A carbon-dioxide (CO2) -foam enhanced-oil-recovery (EOR) pilot research program has been initiated to advance the technology of CO2 foam for mobility control in a heterogeneous carbonate reservoir. After a drop in drilling activity in recent years, the Haynesville shale has become a hot area for natural gas production in the US, and companies are looking to bolster their positions in the area. Top US seismic experts say they are keeping a watchful eye on ground shaking in the state as new concerns are raised in neighboring Texas.
This paper presents an analysis of a CO2-foam-injection pilot in the Salt Creek Field, Natrona County, Wyoming. A carbon-dioxide (CO2) -foam enhanced-oil-recovery (EOR) pilot research program has been initiated to advance the technology of CO2 foam for mobility control in a heterogeneous carbonate reservoir. Aqueous foam has been demonstrated to have promise in conformance-control applications. This paper explores the foaming behavior of a CO2-soluble, cationic, amine-based surfactant. A growing chorus of suppliers, researchers, and service companies is persuading US operators to re-examine their use of slickwater in shale plays and consider displacing it with carbon dioxide and nitrogen.
This paper covers the staged field-development methodology, including analysis and evaluation of various development concepts, that enabled the company to optimize both completion design and artificial-lift selection, reducing downtime and lowering operating costs by nearly 50%. This paper describes interpretation results of a 4D seismic-monitoring program in a challenging Middle East carbonate reservoir. A high-carbon-dioxide (CO2) carbonate gas field offshore Sarawak, Malaysia, is scheduled for development. Reservoirs in this region have an average clay content of 8%; more than 50% of this clay content is migratory illite, and 15% is migratory kaolinite. The First Eocene is a multibillion-barrel heavy-oil carbonate reservoir in the Wafra field, located in the Partitioned Zone between Saudi Arabia and Kuwait.
Ghawar vs. Permian Basin: Is There Even a Comparison? While some try to put the two enormous oil producers toe-to-toe, the best thing to do might be to understand why they are different. Take a quick look at some of the data points shaping upstream headlines and the movement of oil supplies around the world. Saudi Arabia is trying to push oil prices back up but US producers remain wary and uncertain. The First Eocene is a multibillion-barrel heavy-oil carbonate reservoir in the Wafra field, located in the Partitioned Zone between Saudi Arabia and Kuwait.
Burgan Marrat, a deep carbonate reservoir was transferred from exploration to development team for an accelerated production of the newly discovered oil. This multi-billion barrel reservoir is spread over 450 km2, has more than 40 faults, 8 compartments with large variation in oil-water contact and reservoir/fluid characteristics. The objective of this work is to understand the key uncertainties and quantify their impact on the reservoir offtake rate and oil recovery by conducting uncertainty assessment.
An interdisciplinary team identified the key uncertainty parameters expected to have significant impact on the reservoir development. The range and probability distribution law for each parameter was set considering the uncertainties due to limited measurements or variation in interpretations. A Response Surface Model (RSM) was created to evaluate the uncertainties by using a base dynamic model and applying an appropriate experimental design, which allowed to efficiently study the uncertainty space with a feasible number of simulations. Using the RSM, the primary effects and interaction between parameters were quantified to rank the uncertainties based on their impact on field production.
Key uncertainty parameters were identified including eight OWCs, six fault transmissibilities, horizontal and vertical permeability multipliers, and porosity multiplier. Latin Hypercube was found to be the appropriate Experimental Design for the study considering 17 parameters and the need of building a reliable RSM that includes interactions between them. The design recommended 155 simulation cases, which were prepared and submitted automatically by the software.
Multi-time Responses were analyzed qualitatively to identify the top 5 uncertainties having material impact on field production over 20 years considering 6 existing wells and 30 new well locations. The RSM quantitative evaluation showed three parameters (OWC2, OWC4 and OWC1) having a total effect on the response higher than 10%; followed by PERMX and OWC3 with less than 5%. The other 12 parameters have total effects less than 2%, and the interactions effect is less than 0.5% for any interaction between two parameters. Contrary to the intuition, none of the faults proved impact on the reservoir production.
The results prove very useful to make a right development and appraisal strategy in early life of the reservoir. The new well locations can be ranked and prioritized to optimize the development and effectively appraise the areas with high risks.
Uncertainty assessment has value throughout the life of the reservoir. However, this study indicates that its application in early life of the reservoir can bring immense value. An uncertainty analysis on the reservoir production helps in decision-making regarding the number of wells and their locations to reach a target production by managing the risks.
In-situ gelled acids have been used for acid diversion in heterogeneous carbonate reservoirs for more than two decades. Most of the gelled systems are based on an anionic polymer that has a cleaning problem after the acid treatments that leads to formation damage. This work evaluates a new cationic-polymer acid system with the self-breaking ability for the application as an acid divergent in carbonate reservoirs.
