In the early days of the oil industry, saline water or brine frequently was produced from a well along with oil, and as the oil-production rate declined, the water-production rate often would increase. This water typically was disposed of by dumping it into nearby streams or rivers. In the 1920s, the practice began of reinjecting the produced water into porous and permeable subsurface formations, including the reservoir interval from which the oil and water originally had come. By the 1930s, reinjection of produced water had become a common oilfield practice. Reinjection of water was first done systematically in the Bradford oil field of Pennsylvania, U.S.A. There, the initial "circle-flood" approach was replaced by a "line flood," in which two rows of producing wells were staggered on both sides of an equally spaced row of water-injection wells. In the 1920s, besides the line flood, a "five-spot" well layout was used (so named because its pattern is like that of the five spots on ...
Kirkuk is a supergiant oil reservoir located in Iraq. From 1961 to 1971, 3.2 billion bbl of oil were produced under pressure maintenance by waterdrive using river water. The 1971 production rate was approximately 1.1 million barrels of oil per day (BOPD). Since then, the field has continued to produce large volumes of oil by voidage-replacement water injection; however, few production details for recent years appear in the technical literature. The primary pay interval for the Kirkuk field is the 1,200-ft-thick Main Limestone.
Khalaf G. Salem, Khalaf Gad Salem (South Valley Egyptian Petroleum Holding Company) | Abdulaziz M. Abdulaziz, Abdel Aziz Mohamed (Faculty of Engineering, Cairo University) | Abdel Sattar A. Dahab, Abdel Sattar Dahab (Faculty of Engineering, Cairo University)
An accurate estimation of porosity and permeability are extremely essential for designing an ideal and efficient program of an oil and gas field development. Numerous methods have been developed to determine the porosity and permeability including laboratory measurements and log derived models. Artificial neural network (ANN) provides an efficient technique that successfully addressed several engineering and geological challenges. In the present study ANN is applied to help in predicting porosity and permeability in carbonate reservoirs using back propagation neural network (BPNN) with high accuracy on well log data from numerous fields worldwide.
ANN has the ability to understand a highly non – linear relationship and to perform simulation studies in a rapid manner. The BPNN model of porosity and permeability is developed using a set of well logging data as input layers and core porosity and core permeability as output layers. Two scenarios are considered to develop by ANN.
The first scenario considers using all available logging data directly as input for ANN. In the second scenario an additional input, diagenesis parameter, is added as input to ANN which is essentially calculated from logging data. In each scenario two models are developed; the first for porosity prediction and the second predicts permeability in carbonate reservoirs. The optimal learning rate and momentum constant used in the BPNN model are achieved after serial combinative trials. The available data was assigned 80% for training and 20% for verification.
The results of the developed porosity and permeability models are well compared to core data in verification. In the first scenario, cross-plot of the actual porosity versus ANN predicted Porosity exhibited a good match with a correlation coefficient equal to 0.97. Cross-plot of the actual permeability versus ANN predicted permeability exhibited a good match with a correlation coefficient equal to 0.80. In the second scenario, cross-plot of the actual porosity versus ANN predicted porosity exhibited a good match with a correlation coefficient equal to 0.97. Cross-plot of the actual permeability versus ANN predicted permeability exhibited a good match with a correlation coefficient equal to 0.98. Such data indicate that the developed models are successful in predicting the porosity and permeability for carbonate reservoirs.
