Models and measurements of porosity and permeability evolution in a sandstone formation

2011 ◽  
pp. 263-280
Keyword(s):  
Permeability Evolution ◽  
Porosity And Permeability ◽  
Sandstone Formation

scholarly journals Induced microearthquakes predict permeability creation in the brittle crust

2022 ◽  
Author(s):  
Ziyan Li ◽  
Derek Elsworth ◽  
Chaoyi Wang
Keyword(s):  
Patch Size ◽  
Dynamic Evolution ◽  
Permeability Evolution ◽  
Field Scale ◽  
Scale Invariant ◽  
Flow Paths ◽  
Porosity And Permeability ◽  
Hybrid Machine ◽  
Early Injection

Abstract Fracturing controls rates of mass, chemical and energy cycling within the crust. We use observed locations and magnitudes of microearthquakes (MEQs) to illuminate the evolving architecture of fractures reactivated and created in the otherwise opaque subsurface. We quantitatively link seismic moments of laboratory MEQs to the creation of porosity and permeability at field scale. MEQ magnitudes scale to the slipping patch size of remanent fractures reactivated in shear - with scale-invariant roughnesses defining permeability evolution across nine decades of spatial volumes – from centimeter to decameter scale. This physics-inspired seismicity-permeability linkage enables hybrid machine learning (ML) to constrain in-situ permeability evolution at verifiable field-scales (~10 m). The ML model is trained on early injection and MEQ data to predict the dynamic evolution of permeability from MEQ magnitudes and locations, alone. The resulting permeability maps define and quantify flow paths verified against ground truths of permeability.

The Ravenspurn North Field, Blocks 42/30, 43/26a, UK North Sea

1991 ◽  
Vol 14 (1) ◽  
pp. 459-467 ◽  
Keyword(s):  
North Sea ◽  
Clay Content ◽  
Gas Production ◽  
Commercial Production ◽  
Reservoir Rock ◽  
Normal Faults ◽  
Well Drilling ◽  
Variable Permeability ◽  
Porosity And Permeability ◽  
Sandstone Formation

AbstractThe Ravenspurn North Field is a gas accumulation located in the Southern North Sea, Permian Gas Basin which was discovered in October 1984. It has undergone four years of appraisal well drilling culminating in the approval of the development plan in 1988. Development wells are currently being drilled and three offshore installations are planned; first gas production began in July 1990.The Ravenspurn North Field is a combined structural and stratigraphic trap. The reservoir is fault closed along a series of anastomosing oblique strike-slip and normal faults. Seals along the faults are provided by the Silverpit Formation mudstones and Zechstein Group evaporites. The reservoir deteriorates to the northwest because of thinning, facies change and increasing authigenic clay content.The Lower Leman Sandstone Formation of the Rotliegendes Group forms the reservoir. It consists of a sequence of aeolian dune, fluvial sheetflood, fluvial channels and lake margin sabkha deposits. Non-reservoir intervals are formed by playa lake mudstone sequences. Fluvial and sabkha facies dominate in the northwest while aeolian facies dominate in the southeast parts of the Field.Reservoir quality was initially controlled by lithofacies distribution. Subsequent diagenesis further modified the reservoir rock resulting in variations in the porosity and permeability. Deliverability is a function of variable permeability with two areas identified; the high deliverability area where gas wells have tested sufficient quantities for commercial production without artificial stimulation and a low deliverability area where gaswells require hydraulic fracture stimulation before significant commercial production rates are achieved.

The complexity of carbonate porosity distribution in the Upper Marrat Formation, Central Saudi Arabia

2020 ◽  
Author(s):  
Saleh Ahmed ◽  
Luis González ◽  
Johannes Jozef Gerardus Reijmer ◽  
Ammar ElHusseiny
Keyword(s):  
Saudi Arabia ◽  
Carbonate Rocks ◽  
Early Jurassic ◽  
Arabian Plate ◽  
Permeability Evolution ◽  
Depositional Processes ◽  
Bedding Planes ◽  
Tectonic Processes ◽  
Porosity And Permeability ◽  
The Impact

<p>In terms of reservoir properties distribution carbonate rocks are very heterogeneous. Moreover, the types of porosity in carbonate rocks is very diverse. In our study of the Upper Marrat Formation near Khasm-adh-Dhibi (central Saudi Arabia) we have documented the pore system complexity and are deconvolving the impact of various post-depositional processes on porosity and permeability evolution of the formation. The Upper Marrat Formation is exposed in the central part of the Arabian plate in a north-south elongated mountain belt. It forms the lower part of the thick Jurassic petroleum-rich succession. The sediments forming the Upper Marrat Formation were deposited during the Early Jurassic time, the Toarcian. The Upper Marrat Formation shows fossiliferous biomicrite to sparse biomicrite carbonates with an evaporite deposit at the top. It is bounded by clayey units at both the top and the base. In general, because of the muddy matrix of the Upper Marrat, sediments are very tight and show low permeability. During the last 175 My, the Upper Marrat has been subjected to a series of diagenetic and tectonic processes. The initial micro- and intergranular porosity was reduced due to early compaction and cementation, however, during later diagenesis and tectonism, porosity and permeability were enhanced. The dominant diagenetic porosity in the Upper Marrat sediments is vuggy porosity, followed by fabric selective intragranular porosity. Many of the horizons in the Upper Marrat are heavily burrowed and mostly filled with sand-sized grains showing a higher porosity than the matrix. Dolomite is limited to evaporite strata and contain extensive inter-crystalline porosity produced during dolomite formation. Tectonism has enhanced porosity through the development of micro- and macro-fractures.  The different sized and orientated micro-fractures are important while they enhance permeability by connecting different pore types. Then extensive macro-fracture network has a major impact on the reservoir qualities, both porosity and permeability. The heavily fractured formation shows numerous fractures sets with NNE to SSW and ENE to WNW orientations. Fractures are mostly vertical to near-vertical; they are nearly all open, and often crosscut beds, or end at bedding planes. These fractures are the most abundant porosity type and their connectivity results in a very high permeability. In conclusion, initial porosity and permeability, and subsequent diagenetic and tectonic processes reduced and enhanced the porosity and permeability development of the sediments of the Early Jurassic Upper Marrat Formation.</p>

