Viscoelastic surfactants (VES) are essential components in self-diverting acid systems. Their low thermal stability limits their application at elevated temperatures. The industry introduced new VES chemistries with modified hydrophilic functional groups, which enhances their thermal stability. These new chemistries are still challenged by the lack of compatibility with corrosion inhibitors (CI). This work aims to study the nature and the mechanism of the interaction between the VES and the corrosion inhibitors, which affects both the rheological and corrosion inhibition characteristics of the self-diverting acid system.
This study is based on rheology and corrosion inhibition tests, where combinations of VES and corrosion inhibitors are tested and complemented with chemical and microscopic analysis. Negatively charged thiourea and positively charged quaternary ammonium corrosion inhibitors were selected to study their impact on both cationic and zwitterionic VES systems. Each mixture of the corrosion inhibitor and the VES was blended in a 15 and 20 wt% HCl acid mixture, then assessed for its viscosity at different shear rates, CI concentrations, and temperatures up to 280°F in live and spent acid conditions. Each acid solution was assessed using Fourier-Transform-Infra-Red (FTIR) before and after each rheology and corrosion test to track the changes of the mixture functional groups. Each mixture was examined under a polarizing microscope to assess its colloidal nature. The corrosion inhibition effectiveness of selected acid mixtures was evaluated. N-80 steel coupons were immersed statically in the acid mixture for 6 hours at 150°F and 1,000 psi. The corrosion rate was evaluated by using metal coupon weight loss analysis followed by optical microscope examination for the metal surface.
The interaction between the CI and the VES surface charges and molecular geometries dictates both the rheological and the inhibitive properties of the acid mixtures. The use of a small molecular structure anionic CI with a cationic VES, results in a fine monodispersed CI particles in the VES-acid system. The opposite charges between the CI and the VES results in electrostatic attraction forces. Both the fine dispersion and the electrostatic attraction enhances the rheological performance of the mixture and packs the corrosion-inhibiting layer. The addition of a bulk and similarly charged CI with the VES results in a coarse polydispersed CI particles with repulsive nature with the VES. These properties increase the shear-induced structures and lower the packing of the inhibition layer deposited on the metal coupons, which decrease the rheological performance of the acid mixture and increase its corrosion rate. The FTIR analysis shows that there is no chemical reaction between the CIs and the VESs tested.
This work investigates the interactions between the corrosion inhibitors and the viscoelastic surfactants. It explains the impact of the surface charge of both corrosion inhibitors and VES on their rheological and corrosion inhibition characteristics. It adds a selection criterion for compatible VES and corrosion inhibitors.
Hydraulic fracturing has always been associated with significant volumes of fracturing fluid invading the formation matrix, which leads to water blockage and a reduction in relative permeability to gas or oil. In Shale and tight formations, this has become more challenging since capillary forces have profound impact on water retention and hence, water recovery and subsequent oil productivity. Surfactants and microemulsions have been extensively reported as flowback additives to lower surface and interfacial tension to maximize water recovery.
Most of the previous studies focused on a few testing methods to validate a surfactant or a microemulsion formulation for flowback use. In this work, a new environmentally friendly water-based surfactant formulation (Surf-I) was evaluated for flowback and its performance was compared against several industry standards of microemulsions and non-ionic alcohol ethoxylated surfactant. Surface tension (ST), interfacial tension (IFT), contact angle (CA), and coreflood tests were conducted in a wide range of typical field conditions of water salinity, temperature, crude oil type, and surfactant concentration. Core flow testing on 0.1-0.3 md Kentucky sandstone was conducted simulating oil reservoirs following constant-pressure flow schemes of 50-500 psi. Water recovery and oil productivity were determined for each pressure stage.
