An advanced clarification process that was based on enhanced floc removal with magnetite and magnetic ballast [M2 Water Treatment’s Magnetic Ballast Clarification (MBC) system] was evaluated in a field study at a hydraulic-fracture wastewater disposal site in southwest Texas. In this process, suspended solids are chemically flocculated in the presence of magnetite, rendering dense floc particles that are also magnetic. Flocculated solids with high settling rates are removed by gravity separation. The settled solids are then removed by use of drum-styled magnetics. Magnetite is recovered and reused. Although technically called clarification, the MBC process is governed by magnetic flux as opposed to gravity forces, allowing for a much smaller unit footprint, a unit that is portable for mobile use, and more dynamic control compared with conventional clarification. Produced water from a total of nine wells was processed during a period of several weeks in July and August 2015 in a 5-gal/min (171-B/D) pilot unit. Most tests were operated at approximately 3.1 gal/min (106 B/D) for consistency with the highly variable wastes encountered. Treated water sufficiently met criteria for reuse on the basis of oil and grease (O&G), total suspended solids, and turbidity removal. The cost included two hypothetical treatment-plant sizes: a local processing unit plant (2,380 B/D or 100,000 gal/D) and a larger regional treatment system (11,900 B/D or 500,000 gal/D). Costs ranged from USD 0.79/bbl for the smaller treatment option to USD 0.22/bbl for the larger option, which included chemical costs and amortized (10 years) capital costs, installation, and labor. Estimates were based on assumptions for water requirements and treatment needs in the Barnett, Marcellus, and Eagle Ford shale plays, and included assumptions on freshwater availability, trucking costs, and treatment costs.
Hu, Yisheng (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University) | Mackay, Eric (Heriot-Watt University) | Vazquez, Oscar (Heriot Watt University ) | Ishkov, Oleg (Heriot-Watt University)
In waterflooded reservoirs under active scale management, produced-water samples are routinely collected and analyzed, yielding information on the evolving variations in chemical composition. These produced-water chemical-composition data contain clues as to the fluid/fluid and fluid/rock interactions occurring in the subsurface, and are used to inform scale-management programs designed to minimize damage and enable improved recovery.
In this interdisciplinary paper, the analyses of produced-water compositional data from the Miller Field are presented to investigate possible geochemical reactions taking place within the reservoir. The 1D and 2D theoretical model has been developed to test the modeling of barium sulfate precipitation implemented in the streamline simulator FrontSim. A completely 3D streamline simulation study for the Miller Field is presented to evaluate brine flow and mixing processes occurring in the reservoir by use of an available history-matched streamline reservoir-simulation model integrated with produced-water chemical data. Conservative natural tracers were added to the modeled injection water (IW), and then the displacement of IW and the behaviors of the produced water in two given production wells were studied further. In addition, the connectivity between producers and injectors was investigated on the basis of the comparison of production behavior calculated by the reservoir model with produced-water chemical data. Finally, a simplified model of barite-scale precipitation was included in the streamline simulation, and the calculation results with and without considering barite precipitation were compared with the observed produced-water chemical data. The streamline simulation model assumes scale deposition is possible everywhere in the formation, whereas, in reality, the near-production-well zones were generally protected by squeezed scale inhibitor, and, thus, the discrepancies between modeled and observed barium concentrations at these two given wells diagnose the effectiveness of the chemical treatments to prevent scale formation.
Al-Ruhaimani, Feras (Kuwait University) | Pereyra, Eduardo (University of Tulsa) | Sarica, Cem (University of Tulsa) | Al-Safran, Eissa (Kuwait University) | Torres, Carlos (University of Los Andes, Venezuela)
Slug-liquid holdup is a critical slug-flow parameter, which affects average liquid holdup and pressure gradient in pipes. Most experimental slug-liquid-holdup studies in the literature were conducted either by use of low-viscosity liquid for all inclination angles or high-viscosity liquid for horizontal and slightly inclined pipes, indicating a lack of experimental data for vertical flow of high-viscosity liquid. Therefore, the objective of this study is to experimentally and theoretically investigate the effect of oil viscosity on slug-liquid holdup in gas/liquid upward vertical flow, and to develop a new closure model to predict slug-liquid holdup in vertical pipes. In this study, experiments were conducted in a 50.8-mm inner-diameter (ID) vertical pipe for six oil viscosities: 586, 401, 287, 213, 162, and 127 mPa·s.
