A new thickening system extends the temperature range of traditional viscoelastic surfactant-based fluids and provides additional downhole benefits. Based on a low-molecular-weight associative polymer, the thickener forms an associative gel with surfactants at elevated temperature. This results in a gel structure that can carry proppant. Recent laboratory work has shown that viscosity alone may not accurately assess proppant transport. Thus, the aim of this paper is to evaluate rotational and oscillatory measurements to determine the viscous and elastic properties of the fluid. In addition, dynamic and static proppant settling tests were conducted using a high-pressure/high-temperature visualization cell to confirm the effect of elastic properties on proppant settling. This combination of measurements can better predict whether the fluid can be applied successfully in the field.
Thirty-three different formulae across a wide polymer and surfactant concentration range were examined at temperatures up to 250°F. Also, the effect of other fracturing fluid additives, such as friction reducers and nonemulsifying agents, were examined. Finally, proppant-settling tests were conducted with three proppant types of the same size, but different density and shape at a range of concentrations.
Experimental results show that each formula had a certain operating temperature range where the elastic modulus dominates. A polymer-to-surfactant concentration ratio of 1.4 was found to give the widest working temperature range with the highest elastic characteristics; the same range also gives better proppant suspension. At temperatures less than 100°F, the viscous regime was dominant for all tested formulas. However at the same temperature, the elastic modulus increased with shear rate. This gives a good proppant-carrying capacity during dynamic conditions (mixing and injection) with a small pressure drop. The friction-reducing agent was found to have a tendency to reduce the operating temperature range. However, the nonemulsifying agent reduced the effect of the friction reducer and enhanced the performance of the fluid. Data obtained from this study can be used as a guideline for field treatment design.
Currently, many producing formations are carbonates and/or depleted sands that are characterized by highly permeable flow paths or vugs. Severe-to-total loss of drilling fluid in these formations is a major concern both from the drilling and reservoir damage perspectives. Conventional particulate Lost Circulation Materials (LCMs) such as acid-soluble ground marble may not effectively cure severe losses. Furthermore, since the application is in a producing formation, avoiding reservoir damage is a major criterion that any potential solution must satisfy. The ‘band-width’ of available solutions that are both efficient and reservoir friendly is narrow; leading to both high cost and potentially risky drilling practices.
A possible solution is an acid-soluble Right-Angle-Setting Composition (RAS-Co) developed to provide the industry with a more efficient solution for plugging and isolating producing zones that have high drilling fluid loss rates. RAS-Co is formulated from inorganic, nonhazardous powders and fluids mixed in freshwater or seawater. RAS-Co is engineered to be a low viscosity (18-30cPs) fluid containing small particulates allowing it to be mixed at the rig site and pumped through any drillstring configuration. It is designed to react at a specific bottomhole circulating temperature in a consistent and controllable manner with a ‘right angle’ set. Once it is spotted/placed in the suspected loss zone, it eliminates further fluid losses and formation damage. The small particle size distribution acts as a pore-bridging material while in the fluid state and the right angle set characteristic makes the material non-invasive to the formation and lets it be easily drilled or removed with acid. It can be used in zones with up to 300°F circulating temperature and tolerates up to 50% contamination with water or drilling fluids.
This paper describes attributes of RAS-Co along with successful field applications, which makes it an effective solution for controlling reservoir damage by stopping severe lost circulation events.
Significant production rate decline and a few ESP failures were observed in the Mangala field, onshore India, due to scaling. Scale inhibitor squeeze treatments were required to arrest the production decline and prevent additional ESP failures. The Mangala crude oil is extremely waxy, with a wax appearance temperature (WAT) of 62oC and a reservoir temperature of 65oC. This meant that prior to chemical application, fluids would have to be pre-heated to prevent wax formation and potential damage to the near wellbore area. The produced water chemistry included iron concentrations in the region of 5 - 15 mg/l, which was related to the presence of significant quantity of siderite within the formation and which could have resulted in potential formation damage due to iron dissolution when applying pre-selected acid-phosphonate inhibitors. Additionally, the formation is produced from long horizontal wells completed with stand-alone screens with inflow control devices (ICD). Chemical placement in the wells therefore proved to be a significant challenge, and treatments were designed to achieve placement across the water producing zones.
