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### GUEST EDITORIAL

J. Energy Resour. Technol. 2005;127(3):169-170. doi:10.1115/1.2000275.
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Abstract
Commentary by Dr. Valentin Fuster

### RESEARCH PAPERS

J. Energy Resour. Technol. 2005;127(3):171-180. doi:10.1115/1.1924398.

The pore and grain surface of reservoir rocks often has clay and other fine material attached onto pore walls. It has been long recognized that brine salinity and pH are key factors affecting the attractive forces between pore surfaces and fines. If mobilized particles are assembled in sufficient quantities, they obstruct pore throats and reduce the permeability of the formation. There is anecdotal evidence of substantial fines migration during steam injection enhanced oil recovery operations. As of yet, the mechanism of fines release with temperature is unexplained. The Derjaguin, Landau, Verwey, and Overbeek theory of colloidal stability is used in conjunction with laboratory, core-scale experiments to demonstrate that high temperature, alkaline pH, and low salinity (typical characteristics of steam condensate) are sufficient to induce fines mobilization. Temperature is a key variable in calculations of fines stability. Hot-water floods are performed in Berea sandstone at temperatures ranging from 20°C to 200°C. Permeability reduction is observed with temperature increase and fines mobilization occurs repeatably at a particular temperature that varies with solution pH and ionic strength. A scanning electron microscope is used to analyze composition of the effluent samples collected during experiments. It confirms the production of fine clay material. On the practical side, this study provides design criteria for steam injection operations so as to control fines production.

Commentary by Dr. Valentin Fuster
J. Energy Resour. Technol. 2005;127(3):181-190. doi:10.1115/1.1944028.

To understand the basic relationship between the rising water-cut, well sanding, and migration of fines, the author’s work led him to examine the mechanism of well sanding due to sand liquefaction in cases where the storm chokes in offshore wells were activated and when the production platform separator lines froze due to sudden cold weather. The author found that as the original water-oil contact plane rose above the original plane of contact, it caused a drastic change in water saturation and relative permeability. We show the increased water saturation decreases the resistance of the formation to stress by as much as 50%. This is one of the causes of sand liquefaction at or near the perforation cavities. The parameters affecting the process most are the fine-particle buoyancy, changes in the effective stress and the bulk density of the sand, the pore pressure buildup and changes in porosity near the perforation cavities, the induced transient shear stress resulting from the water-hammer total pressure wave, and the lack of adequate cohesive cement or interlocking contacts between the grains of the unconsolidated sand. The simple model calculations pointed to the conclusion that if the grains of the unconsolidated sand or the fine particles accelerated above the threshold limit of $0.19000g$, the chances for fines migration and sand liquefaction were high. Furthermore, if, at the free face of the washed-out perf tunnels or the cavernous cavities of the unconsolidated sand, the total pressure wave magnitude exceeded the shear resistance of the sand, then sand liquefaction was certain to occur. The obvious outcome of this process is nothing but serious formation damage. Based on his models, the author’s recommendation for alleviating this type of damage, includes but is not limited to selective perforation, oriented perforation, gravel packing, frac packing, filter packing, trajectory planning for well reentries, and controlled drawdown.

Commentary by Dr. Valentin Fuster
J. Energy Resour. Technol. 2005;127(3):191-200. doi:10.1115/1.1937416.

When during oil production the thermodynamic conditions within the near-well-bore formation lie inside the asphaltene deposition envelope of the reservoir fluid, the flocculated asphaltenes cause formation damage. Mathematically, formation damage is a reduction in the hydrocarbon effective mobility, $λ$, $λ=ko∕μo=kkro∕μo$. Three possible mechanisms of asphaltene-induced formation damage have been discussed in the literature. Asphaltenes can reduce the hydrocarbon effective mobility by a) blocking pore throats thus reducing the rock permeability, k, b) adsorbing onto the rock and altering the formation wettability from water-wet to oil-wet thus diminishing the effective permeability to oil, $ko$, and c) increasing the reservoir fluid viscosity, $μo$, by nucleating water-in-oil emulsions. In the most frequently encountered case of asphaltene-induced formation damage where under-saturated oil is being produced without water, the most dominant damage mechanism is blockage of pore throats by asphaltene particles causing a reduction in rock permeability k. This paper presents a rather simple, yet realistic way of modeling asphaltene-induced near-well formation damage caused by blockage of pore throats by asphaltene particles. The model utilizes both macroscopic and microscopic concepts to represent the pore throat blockages. It also utilizes the Thermodynamic-Colloidal Model of Asphaltene, $TCModelSM$, an existing AsphWax asphaltene phase behavior model capable of simulating the asphaltene particle size distribution as a function of the thermodynamics of the system. The new asphaltene near-well formation damage model is applied in one case where it is used to track the degree of formation damage as a function of time and the effect it has on near-well-bore and well-bore hydraulics. Similarly the model can be used to study a priori the economics of developing a reservoir known to contain under-saturated asphaltenic oil.

