Near-wellbore Formation Damage Research Articles

CO2 Injectivity Test Proves Concept of CCUS Field Development

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 216673, “CO2 Injectivity Test Proves the Concept of CCUS Field Development,” by Yermek Kaipov, SPE, and Bertrand Theuveny, SLB, and Ajay Maurya, Saudi Aramco, et al. The paper has not been peer reviewed. _ The complete paper presents a unique case study on injectivity tests done in Saudi Arabia to prove the concept of carbon capture, use, and storage (CCUS) capability. It describes the design of surface and downhole testing systems, lessons learned, and recommendations. The injectivity tests were effective in identifying and confirming the best reservoir for CO2 injection and defining the best completion strategy. Creating injection conditions close to CCUS is vital, especially in heterogeneous carbonate reservoirs where the petrophysical correlations for the reservoir model require calibration with dynamic data. Introduction The energy company has conducted an extensive evaluation campaign by drilling appraisal wells through multizone saline aquifer reservoirs on different sites close to potential sources of CO2 at the surface. The evaluation program included coring, openhole logging, formation testing for stress-test and water sampling, and injectivity testing in the cased hole. Apart from reservoir characterization, different completion strategies were evaluated by performing injectivity tests in both vertical and horizontal wells. The lower completion was represented by perforated casing and an open hole. Injectivity Testing Injection tests are a commonly used method in waterflood projects to evaluate the injectivity capacity of the well and reservoir. The test involves an injection period with one or more injection rates, followed by a falloff period (Fig. 1). During the injection period, the liquid is injected at a stable rate to reduce the risk of near-wellbore formation damage caused by fluid incompatibility or exceeding the fracture gradient and inducing formation fracturing. The bottomhole-pressure data acquired during the test is analyzed using the pressure transient analysis method to estimate the permeability thickness, skin factor, and lateral heterogeneities. Additionally, the injection logging profile can be conducted along the sandface to assess completion efficiency and formation heterogeneity. By interpreting the results of the injection test, engineers can optimize the injection rate and improve the performance of the well and reservoir, ultimately leading to more-efficient oil recovery. Injectivity Test: Case Study The injectivity tests were conducted on virgin reservoirs using vertical appraisal wells that were sidetracked horizontally into the reservoirs with the greatest potential for storage. The reservoirs’ depths varied from 4,000 to 8,000 ft, with a normal gradient of reservoir pressure and temperature. The injectivity test design used reservoir properties estimated from the openhole evaluation, such as porosity, permeability, reservoir pressure, temperature, reservoir fluid sample, and fracture gradient. These data were used to set injectivity-test objectives, calculate expected well parameters, select equipment, and plan operations. The primary goal of the tests was to assess reservoir injectivity by injecting water, nitrogen, and CO2 to prove the concept for a CO2-injection project. While water and nitrogen injections are well-known in the industry, the CO2 injectivity test was new and required more attention during the design phase to evaluate all possible risks.

The impact of effective tortuosity on carbonate acidizing and the validation of Damköhler and Péclet dimensionless phase space

Acid stimulation is one of the main methodologies to enhance well productivity and increase permeability lost by near-wellbore formation damage through matrix acidizing. The desired outcome of acidizing carbonate rocks is to form deep conductive flow channels called “wormholes”. The productivity enhancement depends on how deep these wormholes penetrate into the reservoir. The porous medium is characterized by three fundamental parameters which are anisotropic or isotropic porosity, permeability, and percolation. Here we test the hypothesis that effective tortuosity - a key parameter for microstructure characterization in porous media - has a significant effect on wormhole formation. Significant progress has been made by empirical work on carbonate acidizing to increase the stimulation efficiency, but further improvements are possible by developing a deeper understanding of the impact of effective tortuosity on wormhole initiation and development. We use Indiana limestone core-flooding experiments to inject diluted hydrochloric acid (HCl) at different acid concentrations and injection rates. Effective tortuosity was calculated for the tight Indiana limestone and was compared with an earlier study on the highly porous Mount Gambier limestone to evaluate the effect of tortuosity on wormhole formation. Our results suggest that the inverse Damköhler and Péclet phase space, traditionally used for evaluating criteria for wormhole formation, needs to be extended by tortuosity as a third dimension to capture the effect of microstructure for the initiation of wormhole phenomenon. Incorporating this extension will improve the prediction of wormhole initiation conditions for all carbonate rock types by using a universal dimensionless phase space.