This paper describes the squeeze chemical selection for minimisation of formation damage risks associated with treatments in this particularly challenging case study, with WAT close to reservoir temperature and the presence of reactive iron minerals. The impact that these factors had on both chemical performance and on the potential applicability of the selected chemicals is discussed. The paper also discusses pre-conditioning treatments pumped in these wells to regain productivity. The work also demonstrates how a combination of laboratory testing and treatment modelling has been used to minimise the potential for formation damage while at the same time maximising chemical treatment of the water producing zones. The detailed mineralogy and heterogeneity of the reservoir formations, the impact of production conditions and elevated iron on the performance of the selected chemicals are all described as well as the selection of alternative generic chemicals which were not poisoned by the increased iron. Initial field treatments have been conducted and preliminary results will also be presented which concur with the chemical qualification and treatment design.
A comprehensive review and modeling of the natural and induced formation damage processes and their governing mechanisms involving the various aspects of gas-bearing shale reservoir formations is presented. The investigation and modeling efforts are carried out in several steps. First, the damage potential of shale formations containing large quantities of clay and nonclay inorganic, and organic materials, and natural fractures filled with cement and other debris is delineated. Second, the thermal, chemical, and stress interactions between the drilling and fracturing fluids of frequently used types are described. The various relevant processes and their fundamental mechanisms, including under/over balanced drilling, fracturing fluid disposition and retainment, wettability and nonequilibrium fluid transmission and spontaneous imbibition, swelling and fluidization, gas blockage occurring in extremely-low permeability shale porous media, are reviewed. These processes are described by phenomenological rate processes and the resulting modeling equations are solved simultaneously by a finite-difference-based numerical method. A number of representative case studies are considered and solved numerically. The results provide valuable insights into the nature of the shale-gas reservoir formation damage, indicating the significant roles of the different orders of magnitude rate processes and the thermal, chemical, and stress shocks causing formations damage during drilling, completion, and production. It is demonstrated by various numerical results that we can take advantage of the significant differences between the rates of occurrence of the adverse processes to effectively control, minimize, and/or prevent the shale-gas reservoir formation damage. This provides a scientifically-guided protocol for mitigation of gas-bearing shale formation damage.
Underbalanced drilling (UBD) with nitrogen gas has significantly reduced formation damage and well construction cost in tight and shale gas field development in North American. Excess production of formation water has hindered the application of this technology in several other resions. The rate of formation water production increases with the decreased bottomhole pressure achieved by UBD. Adding water to the injected nitrogen stream can moderate bottom hole pressure and thus mitigate the water production problem. Optimizing nitrogen and water injection rates to depress formation water production requires accurate prediction of water influx from the formations uder various drilling conditions. Currently there is no rigorous method that can be used to perform such a task with adequate accuracy. This paper fills the gap.
NODAL analysis technique has long been employed in oil and gas production engineering for oil and gas production forecast. This technique is introduced to the drilling engineering through predicting water influx rate and optimizing nitrogen gas and liquid injection rates in UBD horizontal gas wells. This paper presents analytical models and solution procedure that are necessary for performing NODAL analysis in nitrogen-UBD design. Inflow performance relationship (IPR) is established on the basis of horizontal well productivity models. The outflow performance relationship (OPR) is constructed using a close-form analytical solution for gas-water-solid 3-phase flow in annular space. The presented NODAL analysis technique can predict water influx rate with drilling time and thus cumulative water production under any nitrogen-UBD conditions. Use of the optimized nitrogen and water injection rates can minimize water influx rate and cumulative water production volume. These parameters can be used for selecting multiphase separators and produced-water reserve tanks. A case application of the technique is illustrated in this paper. This work provides drilling engineers a practical method to optimize nitrogen-UBD design for reducing the cost of drilling tight and shale gas wells.
