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Collaborating Authors
Duan, Shengkai
Abstract Waterflooding can supply additional reservoir energy for producing substantial quantities of oil trapped due to limited displacement drive and poor sweep efficiency. However, water injection is not commonly used in the deepwater Gulf of Mexico (DW GoM) due to good primary recovery, drilling cost and facility limitations. In over 80 fields and 450 reservoirs, water injection program has been implemented in only 18 reservoirs in 13 fields, or less than 5% of potential waterflooding candidates. DW GoM mid-Miocene reservoirs are characterized by sparse well counts, over-pressured, and generally good rock and fluid properties. Rock compaction and moderate aquifer influx often provide moderate to good natural drive energy and oil recovery. Primary oil recovery averages 32% with the 80% confidence range between 16% and 48%. However, Paleogene reservoirs are characterized by deeper depth, high pressure, high temperature, complex geology, and rock and fluid properties. Estimated recoverable oil is only 10% of OOIP assuming primary production and limited natural drive energy. Water injection programs will be difficult to execute in tight, abnormally-pressured Paleogene reservoirs. Waterflooding of deepwater turbidites has accumulated many lessons and learns now, and a comprehensive understanding of the influence of depositional environment and injection into over-pressured, highly compacting rocks is necessary. This paper is a detailed examination of Pleistocene-to-Upper Miocene age turbidite reservoirs in the DW GoM under water injection. Issues on waterflooding these deepwater plays were reviewed in the context of geological setting and depositional environment. Despite many drawbacks that tend to oppose the implementation of a waterflooding in Paleogene reservoirs, this paper still proves that they are candidates for water injection programs under the rules of good production practice. Moderate oil recovery is suggested in highly compacting reservoirs with supplemental injection drive. Overall, waterflooding strategies have proven to be highly effective in achieving good incremental oil recovery from the deepwater Gulf of Mexico reservoirs.
- North America > United States > Texas (1.00)
- North America > United States > Gulf of Mexico > Central GOM (1.00)
- Phanerozoic > Cenozoic > Paleogene (1.00)
- Phanerozoic > Cenozoic > Neogene > Miocene > Middle Miocene (0.34)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > United States > Gulf of Mexico > Western GOM > West Gulf Coast Tertiary Basin > Alaminos Canyon > Block 857 > Great White Field (0.99)
- North America > United States > Gulf of Mexico > Norphlet Formation (0.99)
- North America > United States > Gulf of Mexico > Central GOM > East Gulf Coast Tertiary Basin > Viosca Knoll > Block 786 > Petronius Field (0.99)
- (85 more...)
Summary Water production is controlled by the size and distribution of water saturation around wells. A recent discovery shows that not employing hydrodynamic mixing in numerical simulators may underestimate the water transition zone (Duan and Wojtanowicz 2006). This paper reports continuing research into mechanisms causing expansion of the water-saturation transition zone (transverse dispersion) in a segregated flow of oil and water approaching a vertical well's completion. The mechanismsโincluding nonlinear flow, turbulence, shear rate, and flow baffling at grainsโall contribute to the instability of the oil/water interface, resulting in hydrodynamic mixing. Interface instability because of shearing rate has been demonstrated in our recent study on the Hele-Shaw model (Duan and Wojtanowicz 2007). In this paper, we mathematically model the effect of flow baffling and demonstrate transverse dispersion experimentally using a linear physical sandpack. A simple model of tortuous flow was developed to demonstrate the effect of two-phase-flow baffling in granular porous media. The model shows that the change in flow momentum of the two fluids at the point of collision with rock grains becomes the major factor causing water dispersion. A series of segregated-flow runs (top, oil; bottom, water) was carried out using a physical model packed with different porous media at a constant pressure drop. The runs were videotaped and analyzed for saturation distribution using a color-intensity-recognition software. The results clearly demonstrate onset of transverse dispersion of water into the flowing oil. Further dispersion, however, was overshadowed by the dimensional and end-point effects of the model. With a numerical estimation procedure, the initial dispersion rateโcomputed from the 1D flow modelโis the essential data needed to estimate total dispersion in radial inflow to wells.