Establishment of Models for Tight Sandstone Formation Evaluation in the Ordos Basin of Northwest China

2014 ◽  
Vol 989-994 ◽  
pp. 1372-1375 ◽  
Author(s):  
Xiao Lei Wei ◽  
Jun Li ◽  
Rui Xu ◽  
Ling Ling Zhi
Keyword(s):  
Ordos Basin ◽  
Northwest China ◽  
Tight Sandstone ◽  
Reserve Estimation ◽  
Formation Evaluation ◽  
Porosity And Permeability ◽  
Important Input ◽  
The Ordos Basin ◽  
Sandstone Formation ◽  
Relative Errors

Porosity and permeability are two important input parameters in formation evaluation. However, It faces a great challenge for formation porosity and permeability estimation in tight sandstone reservoirs in the Ordos basin of northwest China due to the greater contribution of rock matrix and complicated pore structure. In this paper, based on the analysis of conventional log responses and 324 core samples drilled from the target formations in different wells, the estimation models of reservoir porosity and permeability are established, and the reliability of these models are verified by comparing the calculated porosity and permeability by using the established models with core analyzed results. The absolute errors between these two kinds of porosities are all lower than 0.64%, and the relative errors between them are lower than 7.1%, these are coincided with the requirement of reserve estimation.

Effect of Sand Content on the Filter Cake Properties and Removal During Drilling Maximum Reservoir Contact Wells in Sandstone Reservoir

2015 ◽  
Vol 138 (3) ◽  
Author(s):  
Badr S. Ba geri ◽  
Mohamed Mahmoud ◽  
Saleh. H. Al-Mutairi ◽  
Abdulazeez Abdulraheem
Keyword(s):  
Calcium Carbonate ◽  
Filter Cake ◽  
Flow Line ◽  
Drilling Fluid ◽  
Horizontal Section ◽  
Fluid Properties ◽  
Porosity And Permeability ◽  
Sand Particles ◽  
Sandstone Reservoir ◽  
Sandstone Formation

The drilling mud program contains many tests such as filtration rate and filter cake properties to select the proper drilling fluid additives that yield the standard ranges of the viscosity, filtration rate, etc. However, the physical and chemical changes in the mud composition during the mud circulating will cause changes to the filter cake properties. The changes in the filter cake properties should be considered in the mud design program to prevent the problems associated with the change in the drilling fluid properties. For long horizontal wellbores penetrating plastic formations, the two sources of solids in filter cake are drilling chemical additives and formation cuttings (sand particles in the case of sandstone reservoir). This study focuses on the effect of introducing sand particles from the drilled—formations on the filter cake properties. Real drilling fluid samples from the field were collected at different location during drilling a 3600 ft of the horizontal section of a sandstone formation. Calcium Carbonate (CaCO3) was used as weighting material in this filed. The drilling fluid samples were collected at two different points: the flow line coming from the well after shale shaker and the flow line going to the well to verify the effect of separation stages on filter cake properties. The primary drilling fluid properties of the collected samples were measured such as density and rheological parameters. High pressure high temperature (HPHT) filter press was used to perform the filtration and filter cake experiments at 300 psi differential pressure and room temperature (25 °C). The mineralogy of the external filter cake formed by fluid loss cell is determined using SEM (scanning electron microscopy) and XRD (X-ray diffraction). Finally, solubility test was conducted to evaluate the effect of sand particles on filter cake removal (containing Calcium Carbonate as weighting material) using chelating agent: glutamic diacetic acid (GLDA) at pH 4. The results showed that for long horizontal sections, the effect of introducing sand particles to the composition of the filter cake can cause significant change to the properties of filter cake such as mineralogy, thickness, porosity, and permeability. For instant the thickness of filter cake increased about 40% of its original thickness when drilling sandstone formation in horizontal well due to fine sand particle settling. The filter cake porosity and permeability increment in the first 2000 ft part of the horizontal section was observed clearly due to the irregular shape of the drilling particles. However for the points after the first 2000 ft of horizontal lateral, the porosity and permeability almost remained constant. Increasing the sand content up to 20% degrade the dissolution rate of calcium carbonate in the GLDA (pH = 3.8) to 80% instead of 100%.

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