Technology Focus: Matrix Stimulation (June 2018)

Technology Focus The evolution of horizontal drilling and multistage completions has changed matrix stimulation from the “more acid, better result” belief to effective lateral distribution and deeper penetration with less acid. Large-gallon-per-foot-based treatment became impractical and unnecessary. The constant remains that drilling is blamed for causing formation damage; therefore, matrix stimulation is needed. Underbalanced coiled-tubing drilling aimed at changing this constant, however, has its own drawbacks. For certain lithologies, acid tunneling can be an attractive alternative to rotary-bit drilling. Though the technology was proposed many years ago, its use has been limited. Hardware to control the drilling direction, fluids to dissolve the formation rock efficiently, and jetting dynamics to optimize the rate of penetration have been pushed forward progressively. The goal of stimulation while drilling finally may be achievable. Of course, not all reservoir rock types are readily soluble in chemicals. Cracking the reservoir rock will continue to be the preferred process for sandstone. The first mechanism we think of for rock cracking is hydraulics. Unless full-fledged hydraulic fracturing is required, using high-energy pulses induced by propellant or other chemical reactions can produce sufficient pressure to break the rock past the near-wellbore formation damage. Perfecting the control and job design can lead to efficiency and broader implementation. One question we often ask in the matrix-stimulation domain is “what’s new?” It almost seems that the products and technologies of yesterday have been brought out again and again with minor twists. Indeed, it is amazing how many “new technologies” actually have been around for decades. While most of the industry is busy handling daily operations and logistics, it is encouraging to see universities, government-supported research and development institutes, and even some large service and operating companies studying the science behind the products and technologies. Advanced multiscale, multiphysics mathematical models are used to optimize particle bridging for diverting efficiency; large-scale experimental setups are used to gain insights into differential etching patterns during acid fracturing caused by viscous fingering and heterogeneous reactions, perforation penetration in realistic geometry and stresses, and other phenomena that could not be observed by small-scale laboratory testing. These studies help us appreciate the ingenuity of our predecessors and help us fit the technologies to the right applications better. Recommended additional reading at OnePetro: www.onepetro.org. SPE 185344 Application of Closed-Fracture Acidizing for Stimulation of Tight Carbonate Reservoir in Mumbai Offshore by Dilip Kumar Sarma, Oil and Natural Gas Corporation, et al. SPE 187019 Large-Scale Visual Experiment and Numerical Simulation of Acid Fingering During Carbonate Acid Fracturing by Xiaogang Li, Southwest Petroleum University, et al. SPE 189546 Influence of Transport Conditions on Optimal Injection Rate for Acid Jetting in Carbonate Reservoirs by Dmitry Ridner, Texas A&M University, et al.

Pitfalls of CO<sub>2</sub> Injection in Enhanced Oil Recovery

The intent of this paper is to offer a comprehensive understanding of the pitfalls associated with CO2-rich gas injection during enhanced oil recovery (EOR) operations. An emphasis is placed, however, on the interactions between this gas and crude oil asphaltenes, because these later compounds are heavy organic molecules which can destabilize, flocculate and precipitate in CO2-rich environments, thus triggering a major field problem: injectivity loss due to near-wellbore (inflow) formation damage: an Achilles heel for any EOR process.

Use of Weak-Acid and Nonacid Alternatives in Acidizing Horizontal Wells

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 171766, “Challenge of Acidizing Horizontal Wells in Tight Carbonate Reservoirs: Weak-Acid and Nonacid Alternatives,” by Sameer Punnapala, SPE, Maryam Abdul Rahman, SPE, and Sanjay Misra, SPE, Abu Dhabi Company for Onshore Oil Operations, prepared for the 2014 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 10–13 November. The paper has not been peer reviewed. An operator developing tight carbonate reservoirs found that conventional acid stimulation with 15% hydrochloric acid (HCl) in horizontal wells did not provide expected results. A subsequent study revealed that permeability and length of treatment are the main parameters in deciding the optimal stimulation chemical. A correlation was developed, on the basis of the kinetic parameters of various chemicals and field experience, that can act as a guide in selecting the proper acidization formulations. Introduction In vertical wells, positive skin pertains to reduction of effective wellbore radius, thus sacrificing reservoir contact. It is very important to note that, in long horizontal wells, wellbore radius does not represent the reservoir contact; rather, it is replaced by the horizontal length. It can be said that the horizontal well itself represents a limiting case of the finite-conductivity fracture. Thus, in the case of a homogeneous reservoir, if vertical permeability is sufficient, the horizontal well is supposed to drain the reservoir. The primary aim of stimulation in such cases becomes removal of near-wellbore formation damage. The field development of this operator’s tight carbonate reservoirs was envisaged as being performed by drilling 3,000- to 5,000-ft-long horizontal wells. Although 15% HCl is the conventional acidization formulation for these fields, a study of conventional acidization jobs carried out in these fields revealed that HCl stimulation did not yield the desired results. Selective stimulation in a segmented completion and by use of diversion also did not change the situation. The operator therefore launched an extensive market and literature survey to conduct a root-cause analysis. The study revealed that weakacid chemicals and nonacid chemicals (e.g., chelates and nanoemulsions) offer a viable alternative. On the basis of the study, using kinetic and transport parameters of different chemical and coreflood studies cited in the literature, a correlation was developed for formation permeability and length of treatment vs. effectiveness of different stimulation recipes. This correlation was validated by the results obtained from the acidization review, and a reasonable matching was obtained.

