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ABSTRACT Tar mats at the oil-water contact (OWC tar mats) in oilfield reservoirs can have enormous, pernicious effects on production due to possibly preventing of any natural water drive and precluding any effectiveness of water injectors into aquifers. In spite of this potentially huge impact, tar mat formation is only now being resolved and integrated within advanced asphaltene science. Herein, we describe a very different type of tar mat which we refer to as a "rapid-destabilization tar mat"; it is the asphaltenes that undergo rapid destabilization. To our knowledge, this is the first paper to describe such rapid-destabilization tar mats at least in this context. Rapid-destabilization tar mats can be formed at the crest of the reservoir, generally not at the OWC and can introduce their own set of problems in production. Most importantly, rapid-destabilization tar mats can be porous and permeable, unlike the OWC tar mats. The rapid-destabilization tar mat can undergo plastic flow under standard production conditions rather unlike the OWC tar mat. As its name implies, the rapid-destabilization tar mat can form in very young reservoirs in which thermodynamic disequilibrium in the oil column prevails, while the OWC tar mats generally take longer (geologic) time to form and are often associated with thermodynamically equilibrated oil columns. Here, we describe extensive data sets on rapid-destabilization tar mats in two adjacent reservoirs. The surprising properties of these rapid-destabilization tar mats are redundantly confirmed in many different ways. All components of the processes forming rapid-destabilization tar mats are shown to be consistent with powerful new developments in asphaltene science, specifically with the development of the first equation of state for asphaltene gradients, the Flory-Huggins-Zuo Equation, which has been enabled by the resolution of asphaltene nanostructures in crude oil codified in the Yen-Mullins Model. Rapid-destabilization tar mats represent one extreme while the OWC tar mats represent the polar opposite extreme. In the future, occurrences of tar in reservoirs can be better understood within the context of these two end members tar mats. In addition, two reservoirs in the same minibasin show the same behavior. This important observation allows fluid analysis in wells in one reservoir to indicate likely issues in other reservoirs in the same basin.
- Asia > Middle East > Saudi Arabia (0.28)
- Europe > Norway > Norwegian Sea (0.24)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > North Kuwait Jurassic (NKJ) Fields > Marrat Formation > Upper Marrat Formation (0.98)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > North Kuwait Jurassic (NKJ) Fields > Marrat Formation > Sargelu Formation (0.98)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Fluid modeling, equations of state (1.00)
- (2 more...)
This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 148717, ’Effects of Fluid and Rock Properties on Reserves Estimation,’ by Kegang Ling, SPE, Zheng Shen, SPE, Texas A&M University, prepared for the 2011 SPE Eastern Regional Meeting, Columbus, Ohio, 17-19 August. The paper has not been peer reviewed. Precise reserves calculation is fundamental for production forecasting. Great efforts are made to obtain fluid and rock properties such as porosity, permeability, saturation, rock and fluid compressibility, viscosity, fluid gravity, gas z-factor, saturation pressure, reservoir pressure, and temperature. There is always uncertainty regarding the information because of instrument sensitivity and limitations, measurement error, environmental effects, sample interval, location, and how representative of the rock the sample is. A systematic study on the effects of fluid and rock properties on reserves estimation was conducted. Introduction Fluid and rock properties control the volume of original hydrocarbon in place and the recoverable oil and gas. Uncertainty and error exist because of the instrument sensitivity and limitations, measurement error, environmental effects, sample interval, location, and how representative of the rock the sample is. Measuring rock properties under reservoir conditions is very difficult. A synthetic field was built to study the effects of fluid and rock properties. It is an oil field with aquifer support. The initial reservoir pressure is above the bubblepoint pressure. Initially, five producers were drilled to produce oil. With time, reservoir pressure declined. As the reservoir pressure declined below the bubblepoint with production, solution gas was released from oil. When the gas saturation reached critical saturation, it began to flow with the oil and water. This three-phase flow in the reservoir represents the middle and late production periods. Model Description The simulation model divides the reservoir into 93×93×2 gridblocks. The reservoir is modified to an irregular shape by assigning zero porosity and permeability to gridblocks at the reservoir edge. To populate the rock properties, different porosities, permeabilities, depths, and pay thicknesses were assigned to each gridblock. Initially, a uniform oil/water contact divided the porous sand into oil and water zones. Pressure at datum was assigned such that pressure above and below the datum can be calculated according to in-situ fluid density. Initial water saturation was assigned to respect the real oil reservoir. Rock and water compressibilities were incorporated and were assumed to be constant at different pressures. Oil viscosity varied with the pressure because solution gas has a significant effect on it. Water viscosity was kept constant. Oil gravity, gas specific gravity, water specific gravity, formation-volume factor (FVF) for oil and gas, and solution-gas/oil ratio were assigned with values often found in real oil fields.
