Horizontal wells are drilled to achieve improved reservoir coverage, high production rates, and to overcome water coning problems, etc. Many of these wells often produce at rates much below the expected production rates. Low productivity of horizontal wells is attributed to various factors such as drilling induced formation damage, high completion skins, and variable formation properties along the length of the wellbore as in the case of heterogeneous carbonate reservoirs. Matrix acidizing is used to overcome the formation damage by injecting the acid into the carbonate rock to improve well performance. Designing the matrix acidizing treatments for horizontal wells is a challenging task because of the complex process. The estimation of acid distribution along wellbore is required to analyze that the zones needing stimulation are receiving enough acid. It is even more important in cases where the reservoir properties are varying along the length of the wellbore. A model is developed in this study to simulate the placement of injected acid in a long horizontal well and to predict the subsequent effect of the acid in creating wormholes, overcoming damage effects, and stimulating productivity. The model tracks the interface between the acid and the completion fluid in the wellbore, models transient flow in the reservoir during acid injection, considers frictional effects in the tubulars, and predicts the depth of penetration of acid as a function of the acid volume and injection rate at all locations along the completion. A computer program is developed implementing the developed model. The program is used to simulate hypothetical examples of acid placement in a long horizontal section. A real field example of using the model to history match actual treatment data from a North Sea chalk well is demonstrated. The model will help to optimize acid stimulation in horizontal wells.

Spent acid retention in the near-wellbore region causes reduction of relative permeability to gas and eventually curtailed gas production. In low-permeability gas carbonate reservoirs, capillary forces are the key parameters that affect the trapping of spent acid in the formation. Capillarity is a function of surface tension at the gas-liquid interface and contact angle of the fluids in the rock. To weaken capillary forces, surface tension should be low and contact angle should be large. This work provides a comprehensive study on the effect of various common acid additives on carbonate rock wettability, and surface tension and contact angle, as the main parameters that control capillarity. Surface tension and contact angle experiments were conducted using Drop Shape Analysis (DSA) instrument at high temperature and pressure. Core flood experiments were also conducted to study the overall impact of the acid additives on wettability by analyzing irreducible fluid saturation in the rocks before and after spent acid exposure. Spontaneous water imbibition was conducted in each case to check for permanent or long-term wettability change as a result of using these additives. Acid additives such as methanol and corrosion inhibitors reduced both surface tension and contact angle. Iron control agents had no impact on surface tension, however, they decreased contact angle at the lower concentration used. Formic and acetic acids did not affect the surface tension, but they had a reducing impact on the contact angle. According to the core flood experiment results, formic acid decreased irreducible fluid saturation whereas methanol increased irreducible fluid saturation. On the other hand, the fluorochemical surfactant tested changed the rock wettability into more gas wetting. Use of this chemical would help in recovering spent acid. The results of the spontaneous water imbibition tests showed that organic acids and iron control chemicals did not have a permanent impact on wettability of the rocks. However, the wettability change as a result of using fluorochemical surfactant would persist for a long time as this chemical forms a film on the rock surface.

Mining for silver, lead, zinc, and copper in Zimapan, Hidalgo State, Mexico has been ongoing since 1576. Unsecured tailings heaps and associated acid mine drainage have presented problems related to soil quality, water quality, and dust emission control in the Zimapan area. Objectives of the study of the mine tailings are (1) to determine mineralogy of the tailings in order to identify acid-producing minerals and heavy metals at risk for release in acidic conditions, and (2) to quantify carbonate minerals and (3) to determine heavy metal content that may be released by the products of sulfide mineral weathering. Representative mine tailings have been sampled from a site located north of Zimapan. Mineralogical characterization has been conducted with X-ray diffraction (XRD), and scanning and transmission electron microscopes (SEM and TEM). Total carbonates have been determined the Chittick procedure. X-Ray Fluorescence (XRF) has been utilized to determine total elemental composition. XRD and SEM analyses have confirmed the presence of pyrite and arsenopyrite indicating a potential for acid mine drainage. Calcite has been confirmed to have a significant presence in the unweathered samples by XRD and the Chittick procedure, with some samples containing an average of 19.4% calcite. NAA and XRF have revealed significant concentrations of toxic elements such as As, Pb and Zn in both the oxidized and unoxidized samples.

No description available.

No description available.

To increase the successful rate of acid stimulation, a method is required to diagnose the effectiveness of stimulation which will help us to improve stimulation design and decide whether future action, such as diversion, is needed. For this purpose, it is important to know how much acid enters each layer in a multilayer carbonate formation and if the low-permeability layer is treated well. This work develops a numerical model to determine the temperature behavior for both injection and flow-back situations. An important phenomenon in this process is the heat generated by reaction, affecting the temperature behavior significantly. The result of the thermal model showed significant temperature effects caused by reaction, providing a mechanism to quantitatively determine the acid flow profile. Based on this mechanism, a further inverse model can be developed to determine the acid distribution in each layer.