A new semi-analytical model for predicting the performance of horizontal wells completed by inflow control devices in bottom-water reservoirs

Simulation and prediction the performance of horizontal wells completed by inflow control devices is the foundation of ICDs completion parameters design-optimization. In this work, a new semi-analytical model that couples the reservoir inflow to the downhole flow is developed for predicting the performance of horizontal wells with inflow control devices in a box-shaped reservoir with bottom-water drive. The reservoir inflow model is based on a 3D volumetric source model that incorporates reservoir permeability heterogeneity in the near well region, reservoir anisotropy, and near-wellbore formation damage. The downhole flow model considers pressure drops due to fluid flow in the tubing, ICDs, and annulus. The calculated results are compared with that obtained from reservoir simulator Eclipse™ showing a good agreement. Influential factors analysis indicates that the reduction in the ICD flow-restriction size gives an even more uniform inflow profile at the cost of reduction in well's productivity. For fractured reservoirs, the optimum well production performance is reached when the number of openhole packers is maximum, which means there is only one ICD joint per compartment. Variable ICD flow-restriction size design not only further improves the well production performance but also causes the increase in well's productivity compared with uniform ICD flow-restriction size design. Ignoring annulus flow will result in higher calculation value of well's productivity.

New Fracture-Stimulation Designs and Completion Techniques Result in Better Performance of Shallow Chittim Ranch Wells

Summary The Sacatosa field in west Texas was discovered in 1956. Since then, more than 1,500 wells have been drilled and completed in the main reservoir section known as the San Miguel 1. The San Miguel 1 is primarily low-permeability sandstone, with several shale layers dispersed throughout. Economic development of the field requires effective well stimulation and an active waterflood program to provide pressure maintenance. Unfortunately, the available injection water is of poor quality and can rapidly plug up pore throats with solids, resulting in significant near-wellbore formation damage. When these factors are considered, hydraulic fracturing of both injector and producer wells is a viable option for improved long-term well performance. However, because of relatively shallow depths, traditional hydraulic-fracturing practices can lead to a multiplane fracture system with a mix of horizontal and vertical components. A significant presence of horizontal fractures can be detrimental to fractured-well performance because of the low conductivities of the fractures. In producer wells, this could impair production if the reservoir is laminated and has low vertical permeability. In injectors, water-front movement and sweep efficiency would be diminished greatly. This paper discusses the steps taken to plan and develop a strategy to place vertical fractures in shallow San Miguel 1 sands. These findings can easily be extended to similar shallow-depth reservoirs worldwide. Some major modifications in completion design included changes in perforation strategy, redesign of the pump schedule, and implementation of a staged stimulation. Fracturing treatments were pumped on a total of 26 injectors and eight producers through a variety of methods, including coiled-tubing fracturing. Post-fracture analysis suggests a strong vertical-fracture component, and analysis of injectivity tests shows fracture parameters in line with design objectives. All the producers that were fracture stimulated with this technique reported higher initial production when compared with wells stimulated through the use of legacy treatment schedules.

Removal of Near-wellbore Formation Damage by Ultrasonic Stimulation

The plugging removal effect under ultrasonic waves and the effect of rock properties, technical parameters, and ultrasonic parameters on the cleaning results were studied using the self-developed dynamic flow apparatus and the artificial cores damaged by in situ fines, inorganic scale, drilling mud, paraffin deposition, and polymer. The experimental results proved that ultrasonic cleaning is the most effective to inorganic scale damage, and the optimum ultrasonic irradiation time is about 80–100 min. In addition, for the five types of damage, the increase of ultrasonic frequency and power drastically improve the permeability recovery rate. The results also indicated that, in in situ fines and inorganic scale experiments, the increase of initial core permeability increases the cleaning effect, and the trend is opposite in drilling mud, paraffin deposition, and polymer experiments.