The new formulation showed a surface tension of 26 mN/m with CMC corresponding to a load of 0.1-0.3 gpt, depending on the water salinity. Interfacial tension measurements varied from 0.17 mN/m to 10 mN/m, depending on the crude oil type and temperature. Contact angle measurements indicated the surfactant ability to water-wet controlled substrates. The coreflood results confirmed the benefit of using surfactants for flowback versus non-surfactant cases, especially at low- to mid-pressure flow and. At 50 psi pressure difference, no oil was observed in the no-surfactant case. At 100, 250, and 500 psi the oil productivity with surfactant was 53, 22, and 20% higher than the base case. The results also showed that a formulation with ultra-low IFT (5E-2 mN/m), can initially recover substantial water volume but did not show a superior performance over the new formulation. The data obtained in this study can be used to identify the optimum criteria of a flowback additive in terms of surface tension, IFT, and wettability requirement to enhance water recovery and maximize oil productivity.
Surfactants have been used in the oil industry for decades as multi-functions additive in stimulation fluids. In hydraulic fracturing, surfactants and microemulsions have been extensively reported numerously as flowback additives to lower surface and interfacial tension to aid water recovery. Fracturing fluids invade the matrix during the fracturing, and if not recovered, leads to water blockage and a reduction to relative permeability to gas or oil. This problem is more challenging in low- permeability formations since capillary forces have more profound impact on water retention, and hence water recovery and subsequent oil productivity.
In this work, surface tension, interfacial tension, foam stability, sand-packed columns, and coreflood experiments were performed on a selected environmentally friendly water-based surfactant formulation. The performance of the surfactant of interest was compared to two commercial microemulsion and one non-ionic alcohol ethoxylated.
The results confirmed the benefit of using surfactants for flowback compared to non-surfactant case. Surface tension (ST) alone cannot be used as a selecting criterion for flow back. The alcohol exthoxylated, while reducing the ST to same level as the two microemulsions, showed very poor performance in packed column and coreflood tests. Although interfacial tension (IFT) seems to be more reasonable criteria, adsorption and emulsion tendency are other challenges that can hinder the performance of good surfactants with low IFT. Based on the data, a surfactant that lowers the IFT with the selected oil to below 1 mN/m is more likely to outperform other surfactants with higher IFT.
Friction reducers (FRs) represent an essential component in any slickwater-fracturing fluid. Although the majority of previous research on these fluids has focused on evaluating the friction-reduction performance of chemical components, only a few studies have addressed the potential damage these chemicals can cause to the formation. Because of the polymeric nature of these chemicals—typically polyacrylamide (PAM)—an FR can either filter out onto the surface of the formation or penetrate deeply to plug the pores. In addition, breaking these polymers at temperatures lower than 200°F remains a problem. The present study introduces a new FR that replaces the linear gel with an enhanced proppant-carrying capacity and reduced potential for formation damage.
Friction-reduction performance, proppant settling, breakability, and coreflood experiments using tight sandstone cores at 150°F were conducted to investigate a new FR (FR1). The performance of the new FR was compared with two different FRs: a salt-tolerant polymer that is a copolymer of acrylamide and acrylamido-methylpropane sulfonate (FR2), and a guar-based polymer (FR3). Different breakers were used to examine the breakability of the three FRs, including ammonium persulfate (APS), sodium persulfate (SPS), hydrogen peroxide (HP), and sodium bromate (SB).
The friction reduction of the new chemical was higher than 70% in fresh water or 2 wt% potassium chloride (KCl) in the presence of calcium chloride (CaCl2) or choline chloride. The presence of 1 lbm/1,000 gal of different types of breakers did not affect the frictionreduction performance. The friction reduction of 1 gal/1,000 gal of the new FR1 was also higher than that of the guar-based FR3 at a load of 4 gal/1,000 gal at the same conditions. The results show that the new FR is breakable with any of the tested breakers. Among the four tested breakers, APS is the most-efficient breaker. Static and dynamic proppant-settling tests further indicated a superior performance of FR1 for proppant suspension compared with a PAM FR (FR2). Coreflood experiments showed that FR1 did not cause any residual damage to the core permeability when APS was used as a breaker, compared with 10% and 9% damage when FR2 and FR3 were tested, respectively. Coreflood tests also showed that FR1 is breakable using SB with only 2.5% damage, whereas FR2 and FR3 resulted in 47% and 41% damage, respectively. The results also show that higher salinity does not affect the breakability of the new FR.