Horizontal wells are drilled to achieve improved reservoir coverage, high production rates, and to overcome water coning problems, etc. Many of these wells often produce at rates much below the expected production rates. Low productivity of horizontal wells is attributed to various factors such as drilling induced formation damage, high completion skins, and variable formation properties along the length of the wellbore as in the case of heterogeneous carbonate reservoirs. Matrix acidizing is used to overcome the formation damage by injecting the acid into the carbonate rock to improve well performance. Designing the matrix acidizing treatments for horizontal wells is a challenging task because of the complex process. The estimation of acid distribution along wellbore is required to analyze that the zones needing stimulation are receiving enough acid. It is even more important in cases where the reservoir properties are varying along the length of the wellbore. A model is developed in this study to simulate the placement of injected acid in a long horizontal well and to predict the subsequent effect of the acid in creating wormholes, overcoming damage effects, and stimulating productivity. The model tracks the interface between the acid and the completion fluid in the wellbore, models transient flow in the reservoir during acid injection, considers frictional effects in the tubulars, and predicts the depth of penetration of acid as a function of the acid volume and injection rate at all locations along the completion. A computer program is developed implementing the developed model. The program is used to simulate hypothetical examples of acid placement in a long horizontal section. A real field example of using the model to history match actual treatment data from a North Sea chalk well is demonstrated. The model will help to optimize acid stimulation in horizontal wells.

Recently developed models of the acid fracturing process have shown that the differential etching necessary to create lasting fracture conductivity is caused by the heterogeneous distributions of permeability and mineralogy along the fracture faces. To predict the conductivity that can be created by acid in a particular formation, the models require information about these formation properties. This research aims to quantify correlation lengths using a geostatistical description of small scale heterogeneity to ascertain the distribution of permeability and mineralogy in a carbonate formation. The correlation length parameters are a first step in being able to couple acid transport and rock dissolution models at reservoir scale with a model of fracture conductivity based on channels and roughness features caused by small scale heterogeneity. Geostatistical parameters of small scale heterogeneity affecting wells in the Hugoton Field are developed. Data leading to their derivation are obtained from a combination of well logs and cores. The permeability of slabbed core is measured to yield vertical correlation length. Well logs are used to estimate permeability via an empirical relationship between core plug permeability and well log data for calculation of horizontal correlation length. A fracture simulator computes the acid etched fracture width for known treatment conditions. The resulting geostatistical parameters and acid etched width are used to predict acid fracture performance for a well in the Hugoton Field. Application of new model conductivity correlations results in a unique prediction for the acid fracture case study that differs from the industry standard. Improvements in low cost stimulation treatments such as acid fracturing are the key to revitalizing production in mature carbonate reservoirs like the Hugoton Field. Planning and development of new wells in any carbonate formation necessarily must consider acid fracturing as a production stimulation technique. Reliable models that accurately predict acid fracture conductivity can be used to make an informed investment decision.

Carbonate reservoirs of different rock types have wide ranges of porosity and permeability, creating zones with different reservoir quality and flow properties. This research addresses how seismic technology can be used to identify different carbonate rock types for characterization of reservoir heterogeneity. I also investigated which seismic methods can help delineate thin high-permeability (super-k) layers that cause early water breakthroughs that severely reduce hydrocarbon recovery. Based on data from a Middle East producing field, a typical geologic model is defined including seal, a thin fractured layer, grainstone and wackestone. Convolutional, finite difference, and fluid substitution modeling methods are used to understand the seismic signatures of carbonate rock types. Results show that the seismic reflections from the seal/fractured-layer interface and the fractured-layer/grainstone interface cannot be resolved with conventional seismic data. However, seismic reflection amplitudes from interfaces between different carbonate rock types within the reservoir are strong enough to be identified on seismic data, compared with reflections from both the top and bottom interfaces of the reservoir. The seismic reflection amplitudes from the fractured-layer/grainstone and the grainstone/wackestone interfaces are 17% and 23% of those from the seal/fracturedlayer interface, respectively. By using AVO analysis, it may be possible to predict the presence of the fractured layer. It is observed that seismic reflection amplitude resulting from the interference between the reflections from overburden/seal and seal/fractured-layer does not change with offset. The thin super-k layer can also be identified using fluid substitution method and time-lapse seismic analysis. It shows that this layer has 5% increase in acoustic impedance after oil is fully replaced by injecting water in the layer. This causes 11% decrease and 87% increase in seismic reflection amplitudes from the seal/fractured-layer interface and the fractured-layer/grainstone interface after fluid substitution, respectively. These results show that it is possible to predict carbonate rock types, including thin super-k layers, using their seismic signatures, when different seismic techniques are used together, such as synthetic wave modeling, AVO, and time-lapse analysis. In future work, the convolutional model, AVO analysis, and fluid substitution could be applied to real seismic data for field verification and production monitoring.

Although it has been shown that clean perforation tunnels facilitate the evolution of a single, deeper-penetrating wormhole, there are no reported applications of reactive shaped charges in carbonates prior to acid stimulation. The present study was instigated to evaluate the impact of reactive charges on acid wormholing in representative carbonate cores. A set of oil-saturated Indiana limestone and cream chalk cores have been perforated under simulated downhole conditions using either a conventional or a reactive shaped charge of equal explosive load. After CT scanning to eliminate outlying perforations affected by rock property anomalies, the set of cores were subjected to identical acid injection treatments representative of typical carbonate reservoir stimulations. Time to breakthrough and effluent chemistry were both analyzed and recorded. Finally, post-stimulation CT scans were used to evaluate wormhole morphology. The laboratory experiments showed that reactive charges provide wider perforation tunnels with higher injectivity, which is beneficial for any type of stimulation job. Higher injectivity tunnels help to propagate more dominant and straighter wormholes resulting in less acid to break through the cores. This technology has a significant potential when perforating tight formations or heterogeneous intervals, where obtaining clean tunnels with conventional perforators is most challenging. Further research work needs to be done to evaluate if the difference in acid volume to breakthrough observed in the experiments would have a major impact in the field.