bluuebunny/crossref_metadata_2025_split huggingface dataset:
Experimental Investigation of Oil Recovery From Siliceous Shale by CO2 Injection
Authors: Kovscek A. R. , Tang G. Q. , Vega B. 
Published: September 2008

Abstract
Enhanced oil recovery from fractured low permeability reservoir rock is challenging and while studied previously, significant challenges remain in improving the recovery factor. In many cases the reservoir has been pressure depleted and gas released from solution. In such cases, continuous gas pathways from fracture to the matrix may have been created aiding our ability to deliver gas to the matrix. Gas injection (i.e., CO2) then proceeds from immiscible to perhaps miscible conditions. The efficiency of gas transport to the low permeability matrix is limited by the presence of a gas phase in the matrix, injection pressure, and cocurrent or countercurrent flow conditions, among others.
This work presents the results of a series of experiments using low permeability (0.02 – 1.3 mD), medium porosity (30 – 40 %) siliceous shale reservoir core samples initially saturated with either: live oil, depleted to a pressure of 200-300 psi; or dead oil brought to near miscible conditions; followed by CO2 injection at pressures proceeding from immiscible to CO2 near miscible conditions. Two gas injection modes were used: CO2 flow across one face of the core (countercurrent flow) which intends to account for the diffusive transfer mechanism; and CO2 flow along the length of the core (cocurrent injection). The experimental setup was monitored using X-ray computed tomography that helped to visualize phase flow and distribution during the processes.
The incremental oil recovery caused by the immiscible CO2 injection ranged from 0-10% for countercurrent flow mode and from 18-25% for cocurrent flow mode, whereas for near miscible conditions the recovery was found to be 25% for the countercurrent flow mode and 10% for the cocurrent flow mode. Countercurrent recovery appears to be critically sensitive to the distribution of the gas phase near the fracture face. Oil recovery potential by CO2 injection into siliceous shale rock is challenged by low permeability, rock heterogeneities, distribution of oil within the rock matrix, but it is aided by the presence of continuous gas pathways that allow CO2 penetration into the matrix. Near miscible injection displays clear multiple contact miscibility; also countercurrent flow seems to exhibit a greater recovery under near miscible as compared to immiscible conditions.
Engineering and Geologic Characterization of Giant East Texas Oil Field: North and South Pilot Studies
Authors: Wang F. P , Ambrose W. A. , Hentz T. F. , Bonnaffé F. , Loucks R. G. , A John , G Katherine 
Published: September 2008

Abstract
East Texas oil field (ETOF), discovered on September 3, 1930, is the second-largest oil field discovered in the United States. It has produced 5.42 BSTB of 39° API oil from &gt;31,000 wells from lower Woodbine sandstones. Estimates of original oil in place (OOIP) have ranged from 6.8 to 7.5 BSTB. Based on a midrange OOIP value of 7.0 BTSB, current recovery efficiency is 77%, which is the highest of any giant oil field in the world. Two areas of the field, one in the north and the other in the south, were selected in 2007 for study of the primary engineering, geological and operational factors controlling recovery; for describing the detailed reservoir architecture; and for developing strategies for future exploitation.
The Upper Cretaceous lower Woodbine Group in ETOF, ~150 ft thick in the western downdip area, is truncated by a pre-Austin Chalk unconformity to the east. The Woodbine is composed of stacked, NE-SW-trending fluvial-dominated deltaic deposits, with dip-elongate distributary-channel sandstones pinching out over short distances into delta-plain and interdistributary-bay siltstones and mudstones. High-quality fluvial- and distributary-channel sandstones with average porosity and permeability of 25.2% and 2,098 mD, respectively, are the major producing lithofacies. The fluvial-channel sandstones that dominate the northern pilot area are laterally and vertically more continuous than the delta-dominated facies of the southern pilot area.
ETOF, with an average of 4.2-acre well spacing, is one of the most densely drilled fields. Production is supported by a active downdip aquifer. Major operating strategies have been downdip water injection, plugback, deepening for untapped intervals, and waterflooding in areas with poor reservoir quality as well as aquifer support. Its high-recovery efficiency stems from its high reservoir quality, low residual oil, favorable stratigraphic dip, effective aquifer support, stable water movement controlled by production rates.
Of the estimated 1.58 BSTB of remaining oil, only 70 MMSTB is likely to be produced under current operating techniques. However, a fraction of 410 MMSTB of remaining mobile oil may be produced by depositional-trend-guided deepening and water injection. The remaining approximately 1.1 BSTB of residual oil will only be produced by enhanced oil recovery methods. Because the reservoir is shallow and reservoir pressure low, CO2 flooding would most likely be immiscible. In addition, with most wells &gt;60 years old, well-bore leakage is an environmental factor that must be considered prior to CO2 injection.
New Flux Surveillance Approach for High Rate Wells
Authors: Tosic S. , Ehlig-Economides C. A. , Economides M. J. , Vincent M. C. 
Published: September 2008