Experimental studies have been conducted to examine the rheological properties of the polymer-based acid systems. The apparent viscosities of the live and the partially neutralized acids at pH from 0 to 5 were measured against the shear rate (0 to 1,000 s-1). The impact of salinity and temperature (80 to 250°F) on the rheological properties of the acid system was also studied. The viscoelastic properties of the gelled acid system were evaluated using an oscillatory rheometer. Dynamic sweep tests were used to determine the elastic (G’) and viscous modulus (G") of the system. Single coreflood experiments were conducted on Indiana limestone cores to study the nature of diversion caused by the polymer-acid system. The impact of permeability contrast on the process of diversion was investigated by conducting dual coreflood experiments on Indiana limestone cores which had a permeability contrast of 1.5-20. CT scans were conducted to study the propagation of wormhole post acid injection for both single and dual corefloods.
The live acid system displayed a non-Newtonian shear-thinning behavior with the viscosity declining with temperature. For 5 wt% HCl and 20 gpt polymer content at 10 s-1, the viscosity decreased from 230 to 40 cp with temperature increasing from 88 to 250°F. Acid spending tests demonstrated that the acid generated a gel with a significant improvement in viscosity to 260 cp (at 250°F and 10 s-1) after it reached a pH of 2. The highly viscous gel plugged the wormhole and forced the acid that followed to the next higher permeability zone. The viscosity of gel continued to increase until it broke down to 69 cp (at 250°F and 10 s-1) at a pH of 4.8, which provides a self-breaking system and better cleaning. Coreflood studies indicated that the wormhole and the diversion process is dependent on the temperature and the flow rate. There was no indication of any damage caused by the system. The injected acid volume to breakthrough (PVBT) decreased from 2.2 to 1.4 when the temperature increased from 150 to 250°F.
The strong elastic nature of the gel (G’= 3.976 Pa at 1 Hz) formed by the partially neutralized acid system proves its suitability as a candidate for use as a diverting agent. This novel acid-polymer system has significant promise for usage in acid diversion to improve stimulation of carbonate reservoirs.
Gutierrez, Mary Ellen (Universidad Industrial de Santander) | Gaona, Silvia Juliana (Universidad Industrial de Santander) | Calvete, Fernando Enrique (Universidad Industrial de Santander) | Botett, Jesus Alberto (Universidad Industrial de Santander) | Ferrari, Jean Vicente (Universidade de Sao Paulo)
About half of the world's oil reserves are in carbonate reservoirs, and most of these formations are mixed-wet or oil-wet and fractured, with extremely heterogeneous porosities and permeabilities. Implementation of enhanced oil recovery (EOR) techniques in this kind of reservoir is essential to achieve peak oil production and increase the recovery factor. Chemical EOR (CEOR) processes have been studied for many years in carbonate reservoirs but are not usually economically viable. Surfactant flooding has been considered as one of the most promising techniques among the chemical recovery methods due to the capacity of some surfactants to alter the carbonate rocks' wettability. However, the process is economically feasible only when losses of surfactant caused by adsorption into the porous media are decreased. Adsorption of surfactants can be affected by the surface charge on the rock surface and fluid interfaces. In general, the adsorption of cationic surfactants on carbonates is lower in comparison with other surfactants. Nevertheless, the high cost of cationic surfactants compared to anionic ones has led to studies aiming to evaluate the injection of the latter in the presence of a sacrificial agent in order to reduce the adsorption caused by interaction between the negative charges of the surfactant and positive charges on the carbonate surface. This work aims to study the effect of the presence of two chemicals, normally applied as scaling and corrosion inhibitors, on reducing the static adsorption of an anionic sodium olefin sulfonate surfactant on a carbonate rock. Water soluble poly(sodium methacrylate) (PSM) and diethanolamine (DEA) were evaluated as sacrificial agents in concentrations close to their scaling and corrosion inhibitor functions, respectively, to verify their sacrificial role in a co-injection chemical scenario. Adsorption studies were carried out using a pulverized carbonate rock in which low-salinity water was used as the base medium. Aqueous stability tests were carried out, which made it possible to select the correct salinity for the solutions of surfactant. Surface tension measurements were used as an indirect approach to study the adsorption of the surfactant in the presence and absence of PSM and DEA. Individually, PSM presented the best performance in reducing the adsorption of the anionic surfactant, while the DEA showed an almost null effect. However, when the chemicals were mixed, a synergistic effect was observed. The performance of PSM can probably be attributed to a steric effect of an adsorbed layer of polymer. It will be shown that even at lower concentrations, co-injection chemicals which are used for targeting other issues, such as scaling and corrosion inhibitors, may play the role of a sacrificial agent in reducing the adsorption of anionic surfactants, which is a concern in application to carbonate reservoirs.
Carbonate reservoir matrix acidizing is commonly conducted with HCl. In these treatments, HCl acid is used to create conductive channels (wormholes) to enhance well productivity/injectivity. However, its use has been limited due to associated rapid tubulars corrosion and formation face dissolution, especially in deep hot reservoirs. Emulsified acid was used as an effective alternative to HCl, but it is associated with drawbacks such high friction losses and emulsion stability. In this paper, an aqueous single-phase retarded HCl alternative system was evaluated as an alternative to straight and emulsified acid fluids.