Sopngwi, Jean-Jose S. (Marathon Oil ) | Gauthreaux, Alex (Marathon Oil ) | Kiburz, Daniel E. (Marathon Oil ) | Kashib, Tarun (Marathon Oil) | Reyes, Enrique Antonio (Halliburton) | Beuterbaugh, Aaron (Halliburton) | Smith, Alyssa L. (Halliburton) | Smith, Steve K. (Halliburton )
The Ewing Bank 873 (EW 873) field is an offshore mature field in the Gulf of Mexico that produces hydrocarbon from Pliocene stacked turbidite sands. Wells on EW 873 have experienced production impairment from formation damage caused by aluminosilicates, fines, and scale including calcium carbonate (CaCO3) and barium sulfate (BaSO4).
This paper discusses the results of the successful application of a new chelant-based Hydrofluoric (HF) acid to remove formation damage and optimize production on EW 873. Additionally, the paper also presents the chemical analyses of acid flow backs, as well as the methods that were used to characterize the formation damage. More importantly, the paper also focuses on the multidisciplinary research efforts that led to the development and successful application of the new chelant-based HF acid.
Throughout the research, analytical experiments and corefloods were performed with three different HF acid formulations on cores that contained acid sensitive clays, CaCO3 and BaSO4. Two formulations contained hydroxypolycarboxylic acids such as citric acid, and the third formulation was based on the new chelant HF acid which contained an aminopolycarboxylic acid. The new chelant-based HF acid proved to be the most effective formulation as it achieved the highest permeability increase and dissolved ions while mitigating precipitation. Furthermore, compatibility and corrosion testing indicated that the new chelant-based HF acid was compatible with both the reservoir fluids and metallurgy of EW 873 wells.
The development of this novel chelant-based HF acid highlights the potential of performing successful acid treatments where heterogeneous mineralogy including CaCO3 and BaSO4 are present.
In water injector wells, continuous injection can wash gravel from the annulus around the screen, especially when injecting above the fracture pressure. The voids created after the annular washouts are sometimes filled by an influx of formation sand during shut-in operations. This sand accumulation consequently reduces the injectivity when the injection operations resume. A technique to prevent gravel washout was needed to maintain sand control and injectivity throughout the life of these water injector wells.
We therefore designed a product to prevent gravel washout by reinforcing the gravel pack with an interconnected network of fibers. The fibers contain a layer on the outside that is activated by temperature, forming a bonded fiber network that locks the gravel in place. This technique can be used with any type of proppant. The key benefit is that the fibers can withstand cyclic loading of stress during the shut-in and re-start of injection operations, which typically happen several hundred times during the life of an injector well.
Our experimental study to test this new product showed that the drag force of injected water easily displaced the gravel in the annulus into the fracture, whereas gravel reinforced with fibers withstood the drag force even at high injection rates (e.g., 100 bbl/d per 0.5-in-diameter perforation). We performed several more experiments to evaluate the strength of the pack under cyclic stress conditions. After 30 cycles, the pack strength was unaffected. The fiber chemistry was also adjusted for compatibility with commonly used fracturing fluids and brines. We found that the fibers remained connected in an interconnected network even after long-term interaction with sea water. We also studied the interaction of fibers with screens and other downhole equipment that come in contact with the fibers during gravel placement. The laboratory results of that study showed that the fibers did not create any issues with proppant placement or tool functionality during the sand control operation.
Our experimental study showed that the fibers provided an effective solution for preventing gravel washout in water injectors, thereby ensuring that sand control and injectivity remain as designed for the life of the well.
Farahani, Mehrdad (Sharif University of Technology) | Soleimani, Rasa (Sharif University of Technology) | Jamshidi, Saeid (Sharif University of Technology) | Salehi, Saeed (University of Louisiana at Lafayette)
The effects of drilling fluid’s filtrate on formation damage have been plaguing the industry. Drastic decrease in production due to the damage in the pay zone has been reported in several occasions. This often is associated with uncertainties to predict filtrate invasion and lack of proper mud engineering design.
