni Spa) | Consonni, Alberto (Eni Spa) | Geloni, Claudio (Eni Spa)
The reservoir quality of Karachaganak Carbonates Field results significantly affected by diagenetic processes. In particular, the replacive dolomitization affects porosity, permeability and irreducible water saturation while the precipitation of anhydrite reduces both porosity and permeability. Such impacting processes were therefore analysed and described in the reservoir 3D Model following geologically consistent rules that honour well data.
The field scale diagenetic study was performed following five steps:
Core data studies Lithological logs analysis Hydrological processes identification Hydrological processes reactive transport simulations 3D Lithological model building
Core data studies
Lithological logs analysis
Hydrological processes identification
Hydrological processes reactive transport simulations
3D Lithological model building
The dolomite distribution, estimated from the lithological log analysis and cores data, results mainly confined on the flanks of the paleo-high. This distribution was endorsed by the results of 3D field scale reactive transport modelling related to Kohout geothermal convection mechanism acting in the shallow burial of the carbonate paleo-high at each stratigraphic unit. The final lithological 3D Model was built consistently with this hydrological process calibrated with well data used as verification data set in the stochastic simulations.
The anhydrite distribution, estimated from lithological log analysis and cores data, is, generally, present in a few percentage of volume and, mainly, in the upper section of the reservoir (less than 250 m, below the bottom of the overlaying Kungurian evaporites). This anhydrite was related to diffuse downward percolation of the Kungurian brine and, marginally, to dolomitization. The occurrence of higher concentration of anhydrite was also locally observed but generally connected to fracture infill and, sometimes, also in the deeper section of the reservoir. These events were related to brine percolation exploiting a network of syn-depositional fractures, particularly along the flanks of the carbonate bank (Neptunian dykes). Such hydrological processes was endorsed by 2D reactive transport modelling. In fact, the anhydrite infilling fractures may have a significant impact on the reservoir flow path and therefore a workflow for identification of these Neptunian dykes was applied, based on seismic attributes (Continuity and Curvatures) according to the Eni proprietary workflow utilized for the identification of sub-seismic discontinuities (Tfrac-Sibilla).
The so estimated dolomite distribution represents about the 15% of the lithology at field scale but up to the 60% on the flanks of the carbonate build-up, marginal areas investigated by very few wells but impacting on about the 30% of the field total GBV. Accordingly, the petrophysical characteristics of the field flanks result affected, in the 3D Reservoir Model, by the presence of dolomite, i.e. increased porosity, permeability and irreducible water saturation. Moreover, the identification of the sub-seismic discontinuities filled by anhydrite allows a better description of the permeability baffles affecting the 3D model flow paths.
Case studies can be instructive in the evaluation of other coalbed methane (CBM) development opportunities. The San Juan basin, located in New Mexico and Colorado in the southwestern U.S. (Figure 1), is the most prolific CBM basin in the world. It produces more than 2.5 Bscf/D from coals of the Cretaceous Fruitland formation, which is estimated to contain 43 to 49 Tscf of CBM in place. For a long time, the Fruitland formation coals were recognized only as a source of gas for adjacent sandstones. In the 1970s, after years of encountering gas kicks in these coals, operators recognized that the coal seams themselves were capable of commercial gas rates. CBM development benefited greatly from drilling and log data compiled from previous wells targeting the deeper sandstones and an extensive pipeline infrastructure that was built to transport conventional gas. These components, along with a U.S. federal tax credit and the development of new technologies such as openhole-cavity completions, fueled a drilling boom that resulted in more than 3,000 producing CBM wells by the end of 1992. The thickest Fruitland coals occur in a northwest/southeast trending belt located in the northeastern third of the basin. Total coal thickness in this belt locally exceeds 100 ft and individual coal seams can be more than 30 ft thick. The coals originated in peat swamps located landward (southwest) of northwest/southeast trending shoreline sandstones of the underlying Pictured Cliffs formation. The location of the thickest coals (Figure 1) coincides with the occurrence of overpressuring, high gas content, high coal rank, and high permeabilities in the San Juan fairway ("fairway"). The overpressuring is artesian in origin and is caused by water recharge of the coals through outcrops along the northern margin of the basin. This generates high vertical pressure gradients, ranging from 0.44 to 0.63 psi/ft, which allow a large amount of gas to be sorbed to the coal. Coal gas in the San Juan basin can contain up to 9.4% CO2 and 13.5% C2 . Chemical analyses suggest that thermogenic gases have been augmented by migrated thermogenic and secondary biogenic gas sources, resulting in gas contents ranging up to 700 ft 3 /ton. Coal rank in the fairway ranges from medium- to low-volatile bituminous and roughly coincides with those portions of the basin that were most deeply buried. Coals in the fairway typically have low ash and high vitrinite contents, resulting in large gas storage capacities and excellent permeabilities of 10 md from well-developed cleat systems.