Nie, Zhen (Research Institute of Petroleum E&D, CNPC) | Luo, Huihong (PetroChina Middle East International Company) | Zhang, Zhenyou (PetroChina Middle East International Company) | Chen, Yufeng (PetroChina Middle East International Company)
The Lower Fars formation located at the depths of 1350-1950meters, it mainly consists of alterations of claystone, anhydrite and salt layer with a 2.22 g/cm3high pressure aquifer in 1400~1600m, the safe drilling window is limited to 0.15g/cm3,the 10~15m interval under this formation is the main Jeribe-Kirkuk reservoir in this oilfield. More than 100 clusters of directional and horizontal Jeribe-Kirkuk wells will be drilled. The high risk of wellbore instability in Lower Fars has resulted in wellhole collapse, overpull, pipe sticking, and sticking during running casing and the high-density salt-saturated drilling fluid is easily deteriorated and loss of liquidity while directional drilling through the Lower Fars interval. In the 1st directional well JKD007, stuck pipe was encountered 3 times and drilling sidetrack holes were required 2 times. In the 1sthorizontal well JK060H,a stuck casing resulted in setting the casing shoe in shallower depth. This study has been carried out in order to decrease the risk of sticking and ensure drilling a smooth, directional hole in the Lower Fars formation. So the lithologic creepage rules and the hole deformation rules in the Lower Fars, major causes for pipe sticking, a safe window of drilling fluid, critical the density of drilling fluid under the different inclinations and technology countermeasures were determined through build the wellbore stability analysis models based on the results of rock mechanics tests of the salt, anhydrite and claystone, the pore pressure, in-situ stress and rock deformation and failure law. The critical density of drilling fluid increase to 2.35 g/cm3 is proposed while the inclination about 35°in Lower Fars formation in order to reduce the risk of pipe sticking; the more stable well trajectory is recommended baesd on the lower Fars deformation rules through adjusting the location of KOP to reduce the inclination and directional length in Lower Fars and considering the distribution of the salt/anhydrite/claystone, and a new kind of the high-density saturated salt-water mud was developed through introducing a kind of new polyamine type inhibitors, synthetic polymer thinner and optimizing the composition and dosage of weighting materials. Since then,11 directional wells and 2 horizontal wells have been drilled and completed with great success for the Jeribe-Kirkuk wells. Average directional drilling time in Lower Fars is reduced from 74days to 59days and the average ROP has improved by 9.64% using a 2.35g/cm3drilling fluid with a controlled viscosity of less than 120s. This paper will systematically describe the details of the sticking mechanism, the Lower Fars wellbore stability analysis method, and the effectiveness of the countermeasures used in directional drilling through the high-pressure salt/anhydrite/claystone layer.
Al-Hilali, Mazin Mohlab (University of Kirkuk & Industrial University of Tyumen) | Al-Abideen, Mohammed Jawad Zein (University of Kirkuk & Industrial University of Tyumen) | Li, Weidong (Baker Hughes Inc.) | Jebutu, Segun (Baker Hughes Inc.) | Perederii, Artur (Gubkin Russian State University of Oil and Gas)
Oil Companies depend on the Core-Measured-wettability. The practice of transferring the samples from the formation to the lab may lead to wettability alteration during core cutting operations and sample preparation; additional laboratory issues include surface adsorption equilibrium and optimal interfaceageing time, if a smooth surface is used it will not account for the rock surface roughness. The biggest disadvantage of the laboratory methods is that of scaling to entire reservoir extent downhole condition. Adding up, all of these processes are time-consuming, consequently a technique to evaluate in-situ wettability is desired. The in-situ wettability of rocks from Nuclear Magnetic Resonance (NMR) log is a representative of the entire interval at the reservoir condition. A derived spin-lattice function from the fundamental NMR relaxation time T2 is directly related to the interfacial tension and the surface wetting fluid properties, as a result, an in-situ wettability index could be computed from the function. Rock wettability may explain some apparent discrepancies that occur in defining water-oil contacts by Reservoir Characterization Instrument (RCI) and logging measurements. Analyzing these discrepancies using the RCI Pressure Data makes it possible to estimate the In-Situ Wettability state of the reservoir. Case Studies from two different Giant Oil Fields located in the South of IRAQ are included in this paper, and each field has various sets of Data, varied from Pressure Test and NMR to only Full-Set of Wire line data.
Abstract. Fractures are common features of many well-known reservoirs. Naturally Fracture Reservoirs (NFR) consist of fractures in igneous, matamorphic, and swedimentary rocks (matrix). Faults in many naturally fractured carbonate reservoirs often have high-permeability zones and are connected to numerous fractures with varying conductivities. In many NFRs, faults and fractures frequently have discrete distributions rather than connected fracture networks. Because fractures are often created by faulting, faults and fractures should be modeled together. Accurately modeling naturally fractured reservoir pressure transient behavior is important in hydrogeology, the earth sciences, and petroleum engineering, including ground-water contamination to shale gas and oil reservoirs. For more than 50 years, conventional dual-porosity type models, which do not include any fractures, have been used for modelling fluid flow in naturally fractured reservoirs and aquifers. They have been continuously modified to add unphysical matrix block properties such as the matrix skin factor.
