Mixtures of HCl-HF, known as mud acid, have been extensively used in sandstone matrix stimulation. However, mud acid treatments were applied with poor success rate. This is mainly due to complex acid/rock interactions and other factors, such as the presence of HCl-sensitive clays and poorly consolidated formations. In addition, precipitation of reaction products of sandstone minerals dissolution in HF, especially at elevated temperatures, is another common factor limiting the mud acid effectiveness. These limitations associated with the use of typical HCl-HF mixtures warrant the use of organic-HF acids. These mixtures are used as an alternative to the HCl-HF blends to stimulate formations with HCl-sensitive clays and corrosion concerns. Various organic-HF blends have been extensively used; however, the studies of their interactions with sandstone rocks have been relatively limited. This work, for the first time, provides a systematic investigation of the chemical interactions of various sandstone minerals with three different organic-HF acids over a wide range of parameters.
Organic-HF systems based on acetic, formic, and citric acids were studied. Using static solubility tests coupled with chemical analysis of spent acid solutions, the dissolution of different sandstone minerals in each system was evaluated as a function of organic acid/HF weight ratio, reaction time, and temperature values of 50 and 75°C. The Scanning Electron Microscopy (SEM) and the X-ray fluorescence (XRF) techniques were used to explore the possibility of the presence of any precipitated reaction products.
Results based on this study showed that all organic-HF acids tested have a retarded nature with sand and clay minerals when compared to regular HCl-HF mixtures. In general, the dissolution of different sand and clay minerals in each organic-HF system is dependent on the type, ratio of the organic acid/HF used, and the temperature value. The reaction rate of different organic-HF acids with sand and clay minerals increased when the temperature value was increased from 50 to 75°C.
Findings based on this study addresses various chemical interactions and precipitation mechanisms involved with the reaction of organic-HF acids with sand and clay minerals. This work highlights the effects of the initial acid concentration, temperature, and soaking time on the performance of organic-HF acids. In addition, it provides new insights into the field application, and potential limitations of organic-HF acids.
Poor cleanup efficiency of injected fracture fluid (FF) has been considered as one of the main factors contributing to the poor performance of many hydraulically fractured wells (HFWs). Limited parametric studies evaluating the efficiency of FF cleanup have not embarked on a much needed extensive investigation of variation of all pertinent parameters.
In this work we present the results of over 130000 simulations of the process, for a HFW model that was constructed using a reservoir simulator. A computer code has been developed, which automatically, read input data, link the injection and production periods and create the output data. The impact of 16 parameters describing the gas and FF effective permeability of matrix and fracture, pressure drawdown, capillary pressure, and porosity have been studied for two injected FF volume values. Different statistical experimental design methods have been used to sample a reasonably wide range of variation of pertinent parameters. Linear and quadratic response surface models have been used to map the gas production loss (GPL), compared to 100% cleanup case.
The results indicate that GPL is mainly controlled by parameters related to FF cleanup inside the fracture particularly fracture permeability. In some cases increased back flow of FF from matrix into fracture increases GPL. As production continues, the impact of matrix permeability and gas exponent of Corey type relative permeability curve in the matrix become more pronounced. The fracture residual gas saturation and matrix gas end points have negligible effect. The relative importance of pertinent parameters is less for lower FF injection volume and especially at higher production periods. These practical findings can be used to make a better decision on the performance of such costly operations, suggested methods for improving the cleanup efficiency of FF and the optimum fracture design practices.
Near wellbore damage is often blamed for many production problems, it can manifest itself in many ways and is caused by almost anything that disturbs the formation; even producing hydrocarbons can lead to near wellbore damage. Knowing where the damage is and how it was produced can help prevent new occurrences, but oftentimes prevention is not possible. Perforation damage is one kind of damage that cannot be prevented; because the objective of perforating is to damage the formation by creating a tunnel as large and as deep as possible.
A new technique of consisting of producing controlled implosions constitutes the most effective way of removing perforation and other types of near wellbore damage, and this technique lends itself to provide quantitative values of well damage removal. This paper discusses how this new technique was developed, from concept and modeling to its effectiveness in the field as demonstrated by a number of jobs on wells with different types of damage. The results are extremely encouraging; in some wells production has increased by as much as three to four times, this production increase is sustained and the rate at which well formation damage occurs is significantly lower.