- North America > United States (1.00)
- Asia (0.93)
Abstract Deepwater Gulf of Mexico oil fields (DW GoM) typically get modest ultimate recovery factors in the 10% - 35% range, because reservoirs tend to be small, deep, and complex. The remaining oil target for Improved Oil Recovery (IOR) is tempting large, with about 30 Billion Bbl estimated to be left in discovered fields at abandonment. Procedures on by-passed oil mechanisms analysis are based on analysis of field data compiled by Minerals Management Service, on data extracted from focused literature reviews, and on original work to analyze by-passed oil mechanisms and describe the remaining oil distribution in turbidite reservoirs of DW GoM. This paper describes a study on oil trapping mechanism, by-passed oil categories and their distributions. It is key part of study directed at recommending a select group of IOR processes for multi-million dollar research and development funding by Research Partnership to Secure Energy for America (RPSEA). The performance of 450 oil reservoirs in 83 deepwater Gulf of Mexico fields has been evaluated and characterized by geological setting, reservoir properties, and development constraints. The results have been used to estimate statistically the average oil recovery, prominent reservoir drive mechanisms, oil trapping due to structural and depositional complexity, and reservoir volume not connected to wells. The term "Trapped Oil Mechanisms" is used in this work to define the reasons for projected remaining oil in-place under current operating practices. In this paper we review the detailed assessment of several signicant reservoirs in two fields and then present the overall summary of trapped oil mechanisms for Neogene reservoirs in the deepwater Gulf of Mexico. The results of this work are being used to define IOR processes targeted at reducing the projected ROIP.
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.34)
- North America > United States > Gulf of Mexico > Western GOM > West Gulf Coast Tertiary Basin > Perdido Basin > Alaminos Canyon > Block 903 > Trident Field (0.99)
- North America > United States > Gulf of Mexico > Central GOM > East Gulf Coast Tertiary Basin > Mississippi Canyon > Block 935 > Europa Field (0.99)
- North America > United States > Gulf of Mexico > Central GOM > East Gulf Coast Tertiary Basin > Mississippi Canyon > Block 934 > Europa Field (0.99)
- (8 more...)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Conformance improvement (1.00)
- Reservoir Description and Dynamics > Reserves Evaluation > Estimates of resource in place (0.98)
Abstract Water production is controlled by the size and distribution of water saturation around wells. Reported in this paper is a continuing research into mechanisms causing expansion of the water saturation transition zone (transverse dispersion) in a segregated flow of oil and water approaching a vertical well's completion. The mechanisms - including non-linear (non- Darcy) flow, turbulence, shear rate, flow baffling at grains - all contribute to instability of the oil/water interface resulting in hydrodynamic mixing. Interface instability due to shearing rate has been demonstrated in our recent study on the Hele-Shaw model. In this work, we have evaluated the practical size of the mixing zone around wells, modeled mathematically the effect of flow baffling, and demonstrated transverse dispersion experimentally using a linear physical sand pack. The maximum size of the mixing zone was evaluated using the turbulence criterion and differential velocity for typical wells' inflow conditions. Critical dimensionless numbers for flow in porous media were used to determine the onset of transverse dispersion. The radial size of mixing zones was then correlated with fluid properties, water cut, and the effective area of well's inflow. A simple model of "bifurcated flow" was developed to demonstrate the effect of two phase flow baffling in granular porous media. The model shows that the change of flow momentum of the two fluids at collisions with rock grains becomes the major factor causing water dispersion. A series of segregated (top oil; bottom water) flow runs were carried out using physical model packed with different porous media at a constant pressure drop. The runs were videotaped and analyzed for saturation distribution using a color intensity recognition software. The results clearly demonstrate onset of transverse dispersion of water into the flowing oil. Further dispersion, however, was overshadowed be the dimensional and end-point effects of the model. With a numerical estimation procedure, the initial dispersion rate - computed from the 1-D flow model - is the essential data needed to estimate total dispersion in radial inflow to wells. Introduction At high production rates, non-Darcy flow displays a strong indicator that linear flow would change to nonlinear flow such as eddies. Non-Darcy flow coefficient ร (Forchheimer, 1901) is commonly regarded as a parameter of intrinsic properties of porous media to describe the intensity of the change. Al-Rumhy et al. (1996), Huang and Ayoub (2006), Haro (2007) and Ma and Ruth (1997) show that tortuosity and core heterogeneity are key factors inducing non-Darcy by In a water oil segregated flow (Figure 1), if the flow driven by inertia force diverts from the main flow across the W/O contact, transverse dispersion may occur. Considering capillary and gravity effects, criteria of transverse dispersion zone near wellbore was developed in this paper. Immiscible transverse dispersion, described here, is a mixing process caused by uneven concurrent laminar flow in porous media (Duan and Wojtanowicz, 2006). The mechanism of transverse dispersion is important for evaluating the size of mixing zone. Ma and Ruth (1997) and Greenkorn et al. (1964) presented how momentum theory explains dispersion using flow streamline diverting and converging in theoretical models and physical experiments in microscopic scale. A simplified bifurcated flow model associated the momentum balance theory is developed to demonstrate the stream distortion between water and oil flow in this paper. The solutions quantitatively described the fluid's diverted velocity and volume resulting from collisions. For water saturation distribution in macroscopic scale, a coefficient of transverse dispersion is used to describe the effect of mixing after series of mixing (Duan and Wojtanowicz, 2006). The coefficient could be calculated with experimental results.