In general, fractured reservoirs are heterogeneous at different length scales. It is clear that even with millions of grid blocks, numerical models may not be capable of accurately stimulating the pressure transient behavior of continuously and discretely NFRs containing variable conductivity fractures. The conventional dual-porosity type models are obviously an oversimplification; their serious limitations and consequent implications for interpreting well test data from NFRs are discussed in detail. These models do not include wellbore-intersecting fractures, even though they dominate the pressure behavior of NFRs for a considerable length of testing time. Fracture conductivities of one to infinity dominate transient behavior of both continuously and discretely fractured reservoirs, but again dual-porosity models do not containa single fracture. Our fractured reservoir model is capable of treating thousands of fractures that are perdiocially or arbitrarily distributed with finite- and/or infinite-conductivities, different lengths, densities, and orientations.
Appropriate inner boundary conditions are used to account for wellbore-intersecting fractures and direct wellbore contributions to production. Wellbore storage and skin efffects in bounded and unbounded systems are included in the model. Three types of damaged skin factors that may exist in wellbore-intersecting fracture(s) are specified. With this highly accurate model, the pressure transient behavior of conventional dual-porosity type models are investigated, and their limitations and range of applicabilities are identified. The behavior of the triple-porosity models are also investigated. It is very unlikely that triple-porosity behaviorf is due to the local variability of matrix properties at the microscopic level. Rather, it is due to the spatial variability of conductivity, length, density, and orientation of the fracture distributions.
Finally, we have presented an interpretation of a field buildup test example from an NFR using both conventional dual-porosity models and our fractured reservoir model.
We aim to demonstrate the use of high-resolution sedimentological data during the early phase of the exploration cycle. The data reviewed included more than 1300 m of log sections taken North of Erbil. This was combined with field mapping, a microfacies study and the acquisition of routine core analysis data from plugs to provide a more complete analysis. Subsurface data included lithological information from two wells and 2D seismic lines with a total length of 487 Km.
The study focussed on carbonate sequences including potential and known hydrocarbon reservoirs, notably the Qamchuqa-, the Shiranish-, the Khurmala- and the Pila Spi Formations. As a result a refined stratigraphic and depositional framework for the Lower Tertiary and Upper Mesozoic sequences has been established. The Cretaceous sequences analysed herein display a series of distinct lithofacies types ranging from shallow marine to deeper marine environments, which can be attributed to different main depositional complexes. The Paleogene sequences show a high diversity of lithotypes that relate to fluvial, fluvio-marine, mixed siliciclastic - carbonate shelf and inner platform depositional environments.
Outcrop samples from both Tertiary and Cretaceous dolomites inherit the highest porosities thus presumably best reservoir quality in the subsurface. However, the effect of fracturing cannot be assessed in detail from surface data alone.
A 3D facies model has proven useful in displaying the spatial relationship of the well and outcrop data. The display of facies probabilities improves the recognition of cyclicity within homogeneous dolomite sections. Possible extent and connectivity of geobodies could be assessed with the model.
The results have been compared with, and put into a regional context with data from literature and proprietary selected subsurface data. The outcrop data have been incorporated into a workflow that supported other G&G subsurface disciplines during the exploration phase.
The youngest major reservoirs and seals of the northern Arabian Plate occur in the Chattian, Aquitanian, and Burdigalian. They unconformably overlie major reservoirs of the Oligocene Kirkuk Group, shelfal carbonates formed on the northeast margin of the Mesopotamian Basin.
