Fracture height is a critical input parameter for 2D hydraulic-fracturing-design models, and also an important output result of 3D models. Although many factors may influence fracture-height evolution in multilayer formations, the consensus is that the so-called “equilibrium height belonging to a certain treating pressure” provides an upper limit. However, because of the complexity of the algebra involved, published height models are overly simplified and do not provide reliable results.
We revisited the equilibrium-height problem, started from the definition of the fracture stress-intensity factor (SIF), considered variation of layered formation properties and effects of hydrostatic pressure, and developed a multilayer fracture-equilibrium-height (MFEH) model by use of the programming software Mathematica (2017). The detailed derivation of SIF and work flow of MFEH model are provided.
The model is compared with existing models and software, under the same ideal geology condition. Generally, MShale (2013) calculated smaller height, and FracPro (2015) larger height, than the MFEH model. Most of the difference is attributable to the different interpretation of the “net pressure,” and the solving of the nonlinear equations of SIF as well. In the normally stressed case, they are both acceptable, although MShale is more reliable. The discrepancy is much larger when there is abnormally high or low stress in the adjacent layers of the perforated interval. The effects of formation rock and fluid properties on the fracture-height growth were investigated. Tip jump is caused by low in-situ stress, whereas tip stability is imposed by large fracture toughness and/or large in-situ stress. If the fluid density is ignored, the result regarding which tip will grow into infinity could be totally different. Second and even third and fourth solutions for a three-layer problem were found by Excel experiments and this model, and proved unrealistic; however, they can be avoided in our MFEH model. The full-height map with very-large top- and bottom-formation thicknesses shows the ultimate trend of height-growth map (i.e., when the fracture tip will grow to infinity) and suggests the maximum pressure to be used. To assess the potential effects of reservoir-parameter uncertainties on the height map, two three-layer pseudoproblems were constructed by use of a multilayer formation to create an outer- and inner-height envelope.
The improved MFEH model fully characterizes height evolution amid various formation and fluid properties (fracture toughness, in-situ stress, thickness, and fluid density), and for the first time, rigorously and rapidly solves the equilibrium height. The equilibrium height can be used to provide input data for the 2D model, improve the 3D-model governing equations, determine the net pressure needed to achieve a certain height growth, and suggest the maximum net pressure ensuring no fracture propagation into aquifers. This model may be incorporated into current hydraulic-fracture-propagation simulators to yield more-accurate and -cost-effective hydraulic-fracturing designs.
Asphaltene precipitation and deposition are major flow-assurance issues that can reduce or completely stop the production of oil wells. To evaluate the severity of asphaltene problems in an oil reservoir, various laboratory tests should be planned. In this paper, a stepwise experimental approach is proposed to assess the asphaltene issue in oil reservoirs. Taking representative oil samples downhole is the first step to accurate experimental investigations. In case the sample does not represent the reservoir status correctly, all the laboratory data—even with accurate measurement—could be misleading. Then, reservoir-fluid characterization and saturate/aromatic/resin/asphaltene (SARA) analysis should be performed for primary evaluations and asphaltene-stability screening. Asphaltene-onset-pressure (AOP) measurement indicates the point at which asphaltene comes out of the solution. After that, assessment of asphaltene-precipitation potential depending on production scenarios (e.g., depletion or gas injection) at reservoir conditions should be performed. Finally, the effect of deposited asphaltene should be characterized in the presence of porous media in terms of deposition amount and its consequent permeability impairment. Eventually, this approach is used for an Iranian oil reservoir.
This experimental approach, along with modeling and simulation of asphaltene precipitation and deposition, can be used as the best practice for assessing the asphaltene issue in oil reservoirs.
This paper highlights the care to be taken by an engineer while specifying and selecting a centrifugal compressor for carbon dioxide (CO2) compression.