- 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...)
Abstract Inaccurate modeling of fluid flow near-wellbores is commonly recognized as shortcoming of numerical reservoir simulators. After water breaks through, the well's inflow involves two or three fluids flowing at velocity exponentially increasing with reducing distance to the well. Understanding of the oil/water inflow to wells and possible improvement of its simulation is the objective of this study. Current commercial simulators disregard the effect of dispersion due to high flow velocity. They only consider effects of viscous and gravity forces, capillary pressure and sometimes Non-Darcy flow effects. We postulate that a process of transverse immiscible dispersion should be considered in evaluating the oil/water transition zone around a well and the production water cut. Transverse dispersion is a process of mixing two fluids in the direction perpendicular to the segregated flow of two phases. In the process, one phase enters the stream of another phase and contributes to the flow characters and the saturation distribution change. Away from the well where the flow velocity is low, the effect is small and overshadowed by the capillary pressure effect. It, however, may significantly increase as the two-phase flow is approaching well since the transverse dispersion coefficient is a function of velocity. Thus, at the well, transition zone size and distribution might be significantly affected by transverse dispersion resulting in water production larger than results of current simulators. In this paper, an analytical model of transverse dispersion in porous media is derived and used to study various factors influencing the dispersion. The results show that radial distance and mechanical dispersion coefficient are essential to transverse dispersion. It also shows that transverse dispersion controls transition zone growth at the bottom of well's completion where vertical gradient of horizontal velocity is the largest - up to 0.25 ft/s-ft. Introduction Before water enters the bottom of well completion, a localized cone is formed due to vertical pressure difference. At this stage, oil displacement with raising water cone is dominated by the fractional flow mechanism. Numerical and analytical predictions of the water cone interface have been compared showing relatively good agreements. After water enters the wellbore, or water breakthrough, saturation distribution of the two immiscible fluids (water and oil) play an important role in well production. A dynamic transition zone develops resulting in the change of total mobility. It has been found out that the expanding transition zone increases total mobility and reduces pressure drawdown. As a result, the inflow of fluids is improved but the oil inflow is reduced. In the previous work, a numerical model using a commercial simulator has been built in order to study the transition zone expansion and pattern, and to analyze how the transition zone is affected by different factors, i.e. fluids' properties, reservoir geometry and well completion. From our previous sensitivity study, response of the transition zone (in terms of its size, pattern and profile) to four parameters (factors) has been examined for 16 scenarios of well inflow conditions to find the main relations between factors and responses. The results showed a strong effect of oil viscosity and vertical permeability on production water cut. Production water cut (WC) hampers oil inflow or oil productivity. We have shown that oil productivity decreases substantially as water cut increases during the low-water-cut production period. Water cut, however, can't be accurately predicted by analytical methods. Based on our simulation results, there was no agreement in the numerical versus analytical predictions of "ultimate" water cut as the analytical model would over-estimate the WC value by order of magnitude comparing to the simulator. Thus, production water cut development should be further studied with a combination of analytical and numerical methods.