Optimizing Fracture Stimulations in Low-Permeability Oil Reservoirs in the Ordos Basin

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 158562, ’Optimizing Fracture Stimulations in Low-Permeability Oil Reservoirs in the Ordos Basin,’ by Xinghui Liu, SPE, Pinnacle—A Halliburton Service; Yanrong Chang, Hongjun Lu, Baochun Chen, Jianshan Li, Yin Qi, and Chengwang Wang, PetroChina Changqing Oilfield Company, prepared for the 2012 SPE Asia Pacific Oil and Gas Conference and Exhibition, Perth, Australia, 22-24 October. The paper has not been peer reviewed. Huge low-permeability oil reserves are found in the Ordos basin in China. Key characteristics are low reservoir quality (10 to 13% porosity), low permeability (0.3 to 2.0 md), and low reservoir pressures (pressure gradients of 0.0075 to 0.009 MPa/m). Fracture stimulation is essential for commercial production in these reservoirs. To understand fracture-growth behavior better and to optimize treatment designs, microseismic monitoring and fracture modeling were performed for pilot wells in key areas. In some reservoirs in the basin, fracture-closure stress sometimes could not be obtained from commonly used pump-in/shut-in tests because pressure decline is extremely slow. To obtain closure stress in these reservoirs, conventional pump-in/flowback (PI/FB) tests were modified and used. Fracture-modeling analysis then was conducted with a calibrated fracture model, which must match both the observed net fracture pressures and the fracture dimensions from microseismic mapping. This approach led to significant improvements in fracture-treatment designs in these tight oil reservoirs. Introduction The Ordos basin is a lacustrine/fluvial and sedimentary basin in northern China and covers approximately 370 000 km2 across the Shaanxi, Gansu, and Shanxi provinces, and the Ningxia and Inner Mongolia autonomous regions, as shown in Fig. 1. Oil reservoirs are found at depths ranging from 800 to 2800 m in the south, and natural-gas reservoirs are found at depths ranging from 2700 to 3600 m in the north. Oil reservoirs are mainly Triassic and Jurassic systems, while natural-gas reservoirs are mainly Permian and Ordovician systems. The Ordos basin also has abundant coal and coalbed methane. Fracture stimulation of the low-permeability oil reservoirs in the Changqing oil field of the Ordos basin was studied. Changqing oil field is a general term that represents many individual oil fields across a large area. Oil production in the Changqing oil field started in 1971. During early development, oil was produced only from reservoirs with relatively good properties (permeability of 10 to 100 md) in the Jurassic formations, and small-scale fracturing treatments were necessary to remove near-wellbore formation damage. In recent years, these Jurassic reservoirs with relatively good properties have been depleted. Currently, the Triassic reservoirs with poorer reservoir properties account for more than 85% of the proved oil reserves in the Changqing oil field. The Triassic reservoirs are characterized by low reservoir quality (10 to 13% porosity), low reservoir permeability (0.3 to 2.0 md), and low reservoir pressures (pressure gradients of 0.0075 to 0.009 MPa/m). Development of the low- permeability reservoirs in the Changqing oil field began in the 1990s, while the large-scale development of ultralow-permeability reservoirs began in 2008. Production from these reservoirs requires the use of fracture stimulation.

Protecting the Reservoir With Surfactant Micellar Drill-In Fluids in Carbonate-Containing Formations

Summary Conventional water-based drill-in fluids (DIFs) contain high-molecular-weight polymers and different-size-distribution solid particles to reduce fluid loss and carry drilling debris back to surface during the drilling process. The polymers and solid particles in the drill-in fluids usually generate near-wellbore formation damage. This paper introduces a new polymer-free and solids-free surfactant micellar-based drill-in-fluid system to drill a carbonate-containing reservoir. This new fluid system contains relatively low-reactivity acids mixed with surfactants and internal breakers. The drill-in fluid is designed to have low viscosities in the drillpipe. After the fluid flows out of the drill bit, the acids will react with carbonates in the formation and thereby increase the pH of the drill-in fluid. The higher fluid pH combined with the presence of dissolved divalent ions will cause the surfactants to form elongated micelle structures that will significantly increase fluid viscosity at the bottom of the hole and in the downhole annulus between the drillpipe and the formation rock. The viscosified drill-in fluid will reduce fluid loss and will carry nondissolved drilling debris to the surface. After drilling through the targeted formation, the internal breakers in the viscosified drill-in fluid will break down the fluid viscosity to improve ease of removal, and the drill-in fluid should leave very little or no near-wellbore damage.