The proposed FR shows higher friction-reduction performance and better proppant-carrying capacity with no formation damage, compared with the conventional counterparts. Hence, FR1 is a viable choice for application in fracturing formations with proppants.
Friction reducers (FRs) are crucial components in any slickwater fracturing fluid. Revising the previous literature showed that the majority of research focused on evaluating the friction-reduction performance of these chemicals. Another important aspect, which a few studies addressed, is the potential damage friction reducers can cause, especially to low-permeability formations.
Friction reducers are polymeric in nature (typically polyacrylamide); therefore, they can either filter out onto the surface of the formation or penetrate deeply to plug the pores. Breaking these polymers at temperatures lower than 200°F remains a challenge. This work evaluates a non-damaging and breakable friction reducer that can be a replacement for liner gel with enhanced proppant-carrying capacity.
Friction-reduction performance, proppant settling, breakability, and coreflood experiments were conducted to investigate the new friction reducer (FR1) in terms of friction-reduction, breakability, and the potential damage it might cause to tight sandstone cores at 150°F. The results of the new friction reducers were compared against two conventional friction reducers; one polyacrylamide-based (FR2), and one guar-based (FR3). Different breakers were used to examine the breakability performance; ammonium persulfate (APS), sodium persulfate (SPS), hydrogen peroxide (H2O2), and sodium bromate (SB).
The friction reduction of the new chemical was always higher than 65% in both fresh water and 2 wt% KCl. The presence of calcium chloride did not affect the friction-reduction performance, compared to performance reduction in the cases of FR2 and FR3. The presence of 1 gpt of different types of breakers did not affect the friction-reduction performance, even for stronger breaker (friction-reduction performance was 67% with APS breaker comparing to 68.5 % with no breaker). The new friction reducer is easily breakable in the three tested breakers: ammonium persulfate, sodium persulfate, and hydrogen peroxide. Among the three, ammonium persulfate was the most efficient breaker. Static and dynamic proppant settling tests indicated a superior performance of FR1 compared to the other conventional friction reducer (FR2). Coreflood experiments showed that the new friction reducer FR1 did not result in any formation damage with APS breaker at low KCl concentration (5 wt%) and high KCl concentration (20 wt%). A 9% formation damage was observed at weaker breaker (SB), comparing to 47 and 41.5% damage when the other two conventional friction reducers FR2 and FR3 were tested, respectively. The proposed friction reducer has higher friction-reduction performance and better proppant-carrying capacity with no formation damage compared to the conventional friction reducers.
Viscoelastic surfactants (VES) have been used to replace polymer-based fluids as effective, cleaner, and non-damaging viscofying carriers in frac-packing, acid fracturing, and matrix acidizing. However, several limitations challenge the use of VES-based fluids including: thermal instability, incompatibility with alcohol-based corrosion inhibitor, and intolerance to the presence of contaminating iron. This work introduces a new VES-based acid system for diversion in matrix acidizing that exhibits excellent thermal stability and diversion performance in both low-and high-temperature conditions.
Rheology measurements were conducted on spent VES-acid system as a function of temperature (77- 300°F) at a pH of 4-5. The effect of acidizing additives on the VES viscosity was investigated. The additives included a corrosion inhibitor, non-emulsifier, iron-chelating agent, and iron-reducing agent. Single and dual coreflood experiments were performed using limestone core samples with an initial permeability range of 4-200 md and a permeability contrast of 1.5-55. Post CT-scan imaging was conducted to investigate the wormhole topography. The diversion characteristic of the new VES in the dual coreflood experiments was evaluated by the structure and the extent of wormhole propagation in the low-permeability core.
Rheological data for 15 wt% HCl spent VES-solutions showed a maximum viscosity of 200-800 over a temperature range of 150-170°F, depending on the VES concentration in the sample. Without acidizing additives, a minimum of 50 cP was obtained at 195, 230, 250, and 275°F at 4, 5, 6, and 8 vol% of the VES in solution, respectively. None of the tested acidizing additives had a negative impact on the VES viscosity. At 8% VES loading, the acidizing package was optimized such that a minimum of 75 cP was obtained at 300°F.