Summary Accurate predictions of heat loss and temperature profile in oil- and gas-production pipelines are essential to designing and evaluating pipeline operations. Although some sophisticated computer packages are available for such purposes, their accuracies suffer from numerical treatments and model-building skills of inexperienced users. A simple and accurate analytical heat-transfer model is highly desirable. This paper presents three analytical heat-transfer solutions for predicting heat loss and temperature profiles in pipelines transporting petroleum fluids. The three solutions consist of one steady-state-flow solution and two transient-flow solutions. The two transient-flow solutions are for startup mode and flow-rate-change mode (shutting down is a special mode in which the flow rate changes to zero). An application example is presented to illustrate how the models can be used in insulation design of an offshore pipeline. Introduction Heat transfer across the insulation of pipelines presents a unique problem affecting flow efficiency. Although sophisticated computer packages are available for predicting fluid temperatures, their accuracies suffer from numerical treatments because long pipe segments have to be used to save computing time. This is especially true for transient-fluid-flow analyses in which a very large number of numerical iterations are performed. Ramey (1962) was among the first investigators who studied radial heat transfer across a well casing with no insulation. He derived a mathematical heat-transfer model for an outer medium that is infinitely large. Miller (1980) analyzed heat transfer around a geothermal wellbore without insulation. Winterfeld (1989) and Almehaideb and Pedrosa (1989) considered temperature effect on pressure-transient analyses in well testing. Stone et al. (1989) developed a numerical simulator to couple fluid flow and heat flow in a wellbore and reservoir. More advanced studies on the wellbore heat-transfer problem were conducted by Hasan and Kabir (1994, 2002), Hasan, Kabir, and Wang (1997, 1998), and Kabir et al. (1996). Although multilayers of materials have been considered in these studies, the external temperature gradient in the longitudinal direction has not been systematically taken into account. Traditionally, if the outer temperature changes with length, the pipe must be divided into segments, with assumed constant outer temperature in each segment, and numerical algorithms are required for heat-transfer computation. The accuracy of the computation depends on the number of segments used. Fine segments can be employed to ensure accuracy with computing time sacrificed. Therefore, accurate heat-transfer equations of closed form are highly desirable. The objective of this study was to develop analytical solutions to the heat-transfer problems under various operating conditions. This paper presents three analytical heat-transfer solutions. They are the transient-flow solution for startup mode, steady-state flow solution for normal operation mode, and transient-flow solution for flow-rate-change mode (shutting down is a special mode in which the flow rate changes to zero). An application case is illustrated in which the model-calculated temperature profiles were used for insulation design.
- Asia (0.68)
- North America > United States > Louisiana (0.30)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.32)
This paper was part of a student paper session at the conference.This paper was included in the proceedings as STUDENT5. Abstract Well cement problems such as small cracks or channels can result in gas migration and lead to sustained pressure at casingheads (SCP). Regulations require removal of significant SCP while tolerating small SCP during production operations. However, SCP of any size must be removed prior to well plugging and abandonment (P&A) as it is believed that even very small leaks might lead to continuous emissions of gas to the atmosphere. In some wells, however, small gas leaks may diminish in time as the gas migration channels are plugged off by the gas condensate. Thus, the objective of this work was to develop a method for computing potential of self-plugging in wells with SCP using priciples of phase behavior and theory of two-phase flow in small channels. Introduction In the industrialized world, today, particularly over cities, air pollution is being contonously generated by smoke from automobiles, factories and hundreds of other sources. There are noxious gases like carbon monoxide, sulfur dioxide and oxides of nitrogen. Air pollution does millions of dollars worth of damage to human being and agricultural crops. The United States, with the world's largest economy, is also the world's largest single source of anthropogenic (human-caused) greenhouse gas emissions. Quantitatively, the most important anthropogenic greenhouse gas emission is carbon dioxide, which is released into the atmosphere when fossil fuels (i.e., oil, coal, natural gas) are burned. In addition to carbon dioxide, oilfiled production facilities are a source of natural gas emissions from gas dehydration units, leaking valves, gaslines and oil storage tanks.[1, 2, 3] Also, natural gas leaks may occur from tubing or casing string often due to poor thread connection, corrosion, or thermal-stress cracking[4] The Clean Air Act of 1970 categorized emission sources into two types: mobile source such as automobile, ships, airplanes and stationary emission source which includes refineries, well facilities, oil and gas tanks, etc. Also, with the direction of the act, EPA established National Ambient Air Quality Standards and calculation methods based on air concentration and emission rates to assess the risk of air pollution.