bluuebunny/crossref_metadata_2025 huggingface dataset:
Selectively Stimulating Oil Production in Mature Naturally Fractured Carbonate Reservoirs
Authors: Guillot Guillermo , De Antuñano Yuri , Cuadras Romel , Milne A. , Miquilena E. , Losada M. , Molero Nestor , Mujica L. , Vazquez J. , Santini J.
Published: January 2016

Carbonate reservoirs in the southern region of Mexico are deep, hot, and naturally fractured. The intensity of natural fractures varies greatly. Wells in these formations are typically completed with multiple perforated intervals, with different producibility and pressure. The oil production is dependent on the presence of natural fractures, which, with time, are invaded by the aquifer, leaving the remaining reserves in the low-permeability formation matrix. The challenge when stimulating these wells is not only to selectively divert the treating fluid away from the natural fractures, but also to reduce water production from the natural fractures and fissures after the treatment.

To divert treating fluid from the lower-pressured natural fractures requires a viscous fluid with fibers or solid particles, whereas to limit water production after the treatment requires a disproportionate permeability modifier (DPM). However, the adsorption of conventional cationic low-viscosity DPM polymers is often limited in carbonates. This led to the development of a viscous zwitterionic DPM (ZDPM) fluid to both divert stimulation fluids from the natural fractures and reduce water production after the treatment. The ZDPM fluid comprises two polymers and a viscoelastic surfactant at a concentration below the critical micelle concentration. The adsorption and DPM properties of the polymers are further enhanced by adjusting the pH and salinity of the fluid.

More than 150 treatments have been performed in mixed carbonate formations with natural fractures and fissures using the ZDPM fluid. The oil production increased by as much as 220% while at the same time the water cut was reduced by up to 23%. This is supported by core flow testing in which the ZDPM fluid reduces the effective permeability to water by up to 80%, whereas in oil-wet cores, the fluid water-wets the core and effectively stimulates oil production, in some cases by more than 25%. The use of the ZDPM fluid has greatly improved the economics and feasibility of treating wet producers in naturally fractured dolomitic limestone reservoirs.

This paper summarizes the laboratory evaluation conducted to validate the use of viscous ZDPM fluid and the successful application in the field to divert stimulation fluids from the natural fractures and reduce water production after the treatment.
Developing a Marginal Field Combining Stimulation and Water Control to Limit Scaling
Authors: Martinez A. , Melo O. , Resendiz T. , Aguilar J. , Vazquez J. , Molero Nestor
Published: January 2016

Many oilfields in southern Mexico produce from naturally fractured carbonate reservoirs with a high water cut. The majority of the remaining reserves are in the formation matrix. The objective when stimulating these wells is to connect the formation matrix with existing fractures. However, in some cases, the water-oil contact is close to the producing interval and the salinity of the water is more than 350,000 ppm. This results in rapid scaling and loss of production. The time for the scale to plug the well is a function of the volume of water produced.

The challenge in these wells is not only to selectively divert the treating fluid away from the natural fissures/fractures—thief zones—invaded with water, but also to reduce water production from the natural fractures and fissures after the treatment. To treat the formation matrix, the diverter fluid must reduce the high permeability of the water-saturated intervals without impairing the permeability of the oil-producing intervals.

Historically, in southern Mexico, viscoelastic surfactants have been used as main diverter for acidizing treatments. However, these systems have been successfully implemented in other applications. The surfactant also acts as a disproportionate permeability modifier (DPM) as the water cut is reduced after the treatments. The water cut of wells stimulated with treatments including the surfactant-based diverter remains below 10%, and the wells typically produce over 1,000 BOPD for more than 200 days before the scale has to be removed. The water cut of wells treated conventionally in the same field is typically above 60%, and the wells produce for fewer than 50 days after being treated before plugging with scale. The ability of the solids-free surfactant-based diverter to limit water production has made possible developing a field that previously was considered uneconomic due to the saline precipitation into the formation.
Study of Condensate Blockage and Its Remedy in Eagle Ford Gas- Condensate Zone
Authors: Pu Hui , Li Yinghui
Published: January 2016