Abstract
Wells in high permeability reservoirs requiring sand control are commonly completed either with a high permeability fracture (HPF) or a high rate water pack (HRWP). These prolific reservoirs are capable of delivering high production rates, but the downhole flow velocity becomes a limiting factor. The downhole velocity is one of the most important factors in completion failure. To determine a safe producing rate for prolific wells, the current best practice is to monitor flux to avoid completion failure due to screen erosion or destabilization of the annular pack. Flux is the flow velocity at a critical location in the completion: at the screen face to avoid screen erosion, or in the annular pack to avoid pack destabilization. The commonly applied method for mathematically estimating the flux from the mechanical skin relies on a number of parameters that cannot be uniquely quantified, including the proppant permeability, the proppant turbulence factor, and the fracture skin. The calculated flux is highly sensitive to these uncertain parameters. When the flux is overestimated, the well rate will be unnecessarily restricted. Underestimation of the flux risks completion failure.
Most practitioners assume values for uncertain parameters, calculate the flux, and back-calculate the number of flowing perforations. Sensitivity studies will show the potential pitfalls of this technique. Instead, this paper presents an alternative approach to determine the flux as the total flow rate divided by the flow area, which, in turn, can be related to the number of perforations effectively conducting fluid from the reservoir to the wellbore. For the HPF case, this means how many perforations connect the fracture to the wellbore, which is a function of the angle between the well trajectory and the far field plane of the hydraulic fracture. When the angle cannot be determined due to a lack of the necessary stress measurements or stress isotropy, the flux will be calculated based on the pressure drop across the perforation tunnels obtained from the mechanical skin. The method and its advantages over existing techniques will be demonstrated using field data from deepwater Gulf of Mexico (GOM) wells.
Measurement of Non-Wetting Phase Trapping in Sand Packs
Authors: Pentland Christopher H. , Al-Mansoori Saleh , Iglauer Stefan , Bijeljic Branko , Blunt Martin J. 
Published: September 2008

Abstract
We measure the trapped non-wetting phase saturation as a function of initial saturation in sand packs. The application of the work is for carbon dioxide (CO2) storage in aquifers, where capillary trapping is a rapid and effective mechanism to render the injected fluid immobile: the CO2 is injected into the formation followed by chase brine injection or natural groundwater flow that displaces and traps it. Current models to predict the amount of trapping are based on experiments in consolidated media; while CO2 is likely to be injected at depths greater than around 800 m to render it super-critical, it may be injected into formations that tend to have a higher porosity and permeability than deep oilfield rocks. We use analogue fluids – water and refined oil – at ambient conditions. The initial conditions are established by injecting oil into vertical or horizontal sand packs 1 m long at different flow rates and then allowing the oil to migrate due to buoyancy forces. The packs are then flooded with water. The columns are sliced and the residual saturation measured with great accuracy and sensitivity by gas chromatography. This method allows low saturations to be measured reliably. The trapped saturation initially rises linearly with initial saturation to a value of around 0.11, followed by a constant residual as the initial saturation increases further. This behavior is not predicted by the traditional Land (1968) model, but is physically consistent with poorly consolidated media where most of the larger pores can easily be invaded at relatively low saturation and there is, overall, relatively little trapping. The best match to our experimental data was achieved with the Aissaoui (1983) trapping model.
Current Status of Enhanced Recovery Techniques in the Fields of Russia
Authors: Shandrygin A. N. , Lutfullin A. 
Published: September 2008