Innovative Use of Kaolinite in Downhole Scale Management: Squeeze-Life Enhancement and Water Shutoff

Summary Applied research has been undertaken to examine the potential of kaolinite combined with a kaolinite-fixation agent to increase squeeze lifetime through alteration of near-wellbore surface characteristics and mineralogy, and to provide water-shutoff control. With respect to enhancing squeeze lifetime, it is documented that kaolinite increases the quantity of inhibitor adsorbed. Conversely, clean sandstone with low clay content commonly provides a poor substrate for adsorption. Furthermore, in reservoirs that experience near-wellbore formation damage because of kaolinite mobilization, it has been shown that the use of a fixation agent as part of a squeeze treatment can increase squeeze lifetime. Using these facts, research has assessed the feasibility of injecting micro-crystalline kaolinite (average particle size 2 μm) combined with the fixation agent and scale inhibitor as a means of mechanically altering near-wellbore mineralogy and surface-property characteristics within clean, high-permeability sandstones. The testing has been designed to mimic the squeeze procedure used in the field for performing such a job and involves no additional steps to those used in a normal squeeze (i.e., preflush, main treatment, overflush). The paper presents the results of coreflood experiments that demonstrate "proof of concept," along with examples of potential field applications. A further concept, born from the initial idea, was the use of kaolinite and fixation agent for efficient, low-cost, environmentally friendly water shutoff. There are several available products for water shutoff, but the disadvantage of these is that they are not acceptable for use in Norway because of poor environmental characteristics. Hence, there was a need to fill this gap by developing water-shutoff technology to meet country-specific environmental legislation. The paper provides details of coreflood testing where an excess of kaolinite has been used to form an internal and external filter cake that is attached to the wellbore face and within the near-wellbore region using the fixation agent. The paper draws on data from StatoilHydro-operated fields in order to highlight the potential of this innovative approach to downhole scale management and water control.

Advanced Noncement Options for Isolating Wellbores

Technology Update Information provided by Ed Wood, Sean Yakeley, Jesse Constantine, and Jody Augustine, Baker Hughes. For today's long horizontal wellbores and multilateral completions, competent zonal isolation is especially critical. But cementing and perforating multiple zones is costly and time consuming, requires specialized equipment and personnel, can cause near-wellbore formation damage, and poses safety and environmental risks. Alternative isolation technologies now can reduce costs and improve well productivity through more effective fracture treatment and better inflow management. Among these new options, reactive-element (RE) technology and other fit-for-purpose packer systems are field-proven solutions for a variety of zonal isolation challenges. Much more of the world's oil and gas can now be recovered economically by exposing to the wellbore long stretches of reservoir that typically contain several pay zones. Without cost-effective zonal isolation, however, the full potential of advanced drilling and completion technology to increase production, ultimate recovery, and profitability cannot be realized. Efficient, practical zonal isolation is also important in solving fluid-loss problems while drilling and in reviving mature wells. With new, noncement isolation methods, it is possible to achieve uniform flow in highly productive wells, perform multiple fracture treatments in carbonate and shale reservoirs, and employ inflow control devices (ICDs) to man-age flow without well intervention. All of these capabilities extend a well's productive life and profitability. Two Key Drivers Isolating well intervals without cement is not a new concept, but recent growth in commercial use has been driven by such challenges as the need to fracture tight gas formations and to regulate flow in high-rate wells. Two means of achieving cementless isolation are the use ofRE packers with swelling-elastomer elements that self-energize in reaction to water and/or hydrocarbonsHydrostatic/mechanical packers, set hydraulically The latter type of packer often is used with an ICD. RE Systems For a fast-growing number of diverse zonal isolation challenges, an RE packer is an efficient, cost-effective alternative to cementing and perforating. RE-packer completions are simple to deploy and require fewer trips, no running tools, and no specially trained personnel on site. RE devices are usable in both oil and gas producers. Elastomeric-polymer sealing elements in the packer react with oil or water to swell and seal off the annulus between liner or casing, and open hole. The water-reactive element consists of particles contained in a nitrile-based polymer that swell by absorbing water. The rubber expands without the particles being physically absorbed in the rubber matrix. Oleophillic polymers in the oil-reactive element absorb hydrocarbons into the matrix. The swelling mechanisms are not reversible, so the element will not shrink if fluids are changed after swelling. Tests show negligible contraction in the elastomer when exposed to natural gas. RE packers are rated for temperatures to 300°F and pressures to 10,000 psi. RE-packer applications include water shutoff and the isolation of cement shoes, lateral junctions, and fractures. A special type of RE packer can be field-installed onto existing tools for added flexibility in deployment. Another RE tool can be used as a debris barrier.