[5, 6 7] For the oilfield production facilities, emission rates are computed using published values of emission factors - multipliers specific for the equipment installed in the facility. [8] There are no emission factors, however, for leaking petroleum wells. Considerable number of producing and abandoned wells with SCP constitute a potential new source of continuous natural gas emission from failed casingheads due to poor cementing and external gas migration. The gas migration in cement can be diagnosed with the SCP testing procedures involving casing pressure bleed-off followed with pressure buildup. The tests provide data for assessing gas emission rates - the first component of risk analysis. (The theory ofSCP testing, - developed at LSU - provides estimation of cement leak conductivity and gas source pressure - a two data needed for computing the emission rate.[9]) Another component is the continuity of gas emission, as some wells may cease to emit gas in time due to source depletion or self-plugging with condensate. In condensation, natural gas fractions turn into liquid when pressure and temperature drop below the dew point. The condition of gas condensation could be induced downhole in the cement channel by rapid pressure drop at the surface resulting from failure of containment (casinghead). If the channel is small, condensate liquid will block the gas flow and terminate gas migration. As the gas emissioin from wells may lead to different outcomes. there is a need to develop a method for predicting potential air pollution from the SCP wells. The method should provide prediction of emission rate and - more importantly - the well's potential for self-plugging, estimation of the flowing time and total gas volume emitted to the atmosphere.The method should be theoretically derived by coupling the PVT gas behavior with critical conditions for liquid blockage in the cement's flow channels.
- Government > Regional Government > North America Government > United States Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)
Abstract Accurate predictions of heat loss and temperature profile in thermal injection lines and wellbores are essential to designing and evaluating thermal operations. Although some sophisticated computer packages are available for such purpose, their accuracies suffer from numerical treatments and model-building skills of inexperienced users. A simple-and-accurate analytical heat transfer model is highly desirable. This paper presents three analytical heat transfer solutions for predicting heat loss and temperature profiles in thermal-insulated flow conduits. The three solutions consist of one steady state flow solution and two transient flow solutions. The two transient flow solutions are for start-up mode and flow rate change mode (shutting-down is a special mode where the flow rate changes to zero). Capability of the analytical model is investigated using a data set that is representative to a typical case of liquid flow in a small-diameter thermal pipeline. An application example is illustrated where the model-calculated temperature profile is used to identify the possible interval of asphaltene deposition in an oil well. The mathematical heat transfer model can also be used for predicting temperature distribution in offshore pipelines. Introduction Heat transfer across the insulation of pipelines and wellbores presents a unique problem affecting flow efficiency. Although sophisticated computer packages are available for predicting the fluid temperatures, their accuracies suffer from numerical treatments because long-pipe segments have to be used to save computing time. This is especially true for transient fluid-flow analyses where a very large number of numerical iterations are performed. Ramey was among the first investigators who studied radial heat transfer across a well casing with no insulation. He derived a mathematical heat transfer model for an outer medium that is infinitely large. Miller analyzed heat transfer around a geothermal wellbore without insulation. Winterfeld and Almehaideb considered temperature effect on pressure transient analyses in well testing. Stone et al. developed a numerical simulator to couple fluid flow and heat flow in a wellbore and reservoir. More advanced studies on the wellbore heat transfer problem were conducted by Hasan and Kabir. Although multi-layers of materials have been considered in these studies, the temperature gradient in the longitudinal direction has not been taken into account. Traditionally, if the outer temperature changes with length, the pipe must be divided into segments with assumed constant outer-temperature in each segment, and numerical algorithms are required for heat transfer computation. The accuracy of the computation depends on the number of segments used. Fine segments can be employed to ensure accuracy with computing time sacrificed. Therefore, accurate heat transfer equations of closed-form are highly desirable. The objective of this study was to develop analytical solutions to the heat transfer problem under various operating conditions. This paper presents three analytical heat transfer solutions. They are transient flow solution for start-up mode, steady flow solution for normal operation mode, and transient flow solution for flow rate change mode (shutting-down is a special mode where the flow rate changes to zero). Sensitivity analyses are run to investigate the capability of the analytical model using a data set that is representative to a typical case of liquid flow in a small-diameter thermal pipeline. An application case is illustrated where the model-calculated temperature profile with the model was utilized to identify the possible interval of paraffin deposition in an oil wellbore.