Abstract
Russia is one of the main oil producing country in the world with very long history of the oil industry. In one's time in former Soviet Union a lot of attention was paid to oil recovery problems. Unfortunattelly the unfavorable economic climate of the late 1980-s and economic shocks during the period of well-known events in the country in 1990-s caused the rapidly decline of the number of new EOR projects. EOR technologies started to develop in direction of sweep efficiency improvement by cheap agents. Nevetheless by now the very intereresting EOR experience has been accumulated in the country. It is likely that EOR- produced oil in Russia has not already reached its peak level and that it will increase above the current production rates because of improvement of economic situation in the country on the one hand and increasing of mature fields on the other hand.
The paper presents an overview of EOR field experiences in former Soviet Union and Russia for the last 25 years, an analysis of recent efforts and discusses briefly on perspectives for conventional and new EOR methods. The main EOR experiences reviewed are chemical flooding (and flow diverting technologies in particular), gas injection, thermal recovery process, microbiological and unconventional EOR.
Correlation Between Microseismicity and Reservoir Dynamics in a Tectonically Active Area of Colombia
Authors: Osorio J. G. , Peñuela G. , Otálora O. 
Published: September 2008

Abstract
BP operates the Cusiana volatile oil field and the Cupiagua gas condensate field in the Andean Mountains foothills province of Colombia (Fig. 1.). In 1992, a permanent seismic network of ten surface stations was installed in Cusiana and Cupiagua to obtain data for seismic hazard models necessary for the design of field infrastructure. The network is now in its sixteenth year of continuous operation. Currently, an average of 1000 microseismic events per month is recorded. The resulting seismological dataset is of high quality covering a range of seismic magnitudes down to about 1.0 on the Ritcher scale.
Over time, the Cusiana-Cupiagua Seismic Network (CCSN) has been used for different purposes. During the past few years, it has become increasingly evident that the network and its data is an invaluable asset for evaluation of conditions relevant to production/injection operations within the reservoirs and adjacent areas.
From the reservoir characterization and production operation standpoints, microseismic monitoring (also known as passive seismic) has had two main applications in Cusiana and Cupiagua: (i) to identify production/injection induced high transmissibility pathways and their temporal variations, and (ii) to image the orientation, extension, complexity, and temporal growth of hydraulic fractures.
This paper is focused on the first of these applications: how microseismicity has been used as a surveillance tool to track movement of reservoir fluids away from the wellbore. A short description of the seismic network is provided. Then, the methodology for data interpretation is discussed. Finally, partial results are presented showing how microseismicity monitoring is being applied to: (i) assess transmissibility changes due to stress and pore pressure changes through time, (ii) identify potential reactivation of pre-existing weak planes, and (iii) calibrate numerical models to improve history matches.
Analysis of the data shows a strong correlation between reservoir dynamics and production induced microseismicity in Cusiana and Cupiagua Fields with great potential as a surveillance tool for improved reservoir characterization and management.
The Determination of Tested Drainage Area and Reservoir Characterisation From Entire Well-Test History By Deconvolution and Conventional Pressure-Transient Analysis Techniques
Authors: Du Kuifu 
Published: September 2008