A new slug-liquid-holdup closure model derived from Froude and inverse viscosity numbers was developed in this study for high-viscosity-liquid two-phase upward vertical flow. The proposed model was validated against independent experimental data and showed excellent prediction for high-viscosity data. Furthermore, the proposed model was compared with existing models that take into account the viscosity effects showing better performance. The new model was incorporated in the Tulsa University Fluid Flow Projects (TUFFP) unified model (all versions; Zhang et al. 2003b), improving the prediction of pressure gradient and average liquid holdup for high-viscosity upward vertical flow.
Sun, Nana (Petroleum Engineering College, Xi'an Shiyou University) | Jiang, Huayi (Petroleum Engineering College, Xi'an Shiyou University) | Wang, Yulong (Petroleum Engineering College, Xi'an Shiyou University) | Qi, Aojiang (Petroleum Engineering College, Xi'an Shiyou University)
We consider the emulsion stabilized by organic base and compound surfactants too stable to separate automatically. To obtain an efficient demulsification technique, the influences of microwave-radiation, conventional-heating, and microwave/chemical methods on the demulsification of heavy-oil-in-water (O/W) emulsions were investigated separately. The results showed that as microwave-radiation time increased, the water-separation rate increased initially and then decreased; with increasing microwave-radiation power, the water-separation rate increased sharply first and then increased moderately; and for both microwave and conventional heating, a higher temperature did not imply a better demulsification effect. In addition, the demulsification efficiency was higher and the separated water was clearer by use of the microwave/chemical approach, which needs less demulsifier in a shorter time for O/W emulsion.
Reinsch, Thomas (GFZ German Research Centre for Geosciences) | Kranz, Stefan (GFZ German Research Centre for Geosciences) | Saadat, Ali (GFZ German Research Centre for Geosciences) | Huenges, Ernst (GFZ German Research Centre for Geosciences) | Rinke, Manfred (Geothermie Consulting-Engineering-Supervision) | Brandt, Wulf (Geothermie Consulting-Engineering-Supervision) | Schulz, Peter (H. Anger's Söhne Bohr- und Brunnenbaugesellschaft mbH)
During production of geothermal brine at the Groß Schönebeck research site, large and heavy solid particles accumulated within the cased reservoir interval of the production well. A wellbore obstruction at a depth of approximately 4100 m (13,452 ft) was caused by copper-, barite-, lead-, and iron-mineral precipitates with a size of up to 1 cm and elongated coating fragments from the production tubing with a length of up to 10 cm. After a failed reverse-cleanout operation by use of 2-in. coiled tubing (CT), lifting the fluid column within the drillstring (DS) was considered to be the most cost-efficient option to clean out the wellbore while simultaneously minimizing fluid invasion into the reservoir. Here, preliminary considerations for the operation and field observations are presented together with a monitoring concept. The field data are used to calibrate a hydraulic model that is then applied to understand hydraulic processes downhole. On the basis of the hydraulic considerations, aspects to optimize the cleanout efficiency are discussed.
Malhotra, Sahil (Chevron Energy Technology Company) | Merrifield, George T. (Chevron North America Exploration and Production Company) | Collins, Jye R. (Chevron North America Exploration and Production Company) | Lynch, Cynthia (Chevron North America Exploration and Production Company) | Larue, Dave (Chevron North America Exploration and Production Company) | Madding, Angela M. (Chevron North America Exploration and Production Company)
Coiled-tubing (CT) fracturing has been applied successfully in multistage vertical-well stimulation in the Belridge diatomite in the Lost Hills field. This same methodology was used to complete two northwest-trending horizontal wells drilled on the northeast flank of the Lost Hills anticlinal structure that targeted thinner, higher-oil-saturation strata separated by thicker lower-oil-saturation intervals. The target reservoir presents high-porosity, low-matrix-permeability, and low-Young’s-modulus Opal A diatomite.