The Relative Importance of Wellbore Pressure Drop and Formation Damage in Horizontal Wells

Summary Numerous studies have examined the roles of wellbore pressure drop and near-wellbore formation damage on the production performance of horizontal wells. These studies identified particular conditions for which these effects are important, but no quantitative general guidelines have been developed. In this paper, we present simple, analytical expressions that can be used to determine the relative effects of wellbore pressure drop and formation damage on horizontal well inflow. The equations developed are used to show how horizontal wells or laterals can be designed so that neither of these effects causes significant flow restrictions. The relative importance of the pressure drop in a horizontal wellbore is shown to be a simple function of two dimensionless numbers: the Reynold's Number for the flow in the wellbore and a new dimensionless number called the Horizontal Well Number. With this relationship, we illustrate how the wellbore diameter and length can be designed to ensure that the wellbore pressure drop is not restricting production. In this paper, we also illustrate a technique for identifying the most critical part of the well flow system (far-field reservoir flow, near-well convergent flow, or flow through the completion) from the relative sizes of different terms in the inflow equations. This analysis method shows that the importance of formation damage and the efficiency of well stimulation depend on formation thickness, well length, and reservoir extent in the horizontal plane. Guidelines are presented to show how much damage can be tolerated while still maintaining productivity within a prescribed fraction of the undamaged productivity.

Fluidic Oscillation With Acid Stimulation Improves Gas-Well Productivity

This article, written by Technology Editor Dennis Denney, contains highlights of paper IPTC 11452, "Fluidic- Oscillation Technique in Conjunction With Acid Stimulation Improves Gas- Well Productivity," by Ahmed Hegazy, Belayim Petroleum Company, and Bruce Conrad, Arshad Waheed, and Osama Sanad, Halliburton, prepared for the 2007 International Petroleum Technology Conference, Dubai, 4–6 December. The paper has not been peer reviewed. Copyright 2007 International Petroleum Technology Conference. Reproduced by permission. Low productivity of gas wells in the offshore Mediterranean Sea operations of Egypt often is caused by near-wellbore formation damage. The stimulation technique will vary depending on the type of damage; however, prevalent techniques are hydraulic fracturing and matrix acid stimulation. A new technique called "fluidic oscillation" was proposed, which would be especially applicable in cases having uncertainties regarding rock mineralogy. Fluidic oscillation is a mechanical, nonfluid-invasive stimulation technique (i.e., it is not essential to inject the treatment fluid into the reservoir to break down damage, although its use in that manner is not precluded). This technique was successful in stimulating gas wells in Egypt. Introduction The main challenge after completing two high-rate gas wells was less-than-expected production. These wells are approximately 37 miles off the Mediterranean Sea coast in the PetroTemsah field, northwest of Port Said in Egypt. This field produces gas and condensate with a condensate/gas ratio (CGR) of 60 bbl/MMscf. The producing formation is the Sidi Salem formation of Serrvallian age (Miocene), with an average porosity of 22%, average water saturation of 30%, and an average permeability of 100 md. This formation consists of four main reservoir layers (Lobe-0, -1, -2, and -3) and is at a depth of approximately 14,000 ft with a bottomhole temperature of 230°F. The bottomhole pressure ranges from 7,400 to 8,000 psi. A complete mineralogical breakdown of the rock by weight is not available, but essentially the rock is clean sandstone (80% quartz with 3 to 4% calcium carbonate and 10 to 15% feldspars and clay). The Sidi Salem formation is unconsolidated, and without adequate sand control, the wells tend to sand up, ceasing all flow from the reservoirs. The sand-control techniques used for the field include openhole gravel packs, expandable sand screens, and cased-hole gravel packs. The first example is an openhole completion with an expandable sand screen set across the zones of interest. The second well has an inside-casing gravel-pack completion.