Invasion of solids and filtrate can be reduced to an acceptable level by the formation of low permeable filter cake. During the filtration process, particles of certain sizes bridge the formation pores and establish a base on which the filter cake can form. Particles considerably smaller than the pore opening may invade the formation. In addition, knowledge of the mudcake characteristics such as thickness, solid contents and also filtration rate of mud filtrate will help the drilling engineer to stay on good conditions especially during drilling pay zones.
Factors affecting filtration process are time, temperature and pressure. In this paper, an advanced analytical model and related laboratory experiments (Figure 1) are presented. The mathematical model estimates mudcake thickness and filtration radius in both static and dynamic conditions with consideration a radial system at constant temperature conditions. The mudcake thickness and permeability variation with time are also considered in the dynamic model.
Second, the results of the simulation will be compared with experimental data in order to verify the simulation results. And, finally, filtrate invasion under high pressure and high temperature are analyzed by digital images (Figure 2) and SEM where potential recommendations are made.
Increasing world demand on energy has encouraged the development of natural gas resources from a variety of sources. Tight gas is a major gas resource which accounts for 14% of the total gas resources in the world, including conventional (Total, 2012). Water blockage is considered a potential damage issue in tight gas reservoirs and motivated the initiation of this study.
A tight gas reservoir is a low permeability reservoir of less than 0.5 md which tends to have higher capillary pressure and higher irreducible water saturation than a conventional reservoir. Tight gas reservoirs also have smaller grains which signify the effect of water film around the grains on gas flow. The gas relative permeability in tight gas formations becomes more sensitive to liquid saturation due to the nature of its grains. As some of these reservoirs show conventional-like connate water saturation, this led to a hypothesis that these reservoirs have gone through a desiccating process and reduced the connate water saturation to a lower value than the irreducible value.
The objective of this study is to examine if water blockage is a potential issue by generating relative permeability curves and simulating different production cases with different water saturation settings. By looking at the well performance and water and gas recovery in these situations, a new understanding of tight gas performance is achieved.
The method used included creating a simulating generic model and setting the water saturations at different settings to see the effect of injecting water during drilling and hydraulic fracturing. Six cases were run with open flow and fixed downhole pressure.
The results show an effect on gas production by delaying production by 21 years in the open flow situation. The gas production is reduced up to 17.17% in the open flow mode. In addition, cases with different water saturation settings never recovered all of the injected water, and in fact, the degree of recovery is proportional to the degree of desiccation.
Lost circulation has plagued the industry since the beginning of drilling. Historically, severity of losses has been categorized based on the amount of barrels lost to the formation, i.e., seepage, partial, and total. Though helpful, this strategy doesn’t help understand the underlying drive mechanism(s) for losses and doesn’t provide enough data to propose a solution. The recently adopted category is focused on the lost-circulation mechanism based on the properties of the exposed formation; these
classifications are losses to 1) pore throats, 2) induced or natural fractures, and 3) vugs or caverns. This study provides an integrated workflow to predict expected losses for such classification/mechanism of losses.
Mud loss through fracturing is categorized based on fracture types, i.e., natural or induced fractures. Different models are used with respect to the fluid-loss mechanism in natural and induced fractures. These models take into account the effect of fracture breathing. In addition, mud loss through the pores on the wellbore and the fracture face is modeled based on formation and mud-cake filtration properties, coupled with the fracture losses. Losses to vugs/caverns are usually total losses due to very large openings in the rock; recommendations are provided on how to
control severe losses.
Lost circulation not only causes the adverse effect of mud loss itself; it can also lead to several other issues, such as formation damage, stuck pipe, hole collapse, and well-control incidents.The current industry trend is moving towards drilling more low-pressure zones, and lost-circulation planning is becoming a vital part of these projects. Knowledge of the type and the expected amount of mud loss can help engineers select the most appropriate and effective solution and preplan accordingly. This information also provides criteria to evaluate the effectiveness of the applied lost-circulation strategy. In this study we review LCM treatments, wellbore strengthening, MPD, and CwD as some of the most common remedial techniques.