Reservoir Architecture and Fluid Connectivity in an Abu Dhabi Oil Accumulation

Summary Developing an understanding of reservoir architecture and fluid connectivity is a challenging, but essential task for well, reservoir and facilities management (WRFM). Insight into fluid connectivity (both static and dynamic) can be obtained from molecular fingerprinting of crude oil samples. Oil fingerprinting is also applied for allocation of commingled fluid streams, and in time-lapse mode it can even help to understand fluid flow in the subsurface. Results from fingerprinting studies are directly used as constraints for static and dynamic reservoir models. A basic requirement for most fingerprinting applications is an understanding of the initial, pre-production fluid distribution. The limited availability of pre-production fluids has until now been a major constraint for the widespread application of oil fingerprinting in the industry. Reservoir rock samples contain enough residual hydrocarbons for fluid fingerprinting. Reservoir core and cuttings samples are widely available and thus provide an excellent opportunity to increase the spatial coverage of fluid fingerprints in a reservoir. A major challenge, however, is the accuracy and reproducibility of existing fingerprinting methods, which are insufficient in the chromatographic range of the ‘heavier’, non-volatile, hydrocarbons remaining in reservoir rock samples. This paper describes the application of a new, high resolution, molecular fingerprinting technology that resolves these limitations. This so-called Compound Class Specific Fingerprinting (CCSF) technique has unprecedented accuracy and reproducibility over the full analytical window, which makes it suitable for fingerprinting of both oils and extracts. An added benefit of this approach is that the additional compound class information may help to resolve why fluids are different, as not all differences are related to reservoir connectivity. As a first test, the new CCSF technology has been applied to fluid samples from an offshore field in Abu Dhabi. Two specific aspects are highlighted in this paper: Assessment of vertical compartmentalization and fault transmissibility of four stacked reservoirs in a highly fractured zone. Even in this highly fractured zone, a barrier to vertical fluid flow was identified between the top reservoir and the three underlying reservoirs, which contain slightly different oil. The improved resolution of the CCSF method, combined with the molecular information it provides, made it possible to demonstrate that the fluids in the lower reservoirs are vertically connected and that gravity segregation has created a compositional gradient. These conclusions could not have been reached with existing fingerprinting technologies. Identify opportunities for production monitoring. Some of the reservoirs in this field show strong compositional gradients related to the complex charge history and incomplete fluid mixing. Fluid surveillance of the mid-flank producers will help identify the efficiency of the gas and water injection schemes that are simultaneously applied to this reservoir. In addition, fluid surveillance will help to predict water and/or gas breakthrough.

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Dual attenuation peaks revealing mesoscopic and microscopic fluid flow in partially oil-saturated Fontainebleau sandstones

Geophysical Journal International ◽

10.1093/gji/ggaa551 ◽

2020 ◽

Vol 224 (3) ◽

pp. 1670-1683

Author(s):

Liming Zhao ◽

Genyang Tang ◽

Chao Sun ◽

Jianguo Zhao ◽

Shangxu Wang

Keyword(s):

Fluid Flow ◽

Reservoir Characterization ◽

Seismic Analysis ◽

Confining Pressure ◽

Time Lapse ◽

Seismic Attenuation ◽

Fluid Distribution ◽

Oil Viscosity ◽

Measurement Results ◽

And Shifts

SUMMARY We conducted stress–strain oscillation experiments on dry and partially oil-saturated Fontainebleau sandstone samples over the 1–2000 Hz band at different confining pressures to investigate the wave-induced fluid flow (WIFF) at mesoscopic and microscopic scales and their interaction. Three tested rock samples have similar porosity between 6 and 7 per cent and were partially saturated to different degrees with different oils. The measurement results exhibit a single or two attenuation peaks that are affected by the saturation degree, oil viscosity and confining pressure. One peak, exhibited by all samples, shifts to lower frequencies with increasing pressure, and is mainly attributed to grain contact- or microcrack-related squirt flow based on modelling of its characteristics and comparison with other experiment results for sandstones. The other peak is present at smaller frequencies and shifts to higher frequencies as the confining pressure increases, showing an opposite pressure dependence. This contrast is interpreted as the result of fluid flow patterns at different scales. We developed a dual-scale fluid flow model by incorporating the squirt flow effect into the patchy saturation model, which accounts for the interaction of WIFFs at microscopic and mesoscopic scales. This model provides a reasonable interpretation of the measurement results. Our broad-frequency-band measurements give physical evidence of WIFFs co-existing at two different scales, and combining with modelling results, it suggests that the WIFF mechanisms, related to pore microstructure and fluid distribution, interplay with each other and jointly control seismic attenuation and dispersion at reservoir conditions. These observations and modelling results are useful for quantitative seismic interpretation and reservoir characterization, specifically they have potential applications in time-lapse seismic analysis, fluid prediction and reservoir monitoring.