With the increase in the levels of CO2 in the atmosphere, there is an increase in the popularity of capturing CO2 emitted from the large source points such as fossil-fuel power plants, steel mills, cement plants, and others before its release to the atmosphere and storing it in geological formations [also used for enhanced oil recovery (EOR) where possible]. The compressors used to transport and store the CO2 at such depths need to compress the gas from atmospheric pressure to the pressures on the order of 200 bar or more.
The critical temperature of CO2 is only 31.1°C, so the CO2 is generally transported and stored in a supercritical state. The thermodynamic properties of supercritical CO2 are considerably different from those of the other real gases that are generally compressed. Further, to achieve this supercritical state, the critical point of CO2 is crossed somewhere in the compression stage. Near critical point, the ideal-gas law will not hold for CO2. Moreover, there is a reduction in the choke margin of the compressor caused by the reduction of the sound speed in CO2, particularly near the thermodynamic critical point. Also, the CO2 compressibility and specific heats are not linear near the critical pressure and temperature. The impurities in the CO2 will affect further the thermodynamic characteristics of the working fluid. Also, the water content in the CO2 makes it extremely corrosive.
Considering all the aspects mentioned previously, specifying the CO2 compressor correctly in terms of the equation of state (EOS) to be used, the interstage pressures and temperatures to be maintained, suggesting the number of impellers per stage to maintain the desired flow coefficient, metallurgy to be selected and scheme of compressor dry gas seals, and others becomes all the more important and is described in the paper.
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.
A statistical study using extensions to the semiparametric survival analysis (SA) was applied to an individual component of an electrical-submersible-pump (ESP) system. Since its proposal in 1972, the Cox proportional hazards (CPH) semiparametric model (Cox 1972) has become the primary tool for regression analysis of censored data. However, CPH assumes that observations are time-independent and that censoring is noninformative.
With extensions to the standard CPH formulation, we demonstrate the analysis procedure by considering a specific component of an ESP system (a motor) such that informative censoring and time-dependent variables may be accommodated. We track this motor from its first deployment, and subsequent redeployments, in different ESP systems to provide an estimate of how its reuse affects ESP run life. Exploiting such model extensions, however, demands a more-involved analysis undertaking than is typical for conventional SA studies. Model limitations and applicability are also discussed.
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.
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.
Polymer flooding is a proven technology to improve sweep efficiency, while being one of the most economical enhanced-oil-recovery (EOR) processes. Partially hydrolyzed polyacrylamide (HPAM) has been widely used for polymer flooding. As the HPAM usage for EOR increases, the challenge of produced-water management is also raised because residual HPAM in produced water could increase oil content and unwanted viscosity in discharging or reinjecting the water. As the environmental standards and regulations get more stringent, it is difficult for the conventional methods to meet the requirement for discharge. Use of magnetic nanoparticles (MNPs) to remove contaminants from produced water is a promising way to treat produced water in an environmentally friendly way with minimal use of chemicals. The main attraction for MNPs is their quick response to move in a desired direction with application of an external magnetic field. Another attraction of MNPs is versatile and efficient surface modification through suitable polymer coating, depending on the characteristics of target contaminants. In this study, we investigate the feasibility of polymer removal with surface-modified MNPs and regeneration of spent MNPs for multiple reuse.
MNPs, in-house synthesized with prescribed surface coating, were superparamagnetic with an average individual particle size of approximately 10 nm. The removal efficiency of HPAM from water with the MNPs depended on the type and concentration of brines, concentration of amine-functionalized MNPs, surface coating of MNPs, molecular weight of polymer, and how many times the MNPs were regenerated and reused. Virtually 100% removal of HPAM from water was feasible, depending on the reaction conditions. The regeneration of spent MNPs, with pH adjustment to recover the reactive sites, maintained more than 90% removal efficiency for three-time repetitive usages.
The electrostatic attraction between negatively charged HPAM polymer and positively charged MNPs controls the attachment of MNPs to HPAM molecular chains; the subsequent aggregation of the now neutralized MNP-attached HPAM plays a critical role for accelerated and efficient magnetic separation.
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.