This paper presents field experiments conducted on four wells in the Libyan Desert, including logging data based on state of the art measurements, and giving new insights into near wellbore damage. Strategies are recommended to combat the effects of common near wellbore damage mechanisms and to address their root causes. These findings opened a debate that challenges some aspects of industry accepted perforation techniques, and presents conclusive evidence that some well damage is in fact beneficial.
Arora, Gaurav (BJ Services Ltd.) | Stolyarov, Sergey Mikhalovich (BJ Services Company) | Gupta, Anish (Cairn Energy India Pty. Ltd.) | Purusharthy, Naresh Kumar (Cairn Energy India Pty. Ltd.) | Mathur, Mohit (Cairn Energy USA) | Singh, Ratan (Cairn India Ltd.)
The Raageshwari gas field is a relatively deep (3000m) unconventional volcanic reservoir with a gas column in excess of 800 m. Gas from the Raageshwari field is used to generate energy for production of waxy, high-pour-point crude in the nearby Mangala, Bhagyam and Aishwariya fields (which were discovered in January 2004) in Barmer basin, Western Rajasthan, India (Figures 1, 2). The gas reservoir has inherently low permeability, and hydro-fracturing treatment is essential for optimum production from the field. A series of hydro-fracturing operations have been carried out on the field and treatments optimized over a period of time. A recent fracturing campaign implemented a shift in perforation methodology from conventional e-line perforation to peroration using sand jetting through coiled tubing. This paper discusses the challenges that had been associated with hydro-fracturing work in the field and benefits achieved with sand-jet perforation technology.
Reinicke, Andreas (Helmholtz Centre Potsdam GFZ) | Bloecher, Guido (Helmholtz Centre Potsdam GFZ) | Zimmermann, Gunter (GFZ German Research Centre for Geoscience) | Huenges, Ernst (Helmholtz Centre Potsdam GFZ) | Dresen, Georg (TerraTek a Schlumberger Company) | Stanchits, Sergei (Shell E&P Europe) | Legarth, Bjoern Alexander (Shell E&P) | Makurat, Axel
In context of this work, a new formation damage mechanism is proposed: the mechanically induced fracture face skin (FFS). This new mechanism results from mechanical interactions between the proppants and the reservoir rock, due to the increasing stress on the rock-proppant system during production. Proppant embedment into the fracture face and proppant crushing leads to fines production and may impair the fracture performance. In order to achieve sustainable, long-term productivity from a reservoir, it is indispensable to understand the hydraulic and mechanical interactions in rock-proppant systems. Permeability measurements on sandstones with propped fractures under stress using different flow cells were performed, allowing localizing and quantifying the mechanical damage at the fracture face. The laboratory experiments identified a permeability reduction at the fracture face up to 90 %. The mechanical damage at the rock-proppant interface begins immediately with loading the rock-proppant system and for fracture closure stresses below 35 MPa; the damage is localized at the fracture face. Microstructure analysis identified quartz grain crushing, fines production and pore space blocking at the fracture face causing the observed mechanically induced FFS. At higher stresses, damage and embedment of the ceramic proppants further reduces the fracture permeability. Numerical modeling of the rock-proppant system identified highly inhomogeneous stress distributions in the granular system of grains and proppants. High tensile stress concentrations beneath the area of contact between quartz grains and proppants are observed even at small differential stress applied to the rock-proppant system. These high stress concentrations are responsible for the early onset of damage at the fracture face. Therefore, even low differential stresses, which are expected under in-situ conditions, may affect the productivity of a hydraulically fractured well.
Design of an appropriate fracture geometry as well as placement of a sufficient proppant pack of the right proppant type is a key parameter to maintain long-term productivity. Proppant selection must consider appropriate hydraulic conductivity at in-situ stress conditions. Hydraulic conductivity is influenced by mechanical stress on proppant pack and rock-proppant interface, leading to proppant crushing and embedment as well as to a reduction of fracture width and fines production (Anderson et al., 1989). The production analysis often indicates a post-fracture well productivity that is significantly lower than expected from fracture characteristics simulations (Cramer, 2005, Romero et al., 2003). Hence, there is still a need for better understanding and investigating the complex mechanisms influencing the permeability alteration of rock-proppant systems.