- Well Drilling > Wellbore Design > Rock properties (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
- (3 more...)
Abstract This paper describes a workflow that was applied to a carbonate field in Oman to derive fracture and effective permeability models that were validated with multiple blind wells and reservoir simulation. The studied block is the largest and most faulted within a field which is currently under water-flood FDP. The study was kicked off with extensive borehole image interpretation. In parallel, several high resolution seismic inversions and spectral imaging attributes were generated as drivers to geological and fracture modelling. High resolution seismic was used to highlight subtle faults. Facies changes were also visible from seismic as seen in cored wells. Sequential geological modelling of GR, density, porosity and SW was carried out and constrained by seismic attributes. The derived fracture frequency logs were compared against geological, structural and seismic drivers in a process called driver ranking. The results confirmed the role of faults as well as facies being primary controls of fracturing. Subsequently, the screened and cross-correlated potential drivers were carried forward to constrain the fracture models. Multiple stochastic realizations were derived through neural network training and testing and an average model was kept. Final models were validated against hidden BHI data. A new BHI was used to confirm model prediction. Different types of dynamic data in non-BHI wells were also used to validate the fracture models as specific production/injection related issues could be directly linked to presence of fractures. These data include PLT, PTA and tracer tests from which injectivity issues and short circuiting were explained by higher fracture densities and corridors derived from modeling. Through dynamic calibration, the fracture model was converted to fracture permeability. The fracture permeability is the product of fracture density and a scaling factor derived from history matching. Subsequently, the addition of matrix permeability and fracture permeability will determine the effective permeability. This Keffective was directly used in the reservoir simulator without upscaling since it was part of the same grid hosting the fracture models. The results were encouraging as the simulation was smooth and error-free.
- Geophysics > Seismic Surveying > Seismic Interpretation (0.37)
- Geophysics > Seismic Surveying > Borehole Seismic Surveying (0.34)
- Geophysics > Seismic Surveying > Seismic Modeling (0.34)
Abstract A Jurrasic oilfield in Saudi Arabia is characterized by black oil in the crest and with mobile heavy oil underneath and all underlain by a tar mat at the oil-water contact. The viscosities in the black oil section of the column are fairly similar and are quite manageable from a production standpoint. In contrast, the mobile heavy oil section of the column contains a large continuous increase in asphaltene content with increasing depth extending to the tar mat. The tar shows very high asphaltene content but not monotonically increasing with depth. Because viscosity depends exponentially on asphaltene content in these oils, the observed viscosity varies from several to ~ 1000 centipoise in the mobile heavy oil and increases to far greater viscosities in the tar mat. Both the excessive viscosity of the heavy oil and the existence of the tar mat represent major, distinct challenges in oil production. Conventional PVT modeling of this oil column grossly fails to account for these observations. Indeed, the very large height in this oil column represents a stringent challenge for any corresponding fluid model. A simple new formalism to characterize the asphaltene nanoscience in crude oils, the Yen-Mullins model, has enabled the industry's first predictive equation of state (EoS) for asphaltene gradients, the Flory-Huggins-Zuo (FHZ) EoS. For low GOR oils such as those in this field, the FHZ EoS reduces to the simple gravity term. Robust application of the FHZ EoS employing the Yen-Mullins model accounts for the major property variations in the oil column and by extension the tar mat as well. Moreover, as these crude oils are largely equilibrated throughout the field, reservoir connectivity is indicated in this field. This novel asphaltene science is dramatically improving understanding of important constraints on oil production in oil reservoirs.
- North America > United States (1.00)
- Asia > Middle East > Saudi Arabia (0.48)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Oil sand, oil shale, bitumen (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- (4 more...)