Deep-marine carbonates of the upper-Chattian Ch3 and lower-Aquitanian Aq1 sequences (Serikagni Formation) were deposited within the basin. A thin anhydrite occurs at the base. These pass upwards into shelfal carbonates (Euphrates and Middle Asmari formations), which lie unconformably above older shelfal carbonates around the basin. The basin is completely filled by evaporites and carbonates of the upper-Aquitanian Aq2 sequence and lowstand of the basal-Burdigalian Bur1 sequence (Dhiban Formation and Kalhur Anhydrite). The top of the shelfal carbonates is a subaerial unconformity.
Shelfal carbonates (Jeribe and Upper Asmari formations) were deposited in the transgressive to highstand systems tracts of the Bur1 and Bur2 sequences. Subaerial-exposure surfaces are recognized at the top of each of these sequences. Cyclical marginal-marine to nonmarine evaporites, carbonates and siliciclastics (Transition Beds of the Fat'ha Formation, and lower Gachsaran Formation) lap onto the underlying sequences. In parts of northern Iraq the Basal Fars Conglomerate occurs at the base of the Fat'ha Formation, composed of pebbles of the underlying Oligocene-Miocene carbonates and various lithoclasts of Jurassic-Paleogene age transported from the hinterland to the northeast. Deposition of the evaporite-bearing Fat'ha Formation ended in the late Burdigalian to early Langhian.
Oolitic-skeletal grainstones and skeletal-peloidal packstones and wackestones of the Euphrates and Jeribe formations are partly to completely dolomitized and have 8-20% interparticle, intercrystalline and moldic porosity and 1-10 mD permeability. Basinal wackestones and mudstones of the Dhiban and Serikagni formations are dolomitic and have 10-17% porosity with <1 mD permeability. Thin limestones of the Transition Beds have 4-15% porosity with <1 mD permeability. Evaporites of the Fat'ha and Dhiban formations are the primary seals for these reservoirs.
Stratigraphy and Age Framework
The lithostratigraphic units of Iraq and Iran and the ages of the Lower Miocene formations from the northern Arabian Plate are shown in Figure 1. Major sequence boundaries occur at the top of the Transition Beds of the Fat'ha Formation and the Jeribe and Euphrates/Serikagni formations. The basin-filling evaporites of the Saliferous Beds of the Fat'ha Formation and the Dhiban Formation are lowstand-transgressive deposits formed during one and a half sequences.
Carbonates of the lower Aquitanian and lower and middle Burdigalian are porous and form reservoirs for oil and gas. Evaporites of the upper Aquitanian and upper Burdigalian form seals for these reservoirs.
Biostratigraphic control is lacking or imprecise for these marginal- to shallow-marine carbonates and evaporites. We have relied extensively on strontium stable isotopes of anhydrite for age constraints. The 86Sr/87Sr ratio increases steadily from 0.7083 at the base of the Aquitanian to 0.7089 at the top Langhian. The results are summarized in Figure 2.
Tai, Po C. (ExxonMobil Exploration Company) | Grabowski, George J. (ExxonMobil Exploration Company) | Liu, Chengjie (ExxonMobil Exploration Company) | Kendall, Jerry (ExxonMobil Exploration Company) | Wilson, Augustus O. (Consulting Geologist)
The Sinjar Trough is a major east-west trending extensional feature in Northwest Iraq and Northeast Syria. It began to develop in the Late Cretaceous (the Maastrichtian) due to transtensional tectonics and was inverted during the late Pliocene-Pleistocene as a result of the Zagros Orogeny. Through biostratigraphic, Sr-isotope age dating, petrographic, and sequence-stratigraphic studies of two late Oligocene-earliest Miocene basin-center evaporite intervals in Northwest Iraq and adjacent Northeast Syria, we recognized several minor episodes of inversion in the Sinjar Trough during the Paleogene.
The Basal Serikagni Anhydrite (BSA) is a thin basinal anhydrite unit imbedded between the middle and late Chattian deep-marine carbonate sequences. The BSA extends into Northeast Syria but is missing in several adjacent wells within the Sinjar Trough.