Use of Viscoelastic Surfactant-Based Diverting Agents for Acid Stimulation: Case Histories in GOM

Summary Viscoelastic-surfactant (VES) -based diverting products have been used successfully in matrix acidizing in the Gulf of Mexico (GOM) in recent years. The uses of VES diverters range from remedial matrix-acid or nonacid-cleanup treatments to use before gravel- or frac-packing operations to clean up long intervals after perforating. Success or failure of these treatments is often related to the efficiency of diverting agents, especially for acid treatments on wells with long, heterogeneous intervals or multiple-zone completions. A VES diverting agent is of particular interest to remedial treatments of frac-/gravel-packed wells, because damage to the near-wellbore area and completion should be minimized for optimum production. Laboratory studies and field applications have demonstrated the nondamaging properties of a VES fluid. This paper reviews the properties of the vesicular-type VES diverting fluid, reviews the operational considerations, and presents several case histories with VES diverting agents in the GOM. The bottomhole static temperatures (BHSTs) of these cases range from 140 to 290°F for both gas and oil wells. With an internal breaker system, the diverter does not require contact with formation fluid, brine, or acid to clean up and provide optimum production. In some cases, as many as four stages of diverters were pumped in the treatment, and successful diversion was observed for each stage. The paper outlines field-operational considerations and detailed fluid properties, which were tailored to specific well conditions and formation characteristics. Details and pressure responses of the treatments are discussed. Introduction Matrix-acid stimulation has been frequently used in the GOM to remove formation damage caused by drilling-mud invasion, clay swelling and clay migration, and production impairment from inorganic scaling. When acid is injected into the reservoir below the fracturing rate and pressure, acid will typically enter the region with the highest permeability. Proper diversion is required to direct the treatment fluid into the damaged zone to achieve maximum benefit of the acid stimulation. Another area that employs acid treatment in the GOM completions is damage removal before gravel packs or frac packs. Gravel packing has been extensively used as a standard sand-control treatment in the GOM for several decades. Before or after the placement of gravel with completion fluids, low-density brines, or linear gels, an acid treatment is usually pumped to remove the near-wellbore formation damage or high skins encountered in wells perforated overbalanced (Unneland and Waage 1996; Matherne and Hall 1996). In other cases, a clay-acid package is often pumped into the formation before the gravel pack to stabilize the residual clays. The effectiveness of these treatments is often directly related to the ability of the acid treatment to remove the near-wellbore damage and connect the wellbore to the formation. In addition to determining the most effective combination of acid blends and volumes for each particular reservoir, treatment design and planning are done to ensure that the correct procedure is followed to place the acid across the entire interval. Staging of the treatment is used to force acid across the entire interval, treating the damaged portion of the completion. The successful acid placement in matrix treatments of openhole horizontal wells are even more difficult because of the length of the zone treated and potential variation of the formation properties. A successful diversion technique is critical to place the acid at the location where damage exists. A variety of diversion techniques have been practiced in acid stimulations (Rae and di Lullo 2003). Diversion sometimes can be achieved by simply increasing pumping rate during the acid treatment. Viscous diversion techniques such as hydroxyethyl cellulous (HEC) gelled brine and nitrogen foam are often used, especially when the temperature of the well is not very high. Other materials used as an acid-diverting agent include acid-insoluble particulates. A mechanic method such as a ball sealer also has been successful when it is practical. Most of these methods have some limitation to their application, especially in a completion with a sand-control method installed. VES-based diverting products have been developed and widely used in recent years, and their use has found application beyond the limitations of the previously mentioned techniques.

Near-Wellbore Formation Damage Effects on Well Performance: A Comparison Between Underbalanced and Overbalanced Drilling

Summary Prediction of formation damage that occurs while drilling horizontal wells is a critical point for optimizing an oil field's development. The economic impact of near-wellbore drilling-induced damage and cleanup efficiency has led to significant progress being made in both experimental and numerical studies to assess wellbore flow properties during oil production. As a result, a numerical model has been developed to study the impact of various parameters related to the properties of drilling fluids on well inflow performance. This paper describes a numerical approach developed in this model to simulate near-wellbore formation damage caused by underbalanced drilling (UBD). It is generally expected that UBD will be of benefit by preventing formation damage. However, this benefit can be lost for various reasons. For instance, an overbalanced pressure can be applied on the formation during short periods of time for various operational reasons and can cause severe formation damage because of the absence of external cake protection and huge filtrate invasion. Another possible cause of formation damage in UBD is related to spontaneous imbibition, which induces water-blocking, which was observed while drilling tight gas reservoirs. A methodology for the modeling of possible formation damage during UBD is presented. Crossflow phenomena caused by spontaneous imbibition is taken into account to model the filtrate invasion from the well to the porous media, as the well is in production.