Abstract It is fundamental to pilot and deploy IOR/EOR initiatives to improve recovery from petroleum reservoirs using cost effective methods, ensuring a continuous supply of production that would meet the ever-increasing demand for energy. Under-Balanced Drilling (UBD) technology proved worthy as a valuable initiative in the redevelopment strategy of a Giant Carbonate reservoir located in the Middle East. It improved well deliverability especially in low permeability reservoir zones. The strategy for this has been to deploy 3-4000 feet laterals to maximize reservoir contact to such tight units or drill as far as possible to have maximum flow input/productivity. Horizontalization (non-UBD), together with stimulation has been going on for many years with mixed success as recent production log surveys showed negligible contribution from several wells completed in these low permeability units. In 2011, well-X was drilled underbalanced to assess the value of this technology in augmenting productivity and improving reservoir characterization. Significant improvement in Productivity Index was accomplished by minimizing damage from drilling and completion operations. In addition, considerable knowledge was acquired from Flowing While Drilling (FWD) data and multi-rate tests in four segments of the production zone. Real-time geosteering was actively used to account for changes in the reservoir architecture. Analysis of the FWD data has derived in new understanding of the dynamic nature of the reservoir's South-central region, highlighting sectors of high permeability, fractures, tight areas, different pressure regimes and varying fluid composition. Furthermore, despite the innovative nature of the technology, drilling and completion was very well controlled by the Well Construction teams, resulting in costs not significantly higher than normal over-balanced wells. The enhanced reservoir knowledge that UBD delivers as shown from well-X will result in improved recovery efficiency and possible delayed water production. Moreover, it is a lead value improvement technology that will meet strategic business objectives with minimum risk and lowest Unit Technical Cost.
- Asia > Middle East (0.88)
- Europe (0.88)
- North America > United States > Texas (0.68)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (21 more...)
Challenges and Key Learning for Developing Tight Carbonate Reservoirs
George, Bovan K (Abu Dhabi Company for Onshore Oil Operations (ADCO)) | Clara, Cedric (Abu Dhabi Company for Onshore Oil Operations (ADCO)) | Al Mazrooei, Suhaila (Abu Dhabi Company for Onshore Oil Operations (ADCO)) | Manseur, Saadi (Abu Dhabi Company for Onshore Oil Operations (ADCO)) | Abdou, Medhat (Abu Dhabi Company for Onshore Oil Operations (ADCO)) | Chong, Tee Sin (Abu Dhabi Company for Onshore Oil Operations (ADCO)) | Al Raeesi, Muna (Abu Dhabi Company for Onshore Oil Operations (ADCO))
Abstract Fast track development projects, with timely data acquisition plans for development optimization, are very challenging for tight and heterogeneous carbonate reservoirs. This paper presents the challenges and key learning from initial stages of reservoir development with limited available data. Focus of this study is several stacked carbonate reservoirs in a giant field located in onshore Abu Dhabi. These undeveloped lower cretaceous reservoirs consist of porous sediments inter-bedded with dense layers deposited in a near shore lagoonal environment. The average permeability of these reservoirs is in the range of 0.5-5 md. Mapping the static properties of these reservoirs is difficult since they are not resolved on seismic due to the low acoustic impedance contrast with adjacent dense layers. Petrophysical evaluation of thin porous bodies inter-bedded with dense layers in highly deviated wells pose significant challenges. Laterolog type LWD resistivity measurements which are less affected by environmental effects, offer more accurate formation resistivity compared to propagation type measurements. With limited suite of logs, some of the zones with complex lithology had to be evaluated innovatively as detailed in the paper. Integrated studies are initiated to improve reservoir description by carrying out accurate permeability mapping, SCAL, geomechanical and diagenesis & rock typing studies. Significant challenges exist regarding the development of thin, tight and highly heterogeneous reservoirs, in terms of recovery mechanism, well architecture, well count, drilling, well completion and economics. Static and dynamic models were used extensively to evaluate different development scenarios and conduct sensitivity studies to bracket uncertainties. Various geo-steering options were discussed and the paper also details maximizing the reservoir productivity using long reach MRC (Maximum Reservoir Contact) wells. Tight and heterogeneous reservoirs call for extensive and real time reservoir surveillance activities to assess well performance and reservoir connectivity. This paper highlights how these challenges are overcome through upfront surveillance planning and proactive well completion strategy.
- Geology > Geological Subdiscipline > Geomechanics (0.88)
- Geology > Sedimentary Geology > Depositional Environment > Transitional Environment > Lagoonal Environment (0.54)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.47)
- Geophysics > Seismic Surveying (1.00)
- Geophysics > Borehole Geophysics (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > Asia Government > Middle East Government (0.46)
Summary The purpose of this presentation is to provide an efficient algorithm of AVAZ (amplitude versus angle and azimuth) inversion for elastic parameters and fracture fluid factor. Through analysis of the relationship between fluid factor and the reflection coefficient, a new reflection coefficient approximation equation with fluid factor and anisotropic gradient was derived. The accuracy of the AVAZ inversion algorithm was discussed. Synthetic data were used to validate the AVAZ method. Results on synthetic data showed that P-wave reflection coefficient (p), fluid factor reflection coefficient (g) and anisotropic gradient coefficient (G) can be estimated exactly without noise existing. The estimated P-wave reflection coefficient, fluid factor reflection coefficient and anisotropic gradient coefficient were still reasonable with the S/N ratio being 1:2.