Tight gas condensate reservoirs are an important source of reserves and exhibit unique flow and thermodynamic behaviors. Owing to the overwhelming effects from nano-pores, formation damage mechanisms are uncertain. Significant phase and compositional change occurs in the circumstances where nano-pores dominate. Productivity reduces faster than most existing models could explain owing to a lack of understanding how the condensate affects deliverability, and how the flow and phase behavior would have been altered in unconventional reservoirs caused by those nano-pores. This paper presents a novel formulation that consistently evaluates capillary force using pore size distribution (PSD) directly from core measurements. This study develops a better understanding of production- induced formation damage in important liquid-rich formations for an optimal production strategy, to mitigate productivity risks associated with condensate blockage at reservoir conditions.
Effects of High Pore Pressure on Perforation Tunnels in Both High and Moderate Compressive Strength Rocks
Authors: Haggerty D. , Craddock G. , McGregor J.
Published: January 2016

Knowing the productivity to expect from a well is highly dependent on how deep the perforation penetrates. Besides the quality and explosive load of the shaped charge, the type of rock and the stress it is subjected to help determine penetration depth.

Using the equipment capable of stresses and pore pressures at extremes found in deep, outer-shelf wells, a made-for-purpose perforation laboratory offers insights regarding perforation behavior. Care was taken in the tests to ensure the configuration used matched a typical downhole setup including the applied stress on the rock target. Using Sandia National Laboratories' CTH shock wave physics software, computer simulations were run to compare with the results to offer further insight.

The results from the tests did not necessarily follow trends from extrapolating data from similar tests conducted at lower pressures, historically using matching net stress as a substitute prior to obtaining higher pressure-capable equipment. It was observed that a large increase in pore pressure resulted in only a small decrease in perforation penetration. Formations with various rock properties behaved differently, and with the new higher capacity equipment the ability to quantify these differences was improved. Other attributes beside penetration were observed such as perforation tunnel geometry differences between the high and moderate unconfined compressive strength (UCS) rocks.

This paper discusses the effects on the magnitude of penetration and quality of perforation tunnel in both the high and moderate strength rocks, and possible implications on flow. Simulation runs were conducted on the effects to a perforation at elevated pressure and compared to the test results showing the value of conducting such simulations and insights gained.
CO2 Injection to Mitigate Condensate Banking in a Low-Permeability Reservoir
Authors: Evans Edward , Ghalambor Ali , Orangi Abdollah
Published: January 2016

One of the main challenges of producing tight or low-permeability gas reservoirs is condensate banking when production starts as the reservoir pressure drops below the dewpoint pressure. Condensate banking causes formation damage and subsequently damages production. The normal procedure to mitigate condensate banking is to hydraulically fracture the well to bypass the condensate bank and improve production from that well. Modeling the condensate banking along the hydraulic fracture is critical to understanding the loss of productivity.

We investigated the feasibility of simulating a cyclic CO2 injection scheme to mitigate formation damage due to gas condensate dropout in a low-permeability gas reservoir. The field was modeled using a tartan grid to be able to model the hydraulic fracture explicitly. In addition to the hydraulic fracture, the study examined how much of a role the condensate-gas ratio (CGR) plays in the condensate banking and how to best position a well in a low-, medium-, and high-CGR fluid. For the mitigation phase, different cyclic parameters such as injection rate, injection pressure, and soaking time for the cyclic CO2 injection were considered.

The study found that the volume of the GCR played a critical role in determining injection rates and pressure to best be able to mitigate damage due to condensate banking.
Enhancing a Depleted Sandstone Formation with Single-Stage Acid in a Vietnam Offshore Case Study
Authors: Ao Taliwati , Thang Pham Cong , Loc Tran Duc
Published: January 2016

Stimulating offshore sandstone formations with depleted reservoir pressure is a challenge. The conventional practices for sandstone acidizing are to pump pre- and post-flush hydrochloric acid to minimize precipitates from the main hydrofluoric acid reacting with the carbonates, and to flow back the well immediately after the acid is pumped. However, in offshore wells, limited deck space for chemical mixing equipment and depleted reservoir conditions necessitated a retarded single-stage HCl/HF acidizing approach with nitrogen.

Because cores were not available, solubility testing was performed using cutting samples with normal HCl/HF acid and retarded single-stage HCl/HF acid. The retarded single-stage HCl/HF acid outperformed the conventional HCl/HF acid in these tests. Because of the challenge in treating long perforated intervals with various permeability zones and depleted reservoir conditions, the operator chose to pump retarded single-stage HCl/HF acid with nitrogen as a diverting and lifting agent. The retarded single-stage HCl/HF acid system eliminated the requirement of pre- and post-flush HCl acid stages, reducing the treatment complexity and overall treatment time.