Anderson, Iain (Heriot-Watt University) | Ma, Jingsheng (Heriot-Watt University) | Wu, Xiaoyang (British Geological Survey) | Stow, Dorrik (Heriot-Watt University) | Underhill, John R. (Heriot-Watt University)
This work forms part of a study addressing the multi-scale heterogeneous and anisotropic rock properties of the Lower Carboniferous (Mississippian) Bowland Shale; the UK's most prospective shale-gas play. The specific focus of this work is to determine the geomechanical variability within the Preese Hall exploration well and, following a consideration of structural features in the basin, to consider the optimal position of productive zones for hydraulic fracturing. Positioning long-reach horizontal wells is key to the economic extraction of gas, but their placement requires an accurate understanding of the local geology, stress regime and structure. This is of importance in the case of the Bowland Shale because of several syn- and post-depositional tectonic events that have resulted in multi-scale and anisotropic variations in rock properties. Seismic, well and core data from the UK's first dedicated shale-gas exploration programme in northwest England have all been utilized for this study. Our workflow involves; (1) summarizing the structural elements of the Bowland Basin and framing the challenges these may pose to shale-gas drilling; (2) making mineralogical and textural-based observations using cores and wireline logs to generate mineralogy logs and then to calculate a mineral-based brittleness index along the well; (3) developing a geomechanical model using slowness logs to determine the breakdown stress along the well; (4) placing horizontal wells guided by the mineral-based brittleness index and breakdown stress. Our interpretations demonstrate that the study area is affected by the buried extension of the Ribblesdale Fold Belt that causes structural complexity that may restrict whether long-reaching horizontal wells can be confidently drilled. However, given the thickness of the Bowland Shale, a strategy of production by multiple, stacked lateral wells has been proposed. The mineralogical and geomechanical modelling presented herein suggests that several sites retain favorable properties for hydraulic fracturing. Two landing zones within the Upper Bowland Shale alone are suggested based on this work, but further investigation is required to assess the impact of small-scale elastic property variations in the shale to assess potential for well interference and optimizing well placement.
The development of unconventional reservoirs require key decisions to be made under uncertainty. We regularly consider multiple variables, such as the number of wells to be placed in a section, their horizontal spacing and vertical staggering, the length and orientation of the laterals, the design of fracturing stages and associated perforations, the quantity and type of fracturing fluid and proppant to use, and geologic variability. These decisions are dependent on the subsurface parameters at each development due to the heterogeneities of rock and fluid properties as well as the nearby historical development. Such complex and dynamic problems combined with the fast pace and large scale of unconventional development pose a significant challenge for classical physics-based reservoir models. We propose a data-driven modeling methodology that is used to support development decisions in the STACK play in Oklahoma.
We utilize multi-variate analytics to model the behaviors of horizontal wells in the STACK (Sooner-Trend-Anadarko-Canadian-Kingfisher) of the Anadarko basin (see Fig. 1 for idealized geologic cross section). The STACK consists of two primary targets, the Meramec shale and the Woodford shale. The Mississippian age Meramec is 200-500’ thick with porosity ranging from 3-6%.The Mississippian/Devonian age Woodford ranges from 75-300’ thick with 3-7% porosity. The Meramec formation consists of several parasequences of fine-grained silts with significant carbonate input in some intervals. Our analysis includes over 500 horizontal wells that target the core intervals in the Meramec. We use these wells in our workflow that predict their production performance impact with respect to both the location of horizontal wells in the STACK trend and multiple engineering variables.