- North America > United States (0.16)
- Asia > China (0.15)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Reservoir Description and Dynamics > Fluid Characterization (1.00)
Summary Hydrocarbon identification is one of the ultimate objectives of seismic prospecting and is greatly affected by the choice of fluid factor. Fluid factors have been investigated and applied extensively in the oil and gas exploration, and advanced our ability to discern the unknown subsurface fluid. However, none of the existing factors is perfect. Each of them has its own merits and demerits. Based on the documented methods, we introduce a new fluid factor that considers the general advantages of sensibility of Poisson impedance and the fluid factor presented by Russell et al. (2003). The proposed fluid factor is inspired by the definition of fluid factor angle, too. Thus, the fluid factor equals zero when it comes to water-bearing rocks and will be nonzero values when it comes to hydrocarbon-bearing rocks. The rock physical analysis indicates that the new factor is an effective tool for fluid discrimination. The promising results of the proposed fluid factor are illustrated through model test and real data example.
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Reservoir Description and Dynamics > Fluid Characterization (1.00)
Summary Near the west coast of India there is an oil field producing since last 51 years. The oil field consists of multi-layered Eocene sandstone reservoirs. The main reservoir layer was put on water flooding since 1966. The field has produced about 50% of the initial oil in place. The oil production has substantially declined in the field and now the water cut is more than 90%. The field has light oil with varying API between 45 to 47° API from bottom to top layers of the reservoir. Estimation of EOR potential in brown oil fields is an important input to the company in order to decide if large scale CO2-EOR is being planned. A good EOR potential (tertiary recovery) can extend the life of oil field for many years (typically 15-20 years). This paper shows the preliminary results from simulations of CO2 injection into a representative reservoir model of an onshore Indian oil field. Enhanced oil recovery (EOR) by CO2 injection is an attractive option because it has the potential to increase the oil, gas and condensate recovery of producing fields. The oil reservoir under study was under massive strategic and infill water flooding resulting in high recovery from the field. However, now the plan is to use more advanced tertiary recovery methods so as to increase the recovery. Using CO2 as injection fluid has several advantages. In case CO2 develops miscibility in the displacement front with the oil in-place when propagating through the reservoir at the reservoir conditions, then it enables miscible displacement of the targeting capillary trapped residual oil after water flooding (Per and Idar, 2010). The density of CO2 at reservoir conditions is in most cases lesser than the injected water and it may therefore reach other parts of the reservoir and consequently improve the sweep efficiency. The oil reservoir under study is Eocene sandstone reservoir primarily due to fluvial deposits. Representative live reservoir oil is composed to represent fluid properties of the oil. The Soave-Redlich-Kwong (SRK) equation-of-state EOS is used to characterize the crude oil and gas, to recombine the two and to calculate the phase behavior, the composition of the gas and liquid phases and the physical properties of the phases at relevant pressure and temperature conditions. The EOS model is based on compositional analysis of the stock-tank oil and gas samples from the field as well as fluid properties from laboratory analysis. A commercial software program PVTSim was used to build the EOS model, to tune the parameters and analyse the fluid properties. The oil field under study has 11 main producing layers, some of the good reservoir sands are further divided into sub-layers. Based on the laboratory and log data, representative petrophysical properties and fluid compositions have been used in the models. Different injection schemes including CO2 injection with and without recirculation of CO2 breakthrough gas and CO2- water-alternating-gas (WAG) have been evaluated.
- Asia > India (1.00)
- North America > United States > Texas (0.55)
- Europe > United Kingdom > North Sea (0.34)
- Asia > India > Rajasthan > Cambay Basin (0.99)
- Asia > India > Gujarat > Cambay Basin > Ankleshwar Field (0.99)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Fluid modeling, equations of state (1.00)
Summary Different structure of CO2 from hydrocarbon gases and oils has a significant impact on properties of CO2-oil miscible mixtures in comparison with "live" oil with dissolved hydrocarbon gases. We have systematically investigated velocity and density of CO2 with different oil (API) mixtures above their bubble point. The measurement condition is ranged with CO2 GOR up to 310L/L, temperature from 40°C to 100°C, and pressure from 20MPa to 100MPa. Based on our updated database we have developed preliminary models for the velocity and density of the CO2-oil miscible mixtures.
- Reservoir Description and Dynamics > Reservoir Characterization (0.95)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (0.90)