The perforations were jetted by pumping sand slurry down the CT, and the fracture job was pumped down the annulus. The stages were isolated by setting sand plugs. Nine and twelve stages were pumped in the two wells, respectively. The perforation locations for different stages were selected in areas with high resistivity and inferred high oil saturations, an absence of hydraulic fractures from nearby wells, excellent cement bonding, and low intensity of natural fractures. These assessments followed logging-while-drilling (LWD) with gamma ray, induction-resistivity and azimuthally focused resistivity (AFR) (image) logs, and a cased-hole ultrasonic image tool (USIT) run with the aid of a tractor. The hydraulic fractures were monitored by use of surface tiltmeter sensors. Oil- and water-soluble tracers were pumped to determine the relative production contribution from the stages and fracture-fluid cleanup, respectively, from the stages. All the jobs could be pumped successfully without any screenouts. Challenges were faced in setting sand plugs and isolating stages. Large fracture widths and low leakoff into the formation led to difficulty in forming sand bridges at the perforations and concentrating sand in the wellbore for the plugs. Surface tiltmeters showed excessive fracture-height growth. Tracer results showed that 20 to 30% of the stages contributed to 50 to 60% of the production. Stages with higher treating pressures contributed less toward production. This could be attributed to near-wellbore tortuosity in these stages. Proppant flowback was encountered in one well, and after an effective cleanup, the production rose.
The study illustrates how integration of various aspects, such as completion design, fracture-pressure analysis, and diagnostics, combined with geologic and reservoir information can help in identifying challenges and finding potential solutions for hydraulic fracturing. The findings highlight that the technology most suitable for vertical-well stimulation might not be favorable for horizontal-well stimulation.
Scale-inhibitor (SI) squeeze treatments are applied extensively for controlling scale formation during oil and gas production. The current research involves phosphonate/metal precipitate studies in the context of precipitation-squeeze treatments. The main focus here is on the precipitation and solubility behavior of the SI_ calcium (Ca)_magnesium (Mg) complexes of HEDP (a diphosphonate), DETPMP (a pentaphosphonate), and OMTHP (a hexaphosphonate); these mixed phosphonate/divalent precipitates are denoted as SI_Can1_Mgn2, where n1 and n2 are the stoichiometric ratios of Ca and Mg to SI, respectively.
Precipitation experiments with SI_Can1_Mgn2 species were carried out over a temperature range of 20 to 95°C, while varying the Mg/Ca molar ratio over a wide range from all Ca to all Mg. These precipitates were formed in MgCl2·6H2O/CaCl2·6H2O brine solutions with appropriate molar ratios of metals, then separated from the supernatant by filtration. Subsequently, the solubility of the collected precipitate was found in a solution of the same Mg/Ca molar composition from which it was prepared. In this type of experiment, the solubility of the SI_Can1_Mgn2 precipitate without any respeciation is determined. In addition, another type of solubility experiment was carried out for a precipitate formed in a brine with one fixed Mg/Ca ratio; this was subsequently placed into a solution with different Mg/Ca compositions (from all Ca to all Mg). In these experiments, respeciation of the precipitate may occur.
We have been able to establish the solubility (Cs) of the precipitates of three SIs (HEDP, OMTHP, and DETPMP) as a function of both temperature and Mg/Ca molar ratio. It has been shown that the solubility of precipitate is in equilibrium with Mg and Ca concentrations in solution, and any change of these parameters leads to solubility variation. All phosphonate/metal precipitates become less soluble with increasing temperature and much more soluble with an increasing proportion of Mg. We have found that any change in Mg/Ca ratio of brine does lead to a redistribution of Ca, Mg, and SI concentrations in a given precipitate and bulk solution, and, hence, leads to some variation in the precipitate solubility.
Additionally, the inhibition efficiency (IE) of precipitated and then redissolved HEDP, OMTHP, and DETPMP SIs was tested and compared with the IE of industrial stock products. We show that, unlike polymeric SI precipitates, the inhibition activity of phosphonate SIs does not depend significantly on the precipitation process, and the IE of precipitated and redissolved SI_Ca and SI_Ca_Mg complexes is very close to that of the industrial stock solutions. These results can be used directly for modeling phosphonate precipitation-squeeze treatments, and the significance of these results for field applications is explained.
The injection of seawater into oil-bearing reservoirs for the purposes of maintaining reservoir pressure and improving secondary recovery is a well-established, mature operation. Moreover, the degree of risk posed by deposition of mineral scales (carbonate/sulfate) to the injection and production wells during such operations has been much studied. The current deepwater subsea developments offshore West Africa and Brazil have brought into sharp focus the need to manage scale in an effective way.
