This work presents the conceptual development and experimental evaluation for a new technique to create blocking foams in matrix rock systems by the injection of the foaming agent dispersed in the hydrocarbon gas stream. This new technique aims at simplifying the operation and reducing costs for the deployment of EOR foams in gas injection based projects, and overcoming the disadvantage of limited reservoir volume of influence obtained in the SAG technique.
A systematic experimental work is implemented to investigate the effect of the dispersed chemical (surfactant) concentration and the gas velocity on the ability to create blocking foams at high pressure and temperature, and using representative consolidated porous medium and fluids coming from the Piedemonte fields in Colombia. The concept behind this new technique is the transfer of chemical foamer from the gas dispersion into the connate or residual waters present in the hydrocarbon reservoirs under exploitation, due mainly to the chemical potential derived from the contrast in chemical concentration between the dispersed phase and the in-situ water.
Results herein confirm that it is possible to create blocking foam by this technique in a consolidated sandstone core at residual oil and water conditions, after being submitted to a gas flooding displacement. This condition is obtained as far as the gas velocity is above a minimum threshold, and the concentration of the active chemical is above certain limit (138 ppm for this case). Successful experiments with foams created by gas dispersed surfactant showed much longer stability periods when compared with results from foams created by the SAG technique at much higher chemical concentration (2,000 ppm). Application of this foams technique was done in a field pilot. About 600 Bbls of foaming solution were dispersed in the hydrocarbon gas stream in one gas injector of a Piedemonte field (Colombia, South America). Gas injectivity in the well was impaired after two weeks of injection, and the oil production well influenced by this injector changed its performance showing incremental oil production and flattening of the gas oil ratio (GOR) shortly after the dispersed chemical injection period. This innovative foams technique could also be extended to other non-condensable gases at field operating conditions like CO2, Nitrogen, Air, and Flue Gas.
Rossen, William R. (Delft University of Technology) | Ocampo, Alonso (Equión Energía) | Restrepo, Alejandro (Equión Energía) | Cifuentes, Harold D. (Equión Energía) | Marin, Jefferson (Equión Energía)
The ability of foam to divert gas flow during a long period of gas injection in a surfactant-alternating-gas (SAG) foam process is important for the economics of foam-diversion processes for enhanced oil recovery (EOR). Here, we interpret field data from the foam test in the Cusiana field in Colombia (Ocampo et al. 2013). In this test, surfactant was injected into a single layer that had been taking approximately half the injected gas before the test; then, gas injection resumed into all layers. On the basis of the size of the surfactant slug injected and estimates of adsorption and of water saturation in the foam in situ, we estimate that the treated region extended approximately 5.3 m from the injection well; fortunately, the results to follow are not sensitive to this estimate. On the basis of the change in injection logs before the test and at Day 5 of the test, when approximately 30 pore volumes (PVs) of gas (relative to the volume of the treated zone) had been injected, foam still reduced gas mobility in the treated layer to approximately 11% of its pretrial value. We base this estimate on the decrease of injection into the treated layer and the increase of injection into the other layers; the results are consistent among the layers. After 35 and 152 days of injection (220 and 1,250 treatment PV of gas injected), foam reduced gas mobility in the treated zone to approximately 26 and 50% of its value before the test, respectively.
This result indicates that foam continued to reduce mobility by a modest amount even after long injection of gas. On the other hand, foam did weaken progressively as it dried out. Foam models in which foam remains strong at irreducible water saturation would greatly overestimate foam effectiveness at long times in this test.
In this test, the large volume of gas had quickly penetrated far beyond the edge of the surfactant bank. Mobility in the foam-treated region in this test, after passage of many treatment PVs of gas injection, mimics that very near the injection well in a process with a larger slug of surfactant.
Ocampo-Florez, Alonso (Equion Energia Ltd.) | Restrepo, Alejandro (Equion Energia Ltd.) | Rendon, Natalia (Equion Energia Ltd.) | Coronado, Jorge (Equion EnergÃa Ltd.) | Correa, Juan Alejandro (Equion EnergÃa Ltd.) | Ramirez, Diego Alejandro (Equion Energia Ltd.) | Torres, Monica (Equion Energia Ltd.) | Sanabria, Rosa (Equion Energia Ltd.) | Lopera, Sergio Hernando (Universidad Nacional De Colombia)
Foams have proved to be efficient to block temporarily high conductivity layers, and improving gas injection conformance and sweep efficiency in predominantly matrix reservoir systems, at least at lab and field pilot tests; nevertheless, its successful use in naturally fractured reservoirs has not been fully demonstrated as of today. This paper presents the evaluation process and the successful results for two (2) foam EOR field pilots performed in the Cupiagua in Recetor field; a gas condensate system whose main reservoir is a low porosity (<6%) quartzarenite with matrix permeabilities in the range of 0.01 to 10 mD, and where the fracture corridors are confirmed to play an important role both in well productivity/injectivity, and in the inter-well connectivity and gas channelling between gas injectors and oil producers.