Commentary by Dr. Valentin Fuster
J. Energy Resour. Technol. 2005;127(3):201-213. doi:10.1115/1.1944029.

As offshore production environments become ever more complex, particularly in deepwater regions, the risks associated with formation damage due to precipitation of inorganic scales may increase to the point that production by conventional waterflooding may cease to be viable. The ability to predict and control such formation damage can thus become critical to project success under such circumstances. The work described in this paper presents how the risk may be managed from early in the CAPEX phase of projects through to the OPEX phase by use of reservoir simulation tools to better understand the scaling potential in a reservoir and the possibilities for effective scale control. This process is illustrated by reference to a number of field examples where specific scaling problems have been identified, and the ability to implement effective scale management has been impacted by detailed fluid flow and brine-mixing calculations.

Commentary by Dr. Valentin Fuster
J. Energy Resour. Technol. 2005;127(3):214-224. doi:10.1115/1.1924464.

This study discusses formation damage mechanisms that were caused by commonly used chemical treatments. The chemicals used in these treatments included a scale inhibitor, a biocide-corrosion inhibitor, an in situ gelled acid, a full-strength mud acid, and a mutual solvent. These treatments were designed to remove a known form of formation damage. However, they created new forms of formation damage, which resulted in a significant decline in the performance of the treated wells. Case histories that illustrate the initial and new formation damage mechanisms are explained in detail. Laboratory and field studies that were performed to identify these mechanisms are discussed. Moreover, this paper highlights the remedial actions and field application that resulted in restoring the performance of various wells without affecting the integrity of the formation (both carbonate and sandstone). Finally, recommendations are given to minimize formation damage due to various chemical treatments.

Commentary by Dr. Valentin Fuster
J. Energy Resour. Technol. 2005;127(3):225-232. doi:10.1115/1.1944027.

We have developed a fine-scale model of the sandstone core acid flooding process by solving acid and mineral balance equations for a fully three-dimensional flow field that changed as acidizing proceeded. The initial porosity and mineralogy field could be generated in a correlated manner in three dimensions; thus, a laminated sandstone could be simulated. The model has been used to simulate sandstone acidizing coreflood conditions, with a $1in.diam$ by $2in.$ long core represented by 8000 grid blocks, each having different initial properties. Results from this model show that the presence of small-scale heterogeneities in a sandstone has a dramatic impact on the acidizing process. Flow field heterogeneities cause acid to penetrate much farther into the formation than would occur if the rock were homogeneous, as is assumed by standard models. When the porosity was randomly distributed (sampled from a normal distribution), the acid penetrated up to twice as fast as in the homogeneous case. When the porosity field is highly correlated in the axial direction, which represents a laminated structure, acid penetrates very rapidly into the matrix along the high-permeability streaks, reaching the end of the simulated core as much as 17 times faster than for a homogeneous case.

Commentary by Dr. Valentin Fuster
J. Energy Resour. Technol. 2005;127(3):233-239. doi:10.1115/1.1937419.