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Capillary Equilibrium in Porous Materials

Society of Petroleum Engineers Journal ◽

10.2118/1011-pa ◽

1965 ◽

Vol 5 (01) ◽

pp. 15-24 ◽

Cited By ~ 61

Author(s):

Norman R. Morrow ◽

Colin C. Harris

Keyword(s):

Mass Transfer ◽

Fluid Flow ◽

Porous Materials ◽

Capillary Pressure ◽

Chemical Engineering ◽

Fluid Distribution ◽

Bulk Fluid ◽

Fluid Saturation ◽

Capillary Pressure Curves ◽

The Relationship

Abstract The experimental points which describe capillary pressure curves are determined at apparent equilibria which are observed after hydrodynamic flow has ceased. For most systems, the time required to obtain equalization of pressure throughout the discontinuous part of a phase is prohibitive. To permit experimental points to be described as equilibria, a model of capillary behavior is proposed where mass transfer is restricted to bulk fluid flow. Model capillary pressure curves follow if the path described by such points is independent of the rate at which the saturation was changed to attain a capillary pressure point. A modified suction potential technique is used to study cyclic relationships between capillary pressure and moisture content for a porous mass. The time taken to complete an experiment was greatly reduced by using small samples. Introduction Capillary retention of liquid by porous materials has been investigated in the fields of hydrology, soil science, oil reservoir engineering, chemical engineering, soil mechanics, textiles, paper making and building materials. In studies of the immiscible displacement of one fluid by another within a porous bed, drainage columns and suction potential techniques have been used to obtain relationships between pressure deficiency and saturation (Fig. 1). Except where there is no hysteresis of contact angle and the solid is of simple geometry, such as a tube of uniform cross section, there is hysteresis in the relationship between capillary pressure and saturation. The relationship which has received most attention is displacement of fluid from an initially saturated bed (Fig. 1, Curve Ro), the final condition being an irreducible minimum fluid saturation Swr. Imbibition (Fig. 1, Curve A), further desaturation (Fig. 1, Curve R), and intermediate scanning curves have been studied to a lesser but increasing extent. This paper first considers the nature of the experimental points tracing the capillary pressure curves with respect to the modes and rates of mass transfer which are operative during the course of measurement. There are clear indications that the experimental points which describe these curves are obtained at apparent equilibria which are observed when viscous fluid flow has ceased; and any further changes in the fluid distribution are the result of much slower mass transfer processes, such as diffusion. Unless stated otherwise, this discussion applies to a stable packing of equal, smooth, hydrophilic spheres supported by a suction plate with water as the wetting phase and air as the nonwetting phase. SPEJ P. 15ˆ

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Geostatistical Model for the Arab-D Reservoir, North ’Ain Dar Pilot, Ghawar Field, Saudi Arabia: An Improved Reservoir Simulation Model

GeoArabia ◽

10.2113/geoarabia0102267 ◽

1996 ◽

Vol 1 (2) ◽

pp. 267-284

Author(s):

John L. Douglas ◽

Keyword(s):