Evaluation of Horizontal Well Performance After Drilling-Induced Formation Damage

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.

Acoustic Stimulation to Mitigate Near-Wellbore Damage

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 90356, "Acoustic Stimulation to Mitigate Near-Wellbore Damage," by Fred van der Bas, SPE, Eric de Rouffignac, SPE, and Pedro Zuiderwijk, SPE, Shell Intl. E&P B.V., and Diederik van Batenburg, SPE, Halliburton, prepared for the 2004 SPE Annual Technical Conference and Exhibition, Houston, 26-29 October. Near-wellbore formation damage reduces productivity in oil and gas wells. Formation damage can be caused by fluid invasion during the drilling and completion process and by particles in the production stream. The conventional technique to remove this damage is fluid injection to dissolve the damage. A promising new technique to remove the near-wellbore damage is high-frequency acoustic stimulation. A specially designed acoustic tool is deployed on wireline or coiled tubing (CT) to selectively treat damaged reservoir intervals. Introduction Near-wellbore formation damage can result from many activities during drilling, completion, and production. One of the most pervasive damage mechanisms is pore plugging by solid particles from drilling mud, drilled solids, or particles from the formation. It is not always possible to prevent formation damage, and well-stimulation techniques have been used to remove or mitigate the effect of formation damage for more than half a century. Although conventional well-stimulation techniques have been used very successfully, they have significant limitations in long horizontal wells and in wells with multiple branches. Acoustic cleaning is a promising well-stimulation technology that complements existing stimulation technologies and extends the range of options available for cost-effective well stimulation. High-frequency sound waves are used to “shake loose” damaging particles, and their effectiveness can be enhanced substantially by maintaining an underbalanced pressure in the well. The experiments described in the full-length paper are the first, to the authors’ knowledge, to be conducted with oil and connate water. The ultimate proof of acoustic-stimulation feasibility requires field trials.

High-Power/High-Frequency Acoustic Stimulation: A Novel and Effective Wellbore Stimulation Technology

Summary Local impairment of formation permeability often causes reduced production because of the interaction of the reservoir with drilling and completion fluids. The problem may be further compounded by impairment caused by fines migration during production. High-frequency sonic and ultrasonic waves have been used in many industrial applications to remove contaminants, such as dirt, oil, and grease from parts that are immersed in fluids. An obvious extension of this application is the removal of wellbore impairment by exposing it to high-frequency acoustic waves. The influence of high-frequency waves is limited to the near-wellbore environment because of high attenuation. Dedicated experiments under realistic downhole conditions have been carried out in both linear and radial configurations. We have examined the acoustic power needed to remove near-wellbore formation damage caused by fines and particles plugging pores as well as drilling-induced damage. Specific issues related to well completion and the envelope of acoustic stimulation are presented. The laboratory results have led to the design and construction of a slim, high-power, and high-frequency (above 10 kHz) downhole acoustic tool for field deployment. This paper outlines the concept and presents key experimental results to support the claim. Key features of a prototype downhole tool are also described.

The effect of fracture characteristics on reduction of permeability by asphaltene precipitation in carbonate formation

Crude oils produced in many parts of the world contain asphaltene. Asphaltene plugging is a known cause of near-wellbore formation damage. The deposition phenomenon of asphaltene has been extensively investigated in homogenous porous media. However, we have not found any reported experimental work on asphaltene plugging in naturally or artificially fractured reservoirs. The main objective of this study is to investigate the effect of fracture characteristics on reduction of permeability by asphaltene deposition in carbonate formation. A single fracture system is made with different fracture characteristics such as porosity, permeability, and fracture angle using saw-cut limestone core samples with metallic plate. The fracture aperture was kept constant for most of the studied systems. The effect of flow rate, fracture angle, matrix to fracture permeability, asphaltene concentration, and the state of stress on the retained permeability is presented. Different fracture angle orientations of 45°, 90°, and 180° relevant to the flow axis were investigated. A noninvasive imaging technique—scanning electron microscopy (SEM)—was employed to visualize changes on the surface of the fracture as a result of aspheltenic crude oil flow through the system.