Treatment failure can be commonly attributed to fracture damage processes, such as: poor clean-up after the treatment, alterations due to infiltration processes and precipitation, and mechanical damages like proppant pack failure (Economides, and Nolte, 2000). A wide range of laboratory, field, and theoretical studies cover the aspects of fracture damage mechanisms (Fredd et al., 2000; Wen et al., 2006; Behr et al., 2002; Nasr-El-Din, 2003; Moghadasi et al., 2002; Lynn et al., 1998). Cinco-Ley & Samaniego V. (1977) introduced a potential fracture damage mechanism, the so-called fracture face skin (FFS), which describes a fluid flow impairment along the fracture face. The FFS is a function of fracture length, reduced permeability and extent of damaged zone adjacent to the fracture face (Fig. 1). A FFS can be caused by a variety of effects like fluid-loss damage (Cinco-Ley and Samamiego-V., 1981), filter cake build-up at the fracture face (Romero et al., 2003), water blockage (Holditch, 1979) as well as liquid condensate (Wang et al., 2000).
Although there exists the mentioned fracture face skin models, mechanical effects have yet not been taken into account. We expect that the mechanically induced fracture face skin results from interaction between proppants and rock grains.
In the Llanos basin of Colombia, there are shallow, highly permeable, poorly consolidated sandstone reservoirs close to oil-water contacts. The Carbonera formation is typical—several small, highly permeable (600 to 3000 mD) producing sands, with poorly defined barriers. High production rates and low bottom hole flowing pressures (BHFP) result in water coning and sand production.
One solution is a stacked frac-pack completion.
In these applications, conventional cross-linked fracturing fluids have limitations. High polymer concentrations and viscosity are required to control fluid leak-off and create a sufficiently wide hydraulic fracture to admit proppant. High fluid viscosity has led to uncontrolled fracture growth into oil-water contacts, while the high polymer concentration decreases fracture conductivity and effective half-length.
A linear fluid comprised of polyacrylamide and polysaccharide polymers has proved an effective solution. The polyacrylamide greatly enhances fluid efficiency and elasticity, while reducing friction pressures and horsepower requirements. Fluid elasticity ensures adequate proppant transport. Fluid efficiency is determined by the polyacrylamide concentration and adjusted to achieve the required fracture geometry. The use of this fluid along with a geomechanical model and pseudo 3D fracturing simulator ensures that the propped fracture remains within the producing sand, with increased effective fracture half-length and conductivity. The polyacrylamide reduces the effective permeability to water and limits potential conning, when the well is produced.
Wells completed with frac-packs using the linear fluid produce an average of 1420 bbl/day of fluid with 20% water-cut. The fluid efficiency during the treatments varies between 30% and 15% as a function of permeability. Offset conventionally gravel packed wells with a lower bottom hole flowing pressure (BHFP) average 980 bbl/day of fluid with 60% water-cut.
Frac-packs, using an efficient linear fluid together with a geomechanical model and a pseudo 3D fracturing simulator have greatly improved the economics of producing these highly permeable reservoirs—maximizing production and recoverable reserves, while minimizing water production.
Viscoelastic surfactant (VES) based self-diverting acid system has been developed for better matrix treatment of carbonate formations. Literature survey indicates that the highly viscous fluid acts as a temporary barrier to reduce further fluid loss into the wormholes and allows complete stimulation of all treating zones. After acid treatment, the viscous fluid is broken by either formation hydrocarbons or pre-flush fluids. However, recent lab work confirmed that a significant amount of surfactant was retained inside the core even when mutual solvent was used. The present study was conducted to better understand these acid systems and determine factors that impact their viscosity build-up and performance inside the carbonate formations.
A series of coreflood tests were conducted using carbonate cores at different injection rates. Propagation of the acid, surfactant, and reaction products inside the cores was examined in detail. Samples of the core effluent were collected and the concentrations of calcium, surfactant, and acid were measured. Permeability enhancement and location of any precipitation was detected using CT scanner to the core before and after the acid injection. Material balance was conducted to determine the amount of surfactant that retained in the core.
Experimental results show that VES acid was not able to buildup pressure drop across the core when it was injected inside 70 md permeability cores at various acid concentrations and injection rates when only one fourth pore volumes was injected. At high concentration of HCl, Calcium and the surfactant propagated with the same velocity. When low concentration of HCl was employed, Calcium propagated faster. Surfactant retention is higher when the acid concentration and the injection rate were lower. This number could be up to 100%. CT scan confirmed only small and short wormhole branches at the area near the inlet and one wormhole dominated till the end with a decreasing diameter. Reaction rate and extension of wormhole decreased when lower concentration HCl was used and injected at a higher rate.