The Dhiban Formation is a thicker late Aquitanian-early Burdigalian evaporite-dominated interval mixed with carbonates. It overlies the Serikagni Formation and onlaps onto the carbonate ramp margins of the Euphrates Formation, which prograded towards basin center from the northeast and southwest. In Northeast Syria, the same basin-center evaporite is called the Dibbane Formation and shows local thickening and thinning. The overlying Jeribe Formation, however, has a uniform thickness across Iraq and Northeast Syria.
The areal distribution, facies, and stratal geometry of these basin-center evaporite-bearing intervals reflect the antecedent topography during their deposition. Minor inversions within the Sinjar Trough before or during the late Oligocene caused non-deposition or erosion of the BSA in Northeast Syria. Another episode of inversion before the early Miocene created low-relief highs and differential accommodation within the Sinjar Trough. The Dhiban/Dibbane Formation simply filled the remnant basin and was able to cover the highs during the lowstand stage, resulting in local variations of the basin-center evaporite accumulation. This study may shed some light on the timing of early trap formation within the Sinjar Trough.
Tectonic Setting, Tectonic History, and Hydrocarbon System of the Sinjar Trough
The Sinjar Trough is an east-west trending Late Paleozoic-Mesozoic rift basin (~250 km long, 50 km wide) that is located in Northwest Iraq and Northeast Syria (Best et al., 1993; Brew et al, 1999; Figure 1). It is a possible eastern extension of the Palmyride rift system but has less intense Paleozoic history of extension, thermal subsidence, and sediment accumulation (Best et al., 1993). The major extension took place during Late Campanian-Maastrichtian time and the east-west striking faults formed the Abd el Aziz and Sinjar grabens, in which thick Maastrichtian Shiranish Formation (up to 5000 ft) was deposited (Brew et al., 1999, 2001). Normal faulting ceased abruptly by the end of the Cretaceous, and the Paleogene was mostly a time of tectonic quiescence (Brew et al., 1999). Full-scale inversion by reactivation of east-west striking normal faults formed fault propagation folds during late Plio-Pleistocene time and inverted the grabens as surface anticlines (Kent and Hickman, 1997; Brew et al., 1999, 2001). Deformation increases to the east in the Iraqi Sinjar region (Brew et al, 2001).
In the past, only four types of reservoirs were defined to characterize matrix and fracture systems. These definitions based on matrix and fracture systems do not cover all the pore systems present in the real world because a great number of reservoir systems are made up of different lithologies and pore types. The pore types could be matrix, fractures, or vugs or combinations of these. One of the potential problems is that engineers have simplified that complex problem and therefore have erroneously produced the reservoirs. If a complete classification were available in the literature, more effort would have been made to recognize all the pore types present in a specific reservoir for better characterization and production.
This paper discusses a new methodology to classify all kind of reservoirs in the real world: fracture, matrix, vugs, or combinations of those. We have developed membership functions using fuzzy logic concepts for the cementation factor m variable. We have identified at least five types of reservoirs according to pore types.
All types of unconventional or conventional reservoirs are represented in this new classification system. We used core data from Southern Vietnam, Libya, the United States, Argentina, Iran, Iraq, Saudi Arabia, Colombia, and Venezuela to validate our new classification, and we are certain that it will be of great help to the engineers. Better understanding of the behavior of a specific reservoir will help increase the production and the recovery factor.
We also discuss how to increase the oil or gas production as a reservoir moves from one class to another as result of hydraulic fracturing.
Reservoir rocks are dominantly sedimentary (sandstones and carbonates); however, highly fractured igneous and metamorphic rocks have been known to produce hydrocarbons. Each of these rock types has a characteristic composition and texture that is a direct result of depositional environment and post-depositional processes. That´s why the configuration of reservoirs is extremely diverse and varies from sandstones to carbonates and from intergranular pore space to fracture or vuggy systems.
Sandstones reservoirs are the second most abundant (about 37%) sedimentary rock type of the three (sandstones, shales, carbonates), the most common reservoir rock, and the second highest producer (about 37%). The porosity for these reservoirs is on the range of 10-30% and the most common porosity is intergranular and largely determined by sorting (primary porosity). It does not mean that there is a group that belongs to naturally fracture reservoirs or both, a transition group between intergranular and fracture porosity.