Saudi Arabia ◽

Fluid Flow ◽

Reservoir Rock ◽

Well Test ◽

Geostatistical Model ◽

Deterministic Models ◽

Modeling Approach ◽

The North ◽

Porosity And Permeability ◽

Ghawar Field

ABSTRACT The North ‘Ain Dar 3-D geocellular model consists of geostatistical models for electrofacies, porosity and permeability for a portion of the Jurassic Arab-D reservoir of Ghawar field, Saudi Arabia. The reservoir consists of a series of shallow water carbonate shelf sediments and is subdivided into 10 time-stratigraphic slices on the basis of core descriptions and gamma/porosity log correlations. The North ‘Ain Dar model includes an electrofacies model and electrofacies-dependent porosity and permeability models. Sequential Indicator Simulations were used to create the electrofacies and porosity models. Cloud Transform Simulations were used to generate permeability models. Advantages of the geostatistical modeling approach used here include: (1) porosity and permeability models are constrained by the electrofacies model, i.e. by the distribution of reservoir rock types; (2) patterns of spatial correlation and variability present in well log and core data are built into the models; (3) data extremes are preserved and are incorporated into the model. These are critical when it comes to determining fluid flow patterns in the reservoir. Comparison of model Kh with production data Kh indicates that the stratigraphic boundaries used in the model generally coincide with shifts in fluid flow as indicated by flowmeter data, and therefore represent reasonable flow unit boundaries. Further, model permeability and production estimated permeability are correlated on a Kh basis, in terms of vertical patterns of distribution and cumulative Kh values at well locations. This agreement between model and well test Kh improves on previous, deterministic models of the Arab-D reservoir and indicates that the modeling approach used in North ‘Ain Dar should be applicable to other portions of the Ghawar reservoir.

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Penerapan Dinamika Fluida dalam Perhitungan Kecepatan Aliran dan Perolehan Minyak di Reservoir

ComTech Computer Mathematics and Engineering Applications ◽

10.21512/comtech.v5i2.2232 ◽

2014 ◽

Vol 5 (2) ◽

pp. 707

Author(s):

Dwi Listriana Kusumastuti

Keyword(s):

Fluid Dynamics ◽

Fluid Flow ◽

Flow Velocity ◽

Oil Recovery ◽

Control Volume ◽

Petroleum Industry ◽

Reservoir Rock ◽

Curved Pipe ◽

Fluid Flow Velocity ◽

Control Volumes

Water, oil and gas inside the earth are stored in the pores of the reservoir rock. In the world of petroleum industry, calculation of volume of the oil that can be recovered from the reservoir is something important to do. This calculation involves the calculation of the velocity of fluid flow by utilizing the principles and formulas provided by the Fluid Dynamics. The formula is usually applied to the fluid flow passing through a well defined control volume, for example: cylinder, curved pipe, straight pipes with different diameters at the input and output, and so forth. However, because of reservoir rock, as the fluid flow medium, has a wide variety of possible forms of the control volumes, hence, calculation of the velocity of the fluid flow is becoming difficult as it would involve calculations of fluid flow velocity for each control volume. This difficulties is mainly caused by the fact that these control volumes, that existed in the rock, cannot be well defined. This paper will describe a method for calculating this fluid flow velocity of the control volume, which consists of a combination of laboratory measurements and the use of some theories in the Fluid Dynamics. This method has been proofed can be used for calculating fluid flow velocity as well as oil recovery in reservoir rocks, with fairly good accuration.

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Needles in the Pay Stack ADNOC Exploring Tight-Oil Rock, Triples Production In First Pilot

Journal of Petroleum Technology ◽

10.2118/0121-0020-jpt ◽

2021 ◽

Vol 73 (01) ◽

pp. 20-22

Author(s):

Trent Jacobs

Keyword(s):

Carbonate Reservoir ◽

Reservoir Rock ◽

Abu Dhabi ◽

Data Set ◽

Slowing Down ◽

Tight Carbonate ◽

Potential Impact ◽

Carbonate Formations ◽

Oil Company ◽

Term Data

In the midst of an industry downturn last year, the Abu Dhabi National Oil Company (ADNOC) reached a new oil production ceiling of 4 million B/D. The UAE’s largest producer has no intentions of slowing down. By decade’s end, ADNOC expects to have raised its maximum daily output by another million barrels. To cross that milestone, the company has set its sights on mastering the tight, thin, and unconventional formations that dot the UAE’s subsurface landscape. One of the places where such developments are hoped to unfold soon is known as Field Q. Found in southeastern Abu Dhabi, Field Q sits above a tight carbonate reservoir that holds an estimated 600 million bbl of oil. But with a permeability ranging from 1 to 3 millidarcy and poor vertical communication, the reservoir and its barrels have proven difficult to cultivate economically - until recently. ADNOC has published new details of its first onshore pilot of a “fishbone stimulation” that involved using more than a hundred hollow needles to pierce as far as 40 ft into the reservoir rock. The additional drainage netted by the fishbone needles boosted production threefold in the test well, as compared with its traditionally completed neighbors on the same pad. ADNOC ran the pilot in the summer of 2019 and by the end of the year saw enough production data to launch a wider 10-well pilot that remains underway. Based on a longer-term data set from these wells, the company will decide whether to leap into a fieldwide deployment of the niche completions technology. In the meantime, the petrotechnical team in charge of the test projects have issued roundly positive reviews of the fishbone technique in two recently presented technical papers (SPE 202636; SPE 203086) from the Abu Dhabi International Petroleum Exhibition & Conference (ADIPEC). “There is a chance that the fishbone-stimulated wells can avoid the drilling of multiple wells targeting different sublayers in the same zone,” said Rama Rao Rachapudi, listing one of several of the technology’s advantages over other approaches that were considered. The senior petroleum engineer with ADNOC, who is one of several authors of the papers that cover both the drilling and completions aspects of the pilot, shared during ADIPEC that his onshore team found motivation to test the technology after bringing in a batch of dis-mal appraisal wells. The fishbone system, also known as multilateral jetting stimulation technology, has been a specialized application ever since it was introduced just over a decade ago. Underscoring the potential impact of the current round of pilots on the technology’s adoption rate, ADNOC noted there were only around 30 worldwide fishbone deployments prior to this project. Most of those have been in the Middle East’s naturally fractured and layered carbonate formations - just like those of Field Q.