Formation damage may be caused by in-situ emulsions, changes in wettability and by deposition of asphaltenes, wax and scales. It is widely recognized that these damage mechanisms may be removed by using microemulsion technology, resulting in enhanced productivity of oil and gas wells. It is also known that microemulsion systems are composed of surfactants, oil, brine and optional co-surfactants and acids. These systems can be very complex, due to the number of variables that influence formulation behavior, including temperature, type of oil, type and concentration of salt, surfactant, co-surfactant, and acid.
The development of microemulsions for specific oilfield applications requires a systematic study of phase behavior as a tool to select a treatment composition that satisfies specific parameters defined by the application. Phase behavior studies are necessary in order to identify microemulsion phase boundaries.
Phase behavior diagrams of microemulsion systems developed for wellbore damage remediation considered the following variables: temperature, type and concentration of co-surfactants, type and concentration of brine, oils, surfactants and acids.
Laboratory studies of surfactant-oil-brine systems used successfully in the field confirm that they undergo phase transitions from Winsor I (oil-in-water with excess oil), to Winsor III (microemulsion), to Winsor II (water-in-oil with excess water).
This paper presents formulations positioned in an area of the phase diagram that correspond to maximum detergency and optimum interfacial properties required for field applications. The relationship between phase diagrams, interfacial properties (interfacial tension and contact angle) and well productivity are discussed.
Water availability for injection into oil reservoirs is an effective factor for superiority of water injection project. One of the parameters that cause undesirable effects on reservoir rock injectivity is clay minerals. The different structures of clay minerals will result in undesirable effects on rock permeability. Clay minerals enter into the pores and throats by injected water or they are a part of the structure of the reservoir rocks. Clay swelling from the viewpoint of the clay minerals type and structure can reduce the permeability of reservoir rock. In this study after the effects of clay minerals and their performance mechanisms, some of the rock samples were chosen from one of the field in south of Iran that is injecting water in aquifer.
Then it has been tried with XRD examination to specify the clay minerals type, and to estimate the percentage of each type; however permeability reduction was estimated for each one of core samples in core flooding experiments by injecting distilled water and formation water to the sample and creation of clay swelling. Also results comparison could show their performance and effect in the water injection process to estimate permeability reduction.
Keywords: water injection, clay minerals, clay swelling, permeability, core flooding
Water injection or re-injection of produced water into aquifer is to maintain the reservoir pressure. Injection water quality should be considered so not having suspended solids and oil emulsion in excess that may cause injectivity impairment. On the other hand, it should be compatible with formation water so not having scale formation and precipitation at wellbore face and within the reservoir as a result of mixing which could end in permeability and injectivity impairments.
Study of ions present in both injection and formation waters in respect of the possibility of scale precipitation, the prevention methods and the possibility of high rate water injection could guarantee the process of pressure maintenance and its subsequent improved oil recovery. Water quality improvement in both disposal water injections and secondary oil recovery methods is to achieve desirable injection rate with the lowest possible injection pressure.
Accumulation of spent acid in the wellbore area after acidizing causes severe formation damage that would result in loss of productivity. This would cause reduction of relative permeability to gas, especially in tight gas wells. Capillary forces are the key parameters that affect trapping of spent acid in the formation. This work provides a comprehensive study of the effect of acid additives in spent acid on contact angle in tight gas carbonates. All experiments were conducted using the Drop Shape Analysis (DSA) at high temperature and pressure.
Different types of commonly used additives including corrosion inhibitors, iron control agents, mutual solvents, methanol, acetic acid and formic acid were tested at different concentrations. Experiments were conducted at temperature of 100 oC and pressure of 1000 psi.
Acid additives such as methanol, corrosion inhibitors, formic and acetic acids reduced the contact angle. Both iron control agents showed no impact on contact angle at concentration of 0.3 wt.% while at the lower concentration of 0.03 wt.% they decreased contact angle. A study was also done on the effect of temperature on contact angle of spent acid. The results showed that increasing temperature up to 100 oC increased contact angle, while beyond this temperature contact angle was decreased.
This work would help to better understand the ability of acid additives in altering wettability of carbonate rocks, which would consequently result in better designing the acid formulae and enhancement in well productivity by minimizing capillary forces.