In unconventional resource plays, wells drilled and completed in the same area, within the same target and with the same completions can have results that vary by +/− 50% vs the mean. Without a predictive model to explain this variance, production variability looks like random noise. We chose to use a simple statistical technique called a hypothesis test, and interpret the result using a p-value, a measure of statistical significance. Using the p-value, a trend can be tested to see if the trend in a sample of data is statistically different than the trend that would be expected from a random sample. Several studies have been published on multivariate analytic workflows1,2,3,4.
The Devonian-Mississippian STACK/SCOOP Play of the Oklahoma Anadarko Basin is a complex assemblage of tight carbonate and siliciclastic strata and an important oil and gas province. In the last decade, prolific drilling has demonstrated significant heterogeneity in the composition of oils produced from STACK/SCOOP reservoirs. This study discusses possible geoscientific explanations for the heterogeneity observed in produced oils and describes how source, maturation, and migration affect their composition.
Geochemical data from 136 produced oils across 12 counties from 4 producing reservoirs is reviewed. Calculated thermal maturity (Rc%) from alkylated polyaromatic compounds shows excellent agreement with oil thermal maturity increasing with increased depth. Oils produced from overpressured reservoirs exhibit a strong relationship between Rc% and Gas-Oil Ratio (GOR), while normal- to underpressured reservoirs exhibit GORs up to an order of magnitude higher at similar Rc%. Light hydrocarbons show that paraffinicity varies starkly with producing reservoir, suggesting compositional fractionation from diffusive migration through tight and argillaceous strata. Conversely, aromaticity varies geographically by Play Region, indicative of changing depositional environments and organic input across the basin. Isoprenoid and sesquiterpane biomarkers indicate all oils are generated by Type II or Type II/III mixed organic matter, but Springer Group reservoirs are charged by a highly argillaceous, non-Woodford source.
The Anadarko Basin is the deepest sedimentary basin in the cratonic interior of the North America with as much as 40,000 feet of Paleozoic sediments (Johnson, 1989). The Anadarko is an asymmetric basin with the deepest sediments bound against the Amarillo-Wichita Uplift to the southwest. The basin is elongated along its west-northwest axis and bound by the Nemaha Ridge to the east and the Anadarko shelf to the west and north.
In the last decade, drilling of Devonian-Mississippian strata along the margins of the basin have delineated one the continent's most successful petroleum resource plays. These areas are colloquially referred to as the
The Bowland Shale is a Carboniferous formation of Asbian to Yeadonian age located in Northern England. It is estimated to have a shale gas section with more than 5,000 ft thickness holding over 1300 TCF of total original gas in place. Drilling in the Bowland Basin started in August 2010 and by the end of 2011, three vertical wells (PH-1, GH-1 and BS-1) were drilled to a depth of 8,860 to 10,500 ft with objective of logging and coring the potential shale gas formations including Upper Bowland, Lower Bowland, Hodder Mudstone and Sabden Shale. All the drilled wells encountered several borehole stability problems, such as tight-hole, pack-off, overpull and excessive cutting, causing significant non-productive time (NPT) during drilling. Specifically, in GH-1 and BS-1, side-tracking was required to reach the target depth which imposed significant cost to the project. Careful investigation of the recorded drilling problems showed that majority of them were associated with formation collapse due to insufficient drilling fluid pressure. Fluid losses also occurred in some of the formations due to either too high of downhole pressure or presence of critically stressed natural fractures. These incidents implied that the applied casing design and mud weight program were not appropriate for the current-day state of stress and rock properties.