The reservoir has been developed under massive hydrocarbon gas re-injection, and the current recovery factors of condensate are between 35-40%. The foam treatments were deployed in two gas injectors located in different areas of the field, each one impacting two oil producers, and exhibiting different levels of gas recycling, with GOR ranging between 40,000 and 100,000 scf/STB.
Both operations were performed via bull-heading using the SAG method. The results for both jobs showed a temporary reduction in gas injectivity, with slow recovery to its base line within the next 3 months. Despite showing little changes in the injection profile at the gas injectors, the two producers affected by the first job showed a clear change in GOR trends, and a consistent ramp-up in oil production rates during a period of at least 7 months, reaching a maximum increase between 15 and 30 % over their base line productions. The second job was performed to confirm consistency and repeatability of technology, and evaluate duration cycle of blocking and benefit effects. Early surveillance indicates positive response both at the gas injector, and the oil producers. Results herein presented, confirm the viability for foams as an EOR method for this naturally fractured field, and open EOR opportunities for other fractured reservoirs located in the same basin and exploited under gas injection schemes.
Rossen, William Richard (Delft University of Technology) | Ocampo-Florez, Alonso Alonso (Equion Energia Limited) | Restrepo, Alejandro (Equion Energia Limited) | Cifuentes, Harold D (Equion Energia Limited) | Marin, J. (EquiÃ³n EnergÃa Ltd)
The ability of foam to divert gas flow over a long period of gas injection in a Surfactant Alternating Gas (SAG) foam process is important for the economics of foam-diversion processes for enhanced oil recovery. Here we interpret field data from the foam test in the Cusiana field in Colombia, South America (Ocampo et al., 2013). In this test surfactant was injected into a single layer that had been taking about half the injected gas before the test; then gas injection resumed into all layers. Based on the size of the surfactant slug injected and estimates of adsorption and of water saturation in the foam in situ, we estimate that the treated region extended about 5.3 m from the injection well: fortunately the results to follow are not sensitive to this estimate. Based on the change in injection logs before the test and at day 5 of the test, when approximately 30 pore volumes of gas has been injected, foam still reduced gas mobility in the treated layer by about a factor of 9. We base this estimate on the decrease of injection into the treated layer and the increase into the other layers; the results are consistent among the layers. After 35 and 152 days of injection (220 and 1250 pore volumes gas injected), foam reduced gas mobility in the treated zone by about a factor of 4 and 2, respectively.
This result suggests that foam continued to reduce mobility by a modest amount even after long injection of gas. In this test, the large volume of gas had quickly penetrated far beyond the edge of the surfactant bank. In a design where a larger bank of surfactant were injected, a much greater and longer diversion of gas would be expected. On the other hand, foam did weaken progressively as it dried out. Foam models where foam remains strong at irreducible water saturation would greatly overestimate foam effectiveness at long times in this test.
Enhanced oil recovery by gas injection (CO2, hydrocarbon gas, N2 or steam) can be efficient in displacing oil where gas sweeps, but suffers from poor sweep efficiency because of geological heterogeneity, gravity segregation, and viscous instability between injected gas and resident fluids (Lake, 1989). Foam is a promising means to improve sweep efficiency in these processes (Schramm, 1995; Rossen, 1996). Field-trial data on foam effectiveness are relatively few (Hoefner et al., 1995; Patzek, 1996; Zhdanov et al., 1996; Turta and Singhal, 1998; Skauge et al., 2002). We report here on a field test of foam for diversion to correct for reservoir heterogeneity, and in particular on the long-time diversion achieved by a limited surfactant slug in this test.