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Working Guide to Reservoir Rock Properties and Fluid Flow

10.1016/c2009-0-30574-7 ◽

2010 ◽

Keyword(s):

Fluid Flow ◽

Reservoir Rock ◽

Rock Properties

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Laboratory Investigation of Low Salinity Waterflooding using Carbonate Reservoir Rock Samples

IOR 2017 - 19th European Symposium on Improved Oil Recovery ◽

10.3997/2214-4609.201700266 ◽

2017 ◽

Cited By ~ 1

Author(s):

T. Uetani ◽

K. Takabayashi ◽

H. Kaido ◽

H. Yonebayashi

Keyword(s):

Laboratory Investigation ◽

Carbonate Reservoir ◽

Reservoir Rock ◽

Rock Samples ◽

Low Salinity ◽

Low Salinity Waterflooding

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Post-Depositional Fluid Flow in Jurassic Sandstones of the Uncompahgre Uplift: Insights From Magnetic Fabrics

Frontiers in Earth Science ◽

10.3389/feart.2020.601415 ◽

2020 ◽

Vol 8 ◽

Author(s):

John I. Ejembi ◽

Eric C. Ferré ◽

Sara Satolli ◽

Sarah A. Friedman

Keyword(s):

Fluid Flow ◽

Remanent Magnetization ◽

Magnetic Hysteresis ◽

Natural Remanent Magnetization ◽

Upper Jurassic ◽

Hydrocarbon Exploration ◽

Reservoir Rock ◽

Magnetic Fabrics ◽

Deformation Processes ◽

Carbonate Formations

The anisotropy of magnetic susceptibility (AMS) in sedimentary rocks results from depositional, diagenetic, syn- and post-sedimentary processes that affect magnetic grains. Some studies have also shown the potential role played by post-depositional fluid flow in detrital and carbonate formations. Here we present a new case study of Middle-Upper Jurassic sandstones where secondary iron oxides, precipitated from fluids that migrated through pores, give rise to the AMS. These sandstones are well exposed in the Uncompahgre Uplift region of the Central Colorado Trough, Colorado. The magnetic foliation of these undeformed, subhorizontal strata consistently strike NE-SW over a large distance with an average 45° dip to the SE. This steep AMS fabric is oblique with respect to the regional subhorizontal bedding and therefore does not reflect the primary sedimentary fabric. Also, outcrop-scale and microscopic observations show a lack of post-depositional plastic (undulose extinction) or pressure-solution (stylolites) deformation microstructures in these sandstones, hence precluding a tectonic origin. The combination of magnetic hysteresis, isothermal remanent magnetization, and thermal demagnetization of the natural remanent magnetization indicate that these rocks carry a chemical remanent magnetization born primarily by hematite and goethite. High-field magnetic hysteresis and electron microscopy indicate that detrital magnetite and authigenic hematite are the main contributors to the AMS. These results show that post-depositional iron remobilization through these porous sandstones took place due to the action of percolating fluids which may have started as early as Late Cretaceous along with the Uncompahgre Uplift. The AMS fabric of porous sandstones does not systematically represent depositional or deformation processes, and caution is urged in the interpretation of magnetic fabrics in these types of reservoir rock. Conversely, understanding these fabrics may advance our knowledge of fluid flow in porous sandstones and may have applications in hydrocarbon exploration.

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