Dual coreflood experiments were conducted at 150 and 250°F, and the results proved the ability of the proposed VES to divert efficiently in limestone formations. Single coreflood experiments also confirmed these results. Coreflood data indicated that a range of permeability contrast of 4-10 is the optimum for diversion ability in terms of the final permeability enhancement of the low-permeability cores. The results revealed 18.6, 45.6, 82%, and infinity when the permeability contrast was 28.3, 14.4, 6. 3, 1.63, respectively. A dual coreflood experiment was conducted for two cores with a permeability contrast of 1.6 at 150°F. The VES-acid system in the presence of all acidizing additives exhibited divergent performance that exceeded the performance of the VES in the absence of additivies. These results prove the stable performance of the VES and the enhancement in viscosity response after addition of both the iron-control agent and the non-emulsfier, which resulted in less acid leakoff and better wormhole structure.
Friction reducers (FRs) represent an essential component in any slickwater fracturing fluid. While the majority of the previous research focused on evaluating the friction-reduction performance of these chemicals, only a few studies addressed the potential damage these chemical can cause to the formation.
Because of the polymeric nature of these chemicals (typically PAM, polyacrylamide), a friction reducer can either filter out onto the surface of the formation or penetrate deeply to plug the pores. In addition, breaking these polymers at temperatures lower than 200°F remains a problem. This work introduces a new and non-damaging friction reducer that can be a replacement for liner gel with enhanced proppant-carrying capacity.
Friction-reduction performance, proppant settling, viscosity, and coreflood studies were conducted with the following objectives: (1) investigate the effect of using the new FR on the permeability of tight sandstone formation compared to two conventional FRs, (2) test the performance of the new FR in different salinity environments from fresh to saline water, and (3) examine the effectiveness of breaking the new FR using different breakers.
The friction reduction of the new chemical was higher than 65% in fresh water or 2 wt% KCl in the presence of calcium chloride or choline chloride. The presence of 1 gpt of different types of breaker did not affect the friction reduction performance. The friction-reduction of 1 gpt of the new FR1 was higher than the guar-based FR3 at load of 4 gpt at the same conditions. The results also showed that the new friction reducer is easily breakable in any of the three tested breakers: ammonium persulfate, sodium persulfate, and hydrogen peroxide. Among the three, ammonium persulfate was the most efficient breaker. Static and dynamic proppant settling tests indicated a superior performance of FR1 compared to another conventional polyacrylamide friction reducer (FR2).
Coreflood experiments showed that the new friction reducer FR1 did not result in any residual damage to the formation permeability compared to 10 and 7% damage when the other two conventional friction reducers FR2 and FR3 were tested, respectively. Coreflood tests also showed that the new friction reducer is breakable using a weaker breaker such as sodium bromate with a minimum of 2.5% damage. The results showed that higher salinity did not affect the breakability of the new friction reducer.
West Dikirnis field is located in the Nile delta of Egypt. It contains a thin oil rim with a thick gas cap and strong water aquifer. It is considered the second oil discovery in the Nile delta after El Tamad Field (Operated by Petroceltic & El Mansoura Pet Co). The development of this thin oil rim is very challenging due to: 1) complexity of the fluid system (volatile oil, retrograde condensate gas cap gas), 2) complexity of the geology of the field (compartmentalization, fracturing, and rapid lithological variation), 3) high heterogeneity in reservoir properties (permeability ranges from 200 mD to 11 D), and 4) strong water drive.
This paper represents a case history of developing WD field. It presents a complete development plan of this thin oil rim and its rich gas cap and how to maximize liquid (oil & condensate and LPG) recovery through different stages by optimizing drilling/completion strategy, reservoir management, and production processing.