Abstract
The classical formula for estimating radius of investigation (Rinv) is based on the radial flow equation, which in most practical cases does not correspond to the actual reservoir conditions. This work presents a generalization of calculating drainage area or radius to the entire well test history without any flow regime pre-requisites, which represents a significant improvement to the classical Rinv formula. The methodology is based on integration of two advanced techniques: a) conventional pressure transient analysis (PTA) based "shrinking-box" method and b) pressure-rate deconvolution algorithm. Five field examples are analysed in detail to illustrate practical applications of the methodology including the detailed procedures for computing the minimum tested areas under various reservoir geometries and establishing the noise tolerance (or uncertainty) levels for the two methods as well as how to select and fine-tune some key control parameters governing the outcome of the deconvolution algorithm. These field case studies demonstrate that both methods, if carefully used with the proposed procedures, can yield an equivalent Rinv value, thus a reliable and verifiable result, derived from the entire test history. They also show that the deconvolution technique can obtain more reservoir information from the same dataset than a single pressure buildup or drawdown period, resulting in enhanced reservoir characterization and reduced uncertainties of the interpretation.
Velocity Calibration for Microseismic Monitoring: Applying Smooth Layered Models With and Without Perforation Timing Measurements
Authors: Pei Donghong , Quirein John A. , Cornish Bruce E. , Ay Erkan , Zannoni Steve , Kessler Calvin , Pettitt Will 
Published: September 2008

Abstract
Theorectically, the perforation shot origin time T0 affects the accuracy of the inverted velocity structure, and therefore the accuracy of subsequent microseismic event locations. The origin time can be obtained from perforation timing measurements or estimated from the picked arrival times. In order to investigate the role of origin time in velocity calibration, we designed two inversion procedures. In procedure A, T0 is calculated during the Occam's inversion while T0 is set to its true value in procedure B. A grid search locator is applied on both inverted models to produce two locations. We constructed three synthetic P-wave velocity models and add normally distributed random noise to the synthetic arrival times of all models. The noisy synthetic data are piped through procedure A to obtain location A and through procedure B to produce location B. Graphical analysis show that location A is closer to the true shot location than location B although both are close to each other. If we remove the data noise and repeat the test, location B is closer to the true shot than location A. It was observed that the inverted location A is better in terms of the distance from the true location if using noisy data and location B is better if using noise-free data. This indicates that uncertainties due to data noise cause our inconsistent observation and implies that perforation timing measurements are not necessary and may actually result in a less accurate velocity model.
Production Improvement of Heavy-Oil Recovery by Using Electromagnetic Heating
Authors: Carrizales M. A. , Lake Larry W. , Johns R. T. 
Published: September 2008

Abstract
Heavy oil is produced primarily by reducing its viscosity using well-known processes such as steam injection, steamsoak, and in situ combustion. A recent technique for recovery consists of resistively heating the reservoir using electrical energy. Resistive heating can be particularly beneficial for reservoirs in which conventional steam operations are uneconomic.
Resistive heating is a special case of a more general form of heating based on electromagnetic energy (EM). EM has the following advantages over steam injection: it can be used to recover extremely heavy hydrocarbon, is not susceptible to heat losses through a wellbore, and its water requirements are far less than for steam. Compared to resistive heating, EM heats within the formation. Thus (for downhole generation) larger well spacing may be possible.
Although its potential was recognized in the late 70's, there are relatively few field applications of EM heating and even fewer engineering studies. The purpose of this paper is to examine how the performance response of EM compares to resistive heating.
This paper presents a model for single-phase flow to calculate the temperature distribution, and the productivity improvement obtained when an EM heating source (an antenna) is placed in a well. We consider both counter-current flow, in which the well with the antenna is also a producer, and co-current flow where the flow is opposite to EM energy flow. Flow is taking place concurrently with the addition of EM energy.
Steady-state solutions for counter-current flow showed a relative productivity index (PI) increase of 2.5 - 12.0 times cold oil production when the input power was varied from 20 to 150kw. A peak improvement occurred when the adsorption coefficient was between 1e−3 and le−1 m−1, which indicates that there is an optimum adsorption coefficient. Resistive heating is the special case of an infinite adsorption coefficient and the existence of an optimum suggests that EM heating can be more effective than resistive heating. For co-current flow, the improvement was even greater for the same input power. Calculated energy gains (the ratio of produced to injected energy) were in the 8 to 163 range; successful steam injection processes have gains of around 10.
Active Management of Five-Spot Water Flood Based on Continuous Reservoir Monitoring
Authors: Thigpen B. L. , Sakowski S. A. , Wang X. , Liu X. , Lee J. 
Published: September 2008