A new microemulsion additive has been developed that is effective in remediating damaged wells and is highly effective in fluid recovery and relative permeability enhancement when applied in drilling and stimulation treatments at dilute concentrations. The microemulsion is a unique blend of biodegradable solvent, surfactant, co-solvent and water. The nanometer-sized structures are modeled after Veronoi structures which when dispersed in the base treating fluid of water or oil permit a greater ease of entry into a damaged area of the reservoir or fracture system. The structures maximize surface energy interaction by expanding to twelve times their individual surface areas to allow maximum contact efficiency at low concentrations (0.1–0.5%). Higher loadings on the order of 2% can be applied in the removal of water blocks and polymer damage. Lab data are shown for the microemulsion in speeding the cleanup of injected fluids in tight gas cores. Further tests show that the microemulsion additive results in lower pressures to displace frac fluids from propped fractures resulting in lower damage and higher production rates. This reduced pressure is also evident in pumping operations where friction is lowered by 10–15% when the microemulsion is added to fracturing fluids. Field examples are shown for remediation and fracture treating of coals, shales and sandstone reservoirs, where productivity is increased by 20–50% depending on the treatment parameters. Drilling examples are shown in horizontal drilling where wells cleanup without the aid of workover rigs where offsets typically require weeks of workover.

Commentary by Dr. Valentin Fuster
J. Energy Resour. Technol. 2005;127(3):240-247. doi:10.1115/1.1937420.

Very low in situ permeability gas reservoirs $(Kgas<0.1mD)$ are very common and represent a major portion of the current exploitation market for unconventional gas production. Many of these reservoirs exist regionally in Canada and the United States and also on a worldwide basis. A considerable fraction of these formations appear to exist in a state of noncapillary equilibrium (abnormally low initial water saturation given the pore geometry and capillary pressure characteristics of the rock). These reservoirs have many unique challenges associated with the drilling and completion practices required in order to obtain economic production rates. Formation damage mechanisms affecting these very low permeability gas reservoirs, with a particular emphasis on relative permeability and capillary pressure effects (phase trapping) will be discussed in this article. Examples of reservoirs prone to these types of problems will be reviewed, and techniques which can be used to minimize the impact of formation damage on the productivity of tight gas reservoirs of this type will be presented.

Commentary by Dr. Valentin Fuster
J. Energy Resour. Technol. 2005;127(3):248-256. doi:10.1115/1.1875554.

Coalbed methane (CBM) reservoirs are characterized as naturally fractured, dual porosity, low permeability, and water saturated gas reservoirs. Initially, the gas, water, and coal are at thermodynamic equilibrium under prevailing reservoir conditions. Dewatering is essential to promote gas production. This can be accomplished by suitable completion and stimulation techniques. This paper investigates the efficiency and performance of the openhole cavity, hydraulic fractures, frack and packs, and horizontal wells as potential completion methods which may reduce formation damage and increase the productivity in coalbed methane reservoirs. Considering the dual porosity nature of CBM reservoirs, numerical simulations have been carried out to determine the formation damage tolerance of each completion and stimulation approach. A new comparison parameter, named as the normalized productivity index $Jnp(t)$ is defined as the ratio of the productivity index of a stimulated well to that of a nondamaged vertical well as a function of time. Typical scenarios have been considered to evaluate the CBM properties, including reservoir heterogeneity, anisotropy, and formation damage, for their effects on $Jnp(t)$ over the production time. The results for each stimulation technique show that the value of $Jnp(t)$ declines over the time of production with a rate which depends upon the applied technique and the prevailing reservoir conditions. The results also show that horizontal wells have the best performance if drilled orthogonal to the butt cleats. Long horizontal fractures improve reservoir productivity more than short vertical ones. Open-hole cavity completions outperform vertical fractures if the fracture conductivity is reduced by any damage process. When vertical permeability is much lower than horizontal permeability, production of vertical wells will improve while productivity of horizontal wells will decrease. Finally, pressure distribution of the reservoir under each scenario is strongly dependent upon the reservoir characteristics, including the hydraulic diffusivity of methane, and the porosity and permeability distributions in the reservoir.

Commentary by Dr. Valentin Fuster
J. Energy Resour. Technol. 2005;127(3):257-263. doi:10.1115/1.1924463.

It is well recognized that near-wellbore formation damage can dramatically reduce well productivities, especially for open hole completed horizontal wells. The economic impact of poor productivity of these wells has pushed toward significant efforts in recent years to study laboratory testing techniques and numerical modeling methods for predicting and controlling drilling-induced formation damage. This paper presents an integrated approach, combining a near-wellbore modeling with laboratory experiments for data acquisition as input for the model, to evaluate the performance of oil and gas wells after drilling-induced formation damage.

Commentary by Dr. Valentin Fuster