The successful single-stage HCl/HF acid treatment resulted in a 225% increase in oil production and a 416% decrease in water cut. The decreased drawdown around the wellbore helped improve the oil-water ratio and deliver a lower water cut.

This paper summarizes the challenges of testing, designing and pumping the single-stage sandstone acid system in one well offshore Vietnam.
Novel Evaluation Method of Surfactant and Clay Inhibitor Performance on Fracturing Fluid Recovery for Eagle Ford and Mancos Outcrop Shale Cores using NMR Technique
Authors: Kim Jihye , Gomaa Ahmed M. , Zhang Hao , Nelson Scott G.
Published: January 2016

Because of the unique characteristics of shale formations including low permeability, existence of micro-fractures, and sensitivity to the contact fluids, it is difficult to evaluate the complex microscopic interactions between fracturing fluids and the formation in a traditional laboratory setting. Prior work (SPE 174186) demonstrated the value of using Nuclear Magnetic Resonance (NMR) to evaluate the interaction between shale formations and fracturing fluid components, such as clay control agents and surfactants. The subsequent work (SPE 179122) expanded the research to study more fluids and better understand why the performance of surfactants and clay inhibitors vary with the focus on the Barnett and Marcellus outcrop shale sample. The current work builds on the prior studies with further analyses focused on the high economic value shale play of Eagle Ford and Mancos shale sample.

Outcrop cores from the Eagle Ford and Mancos shales were evaluated in this study. Cores were submerged in various fracturing fluids under different experimental conditions: pressure of 400 psi, temperatures from 150 to 250 °F, and fluid contact times from 2 to 16 days. The change in the fluid volume in the cores during saturation and simulated flowback recovery process was quantified using NMR as a function of the T2 or relative pore radius. In this way, the amount of fluid recovered with different fracturing fluid additives were collected and compared to give formation-specific fluid recommendation based on the relative performance observed with the additives for fluid recovery.

Due to the variations of mineral composition and reservoir properties in different shale formations, the selection of fluid additives used in the fracturing fluids can be optimized based on the characteristics of each shale reservoir. For example, for the Eagle Ford outcrop shale cores with low clay content, any type of clay inhibitors tested in this study showed no sign of clay damage giving similar performance in flowback recovery. In contrast, the Mancos outcrop shale cores with moderate swelling clay content showed higher flowback recovery when treated with permanent clay inhibitor than temporary clay inhibitors.

This work extends understanding of fracturing fluid additives and shale interaction that, in many cases, are currently selected solely based on minimal testing and experience gained from conventional formations, rather than demonstrated performance in a particular shale formation. Moreover, this work opens an opportunity to customize fracturing fluids and services for enhanced fluid recovery by evaluating actual reservoir core from the given area of interest.
Engineering Hydraulic Fracturing Chemical Treatment to Minimize Water Blocks: A Simulated Reservoir-on-a-Chip Approach
Authors: Kim Jihye , Gomaa Ahmed M. , Nelson Scott G. , Hudson Harold G.
Published: January 2016

Fracturing fluid trapping is one of the major sources of damage after well stimulation as the remaining fluids in the pore space reduce the effective hydrocarbon permeability. Especially in tight formations, fluid trapping can require significant time to clean up, even at a high production rate. Outcrop cores have traditionally been used to confirm the existence of damage and to quantify it. However, it is difficult to clearly discern the trapping mechanism in cores and to accurately determine the trapping location and the volume of residual fluid.

In this study, a reservoir-on-a-chip approach was adapted to visualize the residual water blocking process of fracturing fluids. The major advances in using this approach are the clear visualization of the trapping process in the pore space and the control of testing parameters including formation wettability, reservoir/stimulation fluid properties, flow rate, and reservoir pore-space geometry. This study includes two sections: A fluid mechanical study to determine which reservoir conditions require chemical treatments to mitigate water blocks; and a chemical evaluation study to determine how well chemicals, such as surfactants, can alleviate severe water block conditions.