Restrepo, Alejandro (Equion Energia ) | Ocampo, Alonso (Equion Energia) | Lopera, Sergio (Universidad Nacional De Colombia) | Coronado, Jorge L. (Equion Energia ) | Sanabria, Rosa B. (Equion Energia) | Alzate, Luis G. (Equion Energia ) | Hernandez, Sergio (Equion Energia)
The following paper is the continuation of SPE Paper 152309 (GaStim Concept - A Novel Technique for Well Stimulation. Part I: Understanding the Physics) and contains the experimental work and field pilot testing stages of the GaStimulation method already proposed by the authors. Systems studied correspond to tight quartzarenites containing retrograde gas condensates exhibiting Krg impairment under depletion. In this type of systems treatment penetration and durability are key factors for benefit sustainment. Supported by the theoretical background and preliminary lab tests presented in part I (SPE152309), the second stage of the GaStim project was planned and executed covering the phases of product´s screening, well candidate selection, pilots´ execution and results evaluation. Two pilots are reported, one in which water induced blockage is removed by stand-alone gas injection and another in which deep Gas + chemical dispersion is injected to reach a condensate blockage damage radius of 100 ft +. In the first scenario, it is noted that Sw reduction / Kg improvement is attained in the gastimulated area probably by coupled effects of evaporation and water slug displacement. In condensate blockage scenarios, it was noted that micellar type of surfactants exhibit the best performance when tested against IFT reduction capacity, Kg re-establishment (after condensate and water blockage) and treatment durability. Additionally, it was observed that the tuning of chemical concentrations and deployment method is key to maximize hydrocarbon flow capacity and minimize emulsion effects at surface after gastimulation. Further experimental work is planned to support modelling approaches both aimed on improving design criteria and expanding the potential of the technique into more challenging environments.
From theoretical work related to production mechanisms to the development and application of preventative and remedial technologies, water control has been and continues to be a broadly studied subject in the oil industry. Although the last word appears to be elusive and trial and error approaches have led to mixed results, there are recent encouraging advances especially in complex systems such as those related to fractures where water arrival can seriously compromise field development plans.
The present work focuses on the study of polymer based RPMs in different petrophysical systems. Laboratory tests at reservoir conditions are documented for homogeneous, macro fractured and micro fractured sandstone cores representative from fields located in Colombian foothills, where active tectonics and compositional fluids are present.
According to relative permeability mesurements taken before and after treatment, RPMs performance can widely vary depending on the type of rock and water saturation range. Results suggest that a critical Sw exists in macrofractured systems above which RPM "swithches" its behaviour promoting higher Kw. Although this effect is not noted in homogeneous nor microfractured cores, there seems to be higher benefits in the last one in terms of kw reduction and final recovery.
Observations derived from this study are now of key value for planning and executing field tests throughout subject fields allowing to clasiffy target areas and tune expected benefits based on laboratory results.
Water production is a natural and common aspect of almost every reservoir and its impact on project deliverability normally depends on production mechanism, aquifer or water source size, pressure and distance to producing horizons, petrophysical and fluids properties and lifting mechanism. Problems associated to wáter encroachment include but are not limited to Ko and Kg reduction by Sw increase inside the reservoir, poor lifting due to increased hydrostatic in production tubing and water management limitations or over costs. Several techniques have been proposed for wáter control; chemical or mechanical approaches are used depending on the working environment and problem severity. Among chemical systems, RPMs are of special interest given its broad spectrum of application in terms of environments and deployment options.
One of the advantages of RPMs when compared to other mechanical or chemical applcations is that they do not represent a serious compromise to hydrocarbon production after treatment injection. Even though and depending on chemical type, changes on PH, salinity and production drawdown can be induced after treatment affecting its efficiency and durability.
The following study summarizes a set of laboratory experiments conducted on quartzarenite reservoir cores petrophysically different. The performance of an RPM application was evaluated in homogeneous, artificially fractured (macro fractured) and microfractured reservoir cores. Testing protocol included the measurement of effective and relative permeabilities to water and oil.
Restrepo, Alejandro (Equion Energia Ltd.) | Ocampo, Alonso (Equion Energia Ltd.) | Rendon, Natalia (Equion Energia Ltd.) | Arenas, Magda (Ecopetrol S.A.) | Osorio, Raul (Nalco de Colombia, LTDA) | Reyes, David
Deliverability of gas and liquid hydrocarbons in retrograde condensate systems is highly affected by factors related to both reservoir characteristics and operative variables. It is well documented that pressure depletion coupled with tight petrophysical environments can lead to severe PI decrease due to liquid accumulation initially in the near wellbore area and then in the whole reservoir. Conventional approaches for condensate blockage removal have included the injection of low interfacial tension systems and alcohol blends to promote capillary forces minimization up to levels at which liquid bank gets remobilized. This type of solutions though, can be durability limited as liquid will reform once chemicals leave treated area. This condition become even more critical when
static reservoir pressure gets below dew point as liquids from non treated zone will rapidly imbibe into the treated zone decreasing durability even further.