A comprehensive experimental and analytical geomechanical study was carried out to develop a reliable borehole stability model that can firstly explain the observed drilling incidents and secondly provide guidance for design and drilling of the planned wells. The plan was to drill a S-shape appraisal well (PNR-1) in the Preston New Road exploration site to log and core the Bowland Shale sequence and select the optimum landing depths for subsequent horizontal sections (PNR-1z and PNR2) to be completed for multi-stage hydraulic fracturing. The study recognized intrinsic shale anisotropy as a primary causative factor for borehole stability issues and formation collapses in the offset wells. Other important factors were identified to be the abnormal pore pressure regime and the presence of a tectonic strike-slip stress regime with large horizontal stress anisotropy. The anisotropy of the Bowland Shale was characterized in both laboratory and field scales, and anisotropic wellbore stability models were developed for offset and planned wells. As a result of this study, the PNR-1, PNR-1z and PNR2 wells were successfully drilled and completed with no notable borehole stability problems despite the presence of narrow operating mud weight window in several stratigraphic intervals. This paper presents a summary of the conducted borehole stability analysis aiming at risk-free and successful drilling of horizontal wells in the Preston New Road exploration site with emphasis on the effect of shale anisotropy.
This paper presents detailed lithofacies identification from the I-35 Sycamore outcrop and predicts the rock properties from wireline logs to propose landing zones within the Mississippian Sycamore rocks in Southern Oklahoma. To achieve these objectives, three types of studies were conducted: (a) field studies (b) lab analysis, and (c) machine learning. In field studies, we measured the complete 450 ft Sycamore stratigraphic section on the south limb of the Arbuckle Mountains along I-35, measured the outcrop gamma-ray profile, calculated the fracture intensity per bed and restored the fracture orientations to the horizontal bedding plane. The contacts with the underlying Woodford Shale and overlying Caney Shale were additionally examined. Lab studies included petrographic analyses, Scanning Electron Microscopy (SEM), Rock Eval Pyrolysis analyses, and X-ray Diffraction (XRD). For machine learning studies, principal component analysis (PCA), elbow method, and self-organizing map (SOM) were used to analyze the electrofacies from the outcrop and an uncored well.
As a result, it was found that the outcrop stratigraphy, lithofacies and electrofacies are tied with the hand-held gamma ray profile and correlated with a nearby subsurface well. Five major outcrop lithofacies are identified from wireline logs. Two fracture sets (N18E and N63W) were observed in the outcrop. Fracture intensity varied from 1.5 to 8 fractures per linear ft. Most fractures are filled with calcite, but some contain bitumen. The Rock Eval Pyrolysis analyses revealed that the I-35 Sycamore intervals are dominated by apparent type II and type III kerogen (oil prone and oil/gas prone) with an average Tmax of 440 °C. Total organic matter ranged from 0.1 to 1.5 wt % in the outcrop.
The reservoir quality was assessed by integrating lithofacies, fracture analyses, and geochemical analyses. The bioturbated shale and/or the sandy siltstone can be a potential target zone for the following reasons: the bioturbated shale is characterized by the highest fracture abundances (avg. 4.4 fractures per linear ft), and clay content is 35%, with 50% quartz, indicating a somewhat brittle rock, with a potential hydrocarbon migration, during production, from the underlying Woodford shale during hydraulic fracturing. The sandy siltstone is characterized by the absence of calcite cement, highest micro-porosity, highest quartz (58%), and potential hydrocarbon migrations from the underlying upper shale section of Mississippian rocks and/or charged from the overlying Caney shale or the underlying Woodford shale. These two lithofacies and other lithofacies can be predicted from well log signatures when uncored wells are unavailable.
Kutsienyo, Eusebius Junior (Petroleum Recovery Research Center) | Ampomah, William (Petroleum Recovery Research Center) | Sun, Qian (Petroleum Recovery Research Center) | Balch, Robert Scott (Petroleum Recovery Research Center) | You, Junyu (Petroleum Recovery Research Center) | Aggrey, Wilberforce Nkrumah (KNUST) | Cather, Martha (Petroleum Recovery Research Center)
This paper presents field-scale numerical simulations of CO2 injection activities in the Pennsylvanian Upper Morrow sandstone reservoir, usually termed the Morrow B sandstone, in the Farnsworth Unit (FWU) of Ochiltree County, Texas. The CO2 sequestration mechanisms examined in the study include structural-stratigraphic, residual, solubility and mineral trapping. The reactive transport modelling incorporated in the study evaluates the field's potential for long-term CO2 sequestration and predicts the CO2 injection effects on the Morrow B pore fluid composition, mineralogy, porosity, and permeability.