Coreflood experiments were conducted using Indiana limestone core plugs at 180 and 270°F. Computerized Tomography (CT) scan analysis was conducted on the core plugs before/after coreflood testing. Compatibility testing was conducted on prepared retarder acid recipes. ESEM, TGA, and ICP analysis was used to analyze prepared retarder acid recipes and associated solids. Turbiscan LAB was used to assess the stability of the retarded acid recipes.
The low pore volume to breakthrough (PVBT) values (i.e., 0.9-1.6) obtained from coreflood testing at 180 and 270°F, confirmed the retarded HCl acid recipes were effective to stimulate carbonate reservoirs. Compatibility testing showed presence of significant white precipitate. ESEM analysis showed the precipitates were rod-like crystals composed of mainly of Cl and high C with small amounts of N, O, Al and Mg. TGA results showed the major constituent of precipitate were organic-based materials. The precipitate was mainly H4EDTA and chloride. Despite presence of white precipitate at the core inlet, the effect on the performance of the retarded acid system was insignificant. CT scanning analysis of the plug samples before/after the coreflooding experiments showed that wormholes along the plug length with multiple branches were formed in all cases indicating the compatibility of the selected acid recipe.
Sokhanvarian, Khatere (Sasol Performance Chemicals) | Stanciu, Cornell (Sasol Performance Chemicals) | Fernandez, Jorge M. (Sasol Performance Chemicals) | Ibrahim, Ahmed (Texas A&M University) | Nasr-El-Din, Hisham A. (Texas A&M University)
Matrix acidizing is used for permeability and productivity enhancement purposes in oil and gas wells. Hydrochloric acid has been always a first choice due to so many advantages that it can offer. However, HCl in high pressure/high-temperature (HP/HT) wells is a concern because of its high reactivity resulting in face dissolution, high corrosion rates, and high corrosion inhibition costs. There are several alternatives to HCl, among them emulsified acid is a favorable choice due to inherent corrosion inhibition, deeper penetration into the reservoir, less asphaltene/sludge problems, and better acid distribution due to its higher viscosity. Furthermore, the success of the latter system is dependent upon the stability of the emulsion especially at high temperatures. The emulsified acid must be stable until it is properly placed and it also should be compatible with other additives in an acidizing package. This study presents the development of a stable emulsified acid at 300°F through investigating some novel aliphatic non-ionic surfactants.
This paper introduces new non-aromatic non-ionic surfactant to form an emulsified acid for HP/HT wells where the conventional acidizing systems face some shortcomings. The type and quality of the emulsified acid was assessed through conductivity measurements and drop test. Thermal stability of the system was monitored as a function of time through the use of pressure tubes and a preheated oil bath at 300°F. Lumisizer and Turbiscan were used to determine the stability and average particle size of the emulsion, respectively. The viscosity of the emulsified acid was measured at different temperatures up to 200°F as a function of shear rates (0.1-1000 s-1). The microscopy study was used to examine the shape and distribution of acid droplets in diesel. Coreflood studies at low and high flow rates were conducted to determine the performance of the newly developed stable emulsified acid in creating wormholes. Inductively Coupled Plasma (ICP) and Computed Tomography (CT) scan were used to determine dissolved cations and wormhole propagation, respectively.
Superior stimulation results with low pore volume of acid to breakthrough were achieved at 300°F with the newly developed emulsified acid system. The wormhole propagation was narrow and dominant compared to branch wormholes resulted from some of the treatments using conventional emulsified acid systems. The results showed that a non-ionic surfactant with a right chemistry such as suitable hydrophobe chain length and structure can form a stable emulsified acid.
This study will assist in creating a stable emulsified acid system through introducing the new and effective aliphatic non-ionic surfactants, which lead to deeper penetration of acid with low pore volume to breakthrough. This new emulsified acid system efficiently stimulates HP/HT carbonate reservoirs.
Acidizing in un-fractured carbonate reservoirs has been well studied through modeling and simulation. Since carbonate reservoirs are often naturally fractured, fractures should be modeled for realistic acidizing operations. We present adaptive enriched Galerkin (EG) methods to simulate acidizing in fractured carbonate reservoirs. We adopt a two-scale continuum model for the acid transport. The coupled flow and reactive transport systems are spatially discretized by EG methods. Fractures are introduced using local grid refinement (LGR) technique. Adaptive mesh refinement (AMR) is implemented around wormhole interfaces. Simulation results show that acidizing in fractured carbonate reservoirs is largely dependent on the fracture system while acidizing in unfractured carbonate reservoirs is mainly determined by operation parameters such as acid injection rate. Computationally, the proposed EG scheme has less numerical dispersion and grid orientation effects than standard cell center finite difference/volume methods. AMR is very efficient to track the wormhole growth and speed up acidizing simulations.