In a deepwater West African field, the relatively small number of high-cost, highly productive wells, coupled with a high barium sulfate scaling tendency upon breakthrough of injection seawater, meant that effective scale management was critical to achieving high hydrocarbon recovery and that even wells at low water cuts have proved to be at sufficient risk to require early squeeze application.
To provide effective scale control in these wells at low water cuts, phosphonate-based inhibitors were applied as part of the acid-perforation wash and overflush stages before frac-packing operations. The deployment of this inhibitor proved effective in controlling barium sulfate scale formation during initial water production, eliminating the need to scale squeeze the wells at low water cuts (<10% basic sediment and water). To increase the volumes of scale inhibitor (SI) being deployed in the preproduction treatments and so extend the treatment lifetimes, SI was also added to the fracturing gel used to carry the fracturing sand.
This paper outlines the selection methods for the inhibitor chemical for application in fracturing fluids in terms of rheology, retention/release, and formation damage, and presents the chemical-return profiles from the five wells treated (some treatments lasting longer than 300 days), along with the monitoring methods used to confirm scale control in the treated wells.
Many similar fields are currently being developed in the Campos Basin, Gulf of Mexico, and West Africa, and this paper is a good example of best-practice sharing from another oil basin.
Two-phase flow pattern is an important parameter for predicting pressure gradient and liquid holdup in mechanistic models, both of which are required to design and operate hydrocarbon production and transportation systems. Existing two-phase-flow mechanistic models have shown various degrees of discrepancy in predicting flow pattern and their transitions for immiscible laboratory-scale flows of gas and high-viscosity Newtonian liquids (mineral oil) caused by the additional complexity that a high liquid viscosity introduces to the two-phase flow behavior. The objective of this study is to improve the high-viscosity oil flow-pattern transition modeling in horizontal pipes for the stratified-smooth (SS)/stratified-wavy (SW) and intermittent/annular transitions. These two transitions were improved by introducing a liquid viscosity-dependent sheltering coefficient model, and a new high-viscosity liquid-level criterion, respectively. An additional objective is to investigate the existing inviscid Kelvin-Helmholtz (IKH), viscous Kelvin-Helmholtz (VKH), and Taitel and Dukler models for the stratified/nonstratified (S–NS) transition, and provide insights on their applications for high-viscosity oilflow patterns. A validation study of the proposed transition models is carried out with four laboratory-scale two-phase gas/oil flow-pattern experimental data sets covering a wide range of oil viscosities. The validation study revealed that the proposed SS/SW, and intermittent/annular transition models predicted the considered high-viscosity, horizontal flow-pattern data with more accuracy than the Taitel and Dukler and Barnea VKH S/NS models. Furthermore, the validation and comparison of IKH, VKH, and Taitel and Dukler S/NS models show that the IKH model is the simplest one that sufficiently predicts stratified flow for high-viscosity oil, especially for liquid viscosity above 100 mPa·s.
Short-term production and injection optimization are best approached from an integrated surface/subsurface perspective, recognizing that well performance is driven by competition for an existing network hydraulic capacity.
This paper presents a tool for real-time optimization (RTO) of water-injection systems at the scheduling time scale (i.e., days to months). Its development stemmed from the observation that operations such as pigging or shutting manifolds for rig activity might disrupt the injection network balance; hence, injectors would benefit from quick control readjustments. Furthermore, an existing network is not necessarily able to distribute available water where desired, and control compromises best found by an optimizer should be sought.
It is assumed that reservoir conditions are stationary, and injection targets at any level of granularity (well, reservoir segment, or field level) have been established based on subsurface requirements. By use of performance curves for each injector and either a simplified or a full-fledged network model, the algorithm finds a set of optimal well controls with a steepest-descent method implemented in Microsoft (2016) Visual Basic for Applications (VBA). The interface is spreadsheet-based, facilitating updates in well-performance data or changes in reservoir requirements. When needed by the algorithm, a third-party hydraulic-flow simulator able to balance the system from the injection modules down to the manifolds is called through an application programming interface.
A case study is presented, illustrating how the tool has been used to estimate the benefits of installing wellhead chokes on the currently more than 200 active injection strings of a giant oil field offshore Abu Dhabi.