The dynamic CO2 sequestration model was built from an upscaled geocellular model for the Morrow B. This model incorporated geological, geophysical, and engineering data including well logs, core, 3D surface seismic and fluid analysis. We calibrated the model with active CO2-WAG miscible flood data by adjusting control parameters such as reservoir rock properties and Corey exponents to incorporate potential changes in wettability. The history-matched model was then used to evaluate the feasibility and mechanisms for CO2 sequestration. We used the maximum residual phase saturations to estimate the effect of gas trapped due to hysteresis. The coupled approach which involves the aqueous phase solubility and geochemical reactions were modelled prior to import into the compositional simulation model. The viscosities of the liquid-vapor phases were modeled based on the Jossi-Stiel-Thodos Correlation. This correlation depended on the mixture density calculated by the equation of state. The gas solubility coefficients for the aqueous phase were estimated using Henry's law for various components as function of pressure, temperature, and salinity. The characteristic intra-aqueous and mineral dissolution/precipitation reactions were assimilated numerically as chemical equilibrium and rate-dependent reactions respectively. Multiple scenarios were performed to evaluate the effects and potentials of the CO2 sequestrated within the Morrow formation. Additional scenarios that involve shut-in of wells were performed and the reservoir monitored for over 150 years to understand possible dissolution/precipitation of minerals. Changes in permeability as a function of changes in porosity caused by mineral precipitation/dissolution were calibrated to the laboratory chemo-mechanical responses.
This confirms the CO2 injection in the morrow B will alter petrophysical properties, such as permeability and porosity in short-term due to the dissolution of calcite. However, further investigation for the long-term effects needs to be conducted. Moreover, the following significant observations are extracted from the result of this study: oil recovery, total volume of CO2 due to multiple trapping mechanisms, effect of salinity, the timescale-view of the dissolution/precipitation evolution in the Morrow B sandstone.
Experiences gained from this study offers valuable visions regarding physiochemical storage induced by the CO2 injection activities and may serve as a benchmark case for future CO2-EOR projects when reactive transportations are considered.
A powerful new tool for unconformity identification in a range of geological environments is presented together with very strong evidence of its utility.
Commonly in an exploration setting correct sequence interpretation has taken years and multiple detailed studies, now with the new tool it can be done quite easily in near real time.
Recognition of unconformities in boreholes, particularly where correlation with outcrop is not available, traditionally relies on paleontological methods, normally palynology or micropalaeontology and correlations between wells where sections of the observed sequence are missing. Observations in recently drilled wells in Dubai have provided evidence for another useful tool.
While drilling Well A, bulk rock phosphate concentrations were obtained in near real time while drilling using X-ray fluorescence (XRF). These were then plotted against well depth. Phosphate values were taken as indicators of long duration and high intensity of organic production or conversely a low rate of sedimentation. Unconformities were marked by significant and obvious phosphate peaks while drilling in a marine sequence. Higher than average concentration of phosphates in marine environments during periods of non-deposition or very slow deposition have been known for some time but their use as markers for unconformities while drilling has not been widespread due to the practical difficulties with sample analysis. With advances in XRF technology routine wellsite XRF analysis services are now available.
Plots of phosphate concentrations in Well B which was drilled through a sub-aerially deposited sequence also showed phosphate peaks, some of which correlated with known and recognisable unconformity surfaces. Further evaluation, particularly comparison with palynology data, showed that the phosphate peaks which did not correlate with known unconformities indicated previously unrecognised unconformities. Phosphate peaks on unconformity surfaces in sub-aerially deposited sequences have not, as far as the authors can determine, been previously recognised.
Well C is an older well which penetrated a similar sub-aerially deposited sequence to Well B with no XRD analyses available. Correct interpretation of the Well C sequence was not possible until the key points were derived from the more complete Well B data.
Evidence is presented showing that phosphate peaks are practical and useful indicators of unconformities in near real time, especially when interpreted with other geological information. An example is also given of an unconformity which displays no phosphate peak together with an explanation as to why there is no peak.
In an exploration setting analysis of phosphate trends can significantly enhance and simplify sequence and palaeoenvironmental interpretation and understanding of regional tectonics thus providing greater insight when planning follow up wells leading to a higher success rate. As such it is a new and novel exploration tool with a potentially high economic value.