The production strategy of this field was put into phases. In the first phase, the thin oil rim reservoir was developed through vertical and deviated wells for the purpose of collecting geological and reservoir engineering data required for full field development. In this phase the simulation studies showed positive effects of recycling the produced gas into the reservoir gas cap for the purpose of maintaining the reservoir pressure and decreasing the liquid losses due to the expected retrograde condensation in the gas cap gas. This first phase has shown strong, but variable, aquifer effects on the production wells. It also showed a great deal of lithological variations within very short distances in the field. In the second phase, and to overcome the geological and aquifer heterogeneities, it was decided to develop the field with horizontal wells completed with ICD's (Inflow Control Devices). This type of development helped achieve the following: (i) overcome the geological complexity, and (ii) to keep the well away from the water table, (iii) control the water rise by gas cap gas recycling, and iv) normalize the water moving front towards the well bore by the use of ICD's. The studies have shown that the above strategy increases the oil recovery factor by about 50%.
In the third phase an LPG & Refrigeration project was constructed in order to maximize the liquid production from this field.
Currently, an EOR project is put in focus for further increasing of the liquid recovery from this field partly through vaporizing the remaining oil.
To understand the geophysical responses of shale oil/gas plays for identifying sweet spots, we use a rock physics relationship for calculating total organic carbon (TOC) from the Bulk density log (RHOB) and the ΔlogR separation techniques. The TOC values based on core/cuttings samples of wells are in the range of 7-10% and similar values are computed from the well log responses. Elastic properties of TOC-rich shale formation for computation of Young’s modulus (YM), Poisson’s ratio (PR) and brittleness from well-log-derived Vp,Vs and bulk density to understand the competency of the shale rock to frac for stimulation of reservoir. Average of absolute amplitude was extracted from P-impedance volume of 3D seismic data within the mapped “Hot Shale” pack to understand the relationship between acoustic impedance (AI) and the TOC at well locations and thus, use this analogy away from the structures in the basinal area. The impedance calculated directly from the relevant logs was cross checked with that extracted from the impedance volume. The low AI areas directly indicate high porosity rock which may be rich in kerogen identified as sweet spots.
Chelating agents have been used in the oil industry as iron control agents and scale removers, and recently as effective stand-alone stimulating fluids in matrix acidizing, especially for deep wells where using hydrochloric acid is restricted due its corrosion problems. The ultimate goal from using chelating agents is to create highly conductive wormholes that connect the formation to the wellbore. Glutamic acid diacetic acid (GLDA) is a new chelating agent that can be used for this purpose. The objective of this work is to study the reaction of GLDA with calcite and investigate the effectiveness of the created wormholes by both kinetics and transport studies that have been performed experimentally in the laboratory.
The reaction of GLDA with calcite was investigated by measuring the rate of dissolution using the rotating disk apparatus. The effect of initial pH (1.7, 3.8, and 13) and disk rotational speed (100-1800 rpm) on the rate of reaction was studied at 150, 220 and 300oF. Pink Desert limestone cores 1.5 in. diameter and 0.65 in. length were utilized. GLDA transport and its effect on wormhole creation were investigated in core flood experiments using samples of 1.5 in. diameter and 6 in. length. The cores were scanned using CT-scan before and after the injection of GLDA solutions into the cores. Core flood experiments were conducted at temperatures of 200 and 300oF.
The calcite dissolution rate was found to be a strong function of temperature and increased significantly by increasing the temperature from 80 to 300oF. Increasing the pH from 1.7 to 13 resulted in a reduction in the rate of dissolution. GLDA reacted with calcite by one of two mechanisms; hydrogen ion attack and calcium complexation reaction. The GLDA chelation ability (expressed as a percentage of the total rate of dissolution) decreased by increasing temperature, but was not affected much by changing the disk rotational speed.
Acid diffusivity was determined at pH 1.7, 3.8, and 13 and the data was used with core flood results to determine the Damköhler number. An optimal Damköhler number was found in all experiments that corresponds to a minimum pore volume required to breakthrough the cores. Increasing temperature or reducing the pH increased the optimum Damköhler number with a reduction in the minimum pore volume required to breakthrough.