Abstract
Recently, the industry has seen an enormous increase in the amount of upstream data delivered with fine resolution and accuracy as provided by downhole monitoring equipment. Downhole measurements include distributed temperatures along the wellbore, wellbore pressure and temperature at discrete points, zonal flow rates, equipment performance data such as ESP operating efficiency, and downhole and surface chemical injection data. Even though the potential benefits of these measurements are recognized, practical models and processes that take full advantage of the actual data have not been well established.
Intelligent wells are gaining momentum in the oil and gas industry for production optimization, but utilization of this technology is limited to a single well or small group of wells, addressing somewhat localized optimization. Ultimate production optimization achieves higher reservoir recovery through incremental hydrocarbon production, and it needs a higher view than a well-centric approach. Considering that multiple intelligent wells comprise an intelligent field, all the data coming from each intelligent well should be brought together as input for a global optimization. This is analogous to bringing a fuzzy picture of a puzzle into focus as all the pieces fall into place. Similarly, to optimize a 5-spot waterflood, each well in the pattern should be intelligently controlled all the time and, in addition, they need to be optimized relative to each other so that the flood front movement is managed for maximum sweep efficiency. Optimization at this level is accomplished through an integrated use of reservoir/well modeling and real time data acquired through continuous downhole measurements. Measured data enables active model tuning, which in turn improves ongoing reservoir performance prediction. Sensitivity analyses find the optimal configuration of the intelligent wellbore components in injection and production wells that enables active waterflood front control.
This paper discusses methodologies used for the control mechanism, including a simplified reservoir model, continuous monitoring data, and a multi-well optimization process. Visualization and control of water flood efficiency, continuous tuning of the reservoir/well model, improved performance prediction and full utilization of real time data are some of the benefits from the process developed.
Debottlenecking and CFD Studies of High and Low Pressure Production Separators
Authors: Lee Joseph M. , Khan Rafiqul I. , Phelps Daniel W. 
Published: September 2008

Abstract
Efficient and effective oil/water/gas separation is required for success of many production operations. A major oil producer was experiencing difficulties with the oil/water/gas separation equipment on an offshore platform and improvements were required to meet both present and future production rates. Both HP and LP Separators on a major oil production platform were studied to determine the design limitations for foamy service and BS&W levels. CFD studies were completed to show the volumetric utilization and flow pattern improvements made with the design changes.
Both HP and LP separators showed substantial foam and poor efficiency due to poor inlet device design, plugging and other general vessel design limitations. Debottlenecking efforts determined that while the inlet device was somewhat ineffective, major improvements could be made from changes to perforated plate baffles, fluid level adjustments and weir placement and operations.
CFD calculations performed on both vessels indicated similar problems. The perforated plate baffles with improper design lead to counter current flow through the baffles making them less effective in flow control and distribution. Fluid level settings for the weir height affected the velocity differences between fluid layers and contributed to promotion of recirculation within the vessel, which lead to low volumetric utilization.
With adjustments to vessel internal equipment and changes to fluid phase levels, CFD calculations showed that overall vessel volumetric utilization was improved by 22% for the HP vessel and by 38% for the LP vessel. CFD results also showed the changes to the flow patterns accompanying these improvements.
Vessels with the proposed changes were operating effectively with substantially higher throughputs and meeting the expected BS&W levels for operations of the downstream oil processing equipment. Details about the vessel internals, flow properties and other changes required to accomplish these improvements will be discussed.