The present work documents a field trial of a fluoro polymer technology aimed on Kro and Krg enhancement by rock wettability modification. This technique, as opposed to conventional chemistries working at the fluid-fluid interaction level, is aimed on altering rock`s original wettability. The objective is to promote a neutral wettability condition to minimize capillary effects driven by the contact angle according to LaPlace equation (fig 1). Through a "facts and gaps analysis", a set of root causes are presented to explain the high PI improvement (¬50%) but limited durability observed at field scale. Uncertainties on original rock wettability condition, water saturation profile in the near wellbore, deployment technique effectiveness and chemical properties of size and adsorption are all included in the root cause analysis. Data from pre job coreflood tests, pumping variables behavior and backflowed samples chemical analysis are also incorporated to the exercise. A final set of recommendations derived from the f&g analysis are to be included in further trials of the wettability modification technology where heterogeneous sandstone, compositional condensate environments are present.
Restrepo, Alejandro (Equion Energia Ltd.) | Ocampo, Alonso (Equion Energia Ltd.) | Lopera Castro, Sergio Hernando (U. Nacional de Colombia) | Diaz, Maria Paula (U. Nacional de Colombia) | Clavijo, Julian (Equion Energia Ltd.) | Marin, Jefferson (Universidad Industrial de Santander)
Well stimulation for production or injection enhancement in mature fields is a key and challenging task. Loss of reservoir energy due to pressure depletion coupled with complex damage scenarios existing in adverse petro physical environments can become restrictive factors for the proper performance of conventional liquid based chemical stimulation systems. Main limitations are normally related to high interfacial tensions preventing optimal well´s clean up and cost-effective achievable penetrations. This work presents a new well stimulation concept in which the carrying system is gas instead of liquid. The overall study will be presented in 2 parts. Part I will discuss basic physical questions related to treatment durability as a function of deployment method (continuous dispersion vs liquid batch gas displacement) for at least two damage scenarios of particular interest: asphaltene deposition and condensate blockage. A basic mechanistic simulation is also presented for benefit estimations at well scale. Part II will focus on field trials design and execution using micellar and/or fluoropolymer type of chemistries that exhibited the best performance when tested under laboratory conditions.
Experiments herein presented were done in formation sandstone cores simulating reservoir conditions. It is shown that natural gas when used as the carrying system to deploy conventional asphaltene dissolution and condensate removal chemistries enhances both Ko re-establishment and treatment durability as compared to equivalent liquid-based applications. Additional studies are being performed to maximize the effectiveness of the GaStim concept. Sensibilities to gas type (N2, CO2), added chemical and dosages as long as field trial documentation will be presented in part II of the present work. GaStim concept is presented as a novel chemical stimulation technique potentially allowing deeper penetrations and better chemical adsorptions. Its potential, although still not fully undiscovered, is certainly supported by higher Ko reestablishment values and longer treatment durabilities observed.
Restrepo, Alejandro (BP Exploration Colombia Ltd.) | Ruiz Serna, Marco Antonio (U. Nacional de Colombia) | Rendon, Natalia (U. Nacional de Colombia) | Lopera, Sergio Hernando (Universidad Industrial de Santander) | Rincon, Andres
Asphaltene deposition related damage is a well known phenomenon during production of highly under saturated volatile oil systems. It's modelling and control has been broadly documented although this last practice has been restricted to the near wellbore region where its impact seems to be maximum and where treatments can be effectively deployed.
The following paper presents a modelling approach for the estimation of the asphaltene deposition profile in highly under saturated volatile oil systems. This profile would allow predicting effective permeability loss as a function of pressure provided a set of asphaltene content measurements taken at wellhead through time. A simple asphaltene solubility model coupled with laboratory measurements are combined to propose a precipitation-deposition model that estimates expected k losses when thermo dynamical changes such as methane injection or pressure depletion are present. The output from the model which is a k function of pressure was incorporated into a single well model to match well's actual response after near wellbore dissolution treatments and after injection gas appearance in the drainage area. Laboratory tests consisted of core flooding experiments that allowed obtaining basic relationships between mass of asphaltene deposited and damaged Ko.
The present model was developed as a tool for benefit estimation if an asphaltene dissolution technique is applied at reservoir scale. The present approach is proposed as a simple and practical way of estimating asphaltene related damage in compositional volatile oil reservoirs.