Experimental results confirm that the geometry of the pore throat plays a critical role in trapping and releasing fluid. Furthermore, displacing reservoir fluid at high rates, or with a higher oil viscosity, increases cleanup efficiency. With this fundamental understanding, the reservoir conditions that require chemical treatment can be identified. Cleanup efficiency was significantly improved by using a surfactant. The designs of engineered chemical treatments to mitigate water blocks under specific conditions will be discussed in this paper. These new findings expand the industry’s understanding of the fluid mechanics behind residual fluid trapping, capillary effects, and the implications for engineered fracturing fluid systems.
Theoretical and Experimental Study on Optimal Injection Rates in Carbonate Acidizing
Authors: Dong K. , Zhu D. , Hill A. D.
Published: January 2016

Optimal acid injection rate is critical information for carbonate matrix acidizing design. This rate is currently obtained through fitting acidizing coreflood experimental results. A model is needed to predict optimal acid injection rates for various reservoir conditions.

A wormhole forms when larger pores grow in cross-sectional area at a rate that greatly exceeds the growth rate of smaller pores due to surface reaction. This happens when the pore growth follows a particular mechanism, which is discussed in this paper. We have developed a model to predict wormhole growth behavior. The model uses the mode size in a pore size distribution - the pore size that appears most frequently in the distribution, to predict the growth of the pore. By controlling the acid velocity inside of it, we can make this particular pore grow much faster than other smaller pores, thus reaching the most favorable condition for wormholing. This also results in a balance between overall acid/rock reaction and acid flow. With the introduction of a porous medium model, the acid velocity in the mode-size pore is upscaled to the interstitial velocity at the wormhole tip. This interstitial velocity at the wormhole tip controls the wormhole propagation. The optimal acid injection rates are then calculated based on semi-empirical flow correlations for different flow geometries.

The optimal injection rate depends on the rock lithology, acid concentration, temperature, and rock pore size distribution. All of these factors are accounted for in this model. The model can predict the optimal rates of acidizing coreflood experiments correctly, as compared with our acidizing coreflood experimental results. In addition, based on our model, it is also found that at optimal conditions, the wormhole propagation velocity is linearly proportional to the acid diffusion coefficient for a diffusion limited reaction. This is proven both experimentally and theoretically in this study. Since there is no flow geometry constraint while developing this model, it can be applied to field scales. Applications are presented in this paper.
Laboratory Simulation and Damage in Open Hole Water Injectors
Authors: Byrne Michael , Kandasamy Ram , Bruce Angela
Published: January 2016

Completion design in water injection wells has received a lot of attention in recent years. With increasing deployment of sand control and the desire not to fracture with water injection, a much greater emphasis needs to be placed on selection of the optimum drilling, completion and clean-up fluids sequence compliant with the completion hardware.

One tool available to help with the selection process for fluids for drilling and completion is laboratory simulation testing. If performed properly and with attention to the detail required to simulate fluids and hardware, these tests can be employed to predict and optimise well performance.

Taking different examples from different field developments we demonstrate the process of test design and propose some interesting amendments for future test designs. We cite some examples of low or no flow in the laboratory and discuss the implications for real well design and geometry. We also challenge some long held assumptions on the "best" fluids to use for open hole water injection wells.

The paper adds to industry knowledge on this topic and to the development of more representative and revealing laboratory tests. Using real examples from well planning and the subsequent well performance we illustrate the importance of using available tools to help in the design of wells.
Sand Retention Testing: Reservoir Sand or Simulated Sand - Does it Matter?
Authors: Ballard Tracey , Beare Steve , Wigg Nicola
Published: January 2016

Sand retention testing obviously requires sand, and using the reservoir sand is the most straightforward option. However, sometimes reservoir sand is not available in sufficient quantity, and in these instances a particle size distribution matching the reservoir sand is prepared from commercial outcrop sand. The authors were aware that there can be some differences between the results from outcrop and reservoir sands and generally only use reservoir sands, but a recent request for tests using simulated sands gave the impetus for a systematic study of the variations.

Retention tests have been performed with different reservoir sands and two versions of their respective simulated sands; one matched to their laser particle size distribution and one matched to the sieve analysis distribution. Sandpack tests and two slurry test methods (xanthan and caesium formate) have been performed with a range of wire wrap and metal mesh screens. There are quite striking differences in the pressure data recorded between the actual reservoir sands and the simulated sands. The trend in the amount of sand produced between reservoir and simulated sand is still uncertain, but the study has shown some instances that could change the screen recommendations. Efforts have been made to understand the differences between reservoir and simulated sands by examining particle shape.

The results of this study show that using sands simulated from outcrop rock can give retention test results different from those obtained with reservoir sands. This and other potential test artefacts should hopefully discourage reading too much into retention test data; especially for estimating likely sand production. Predictions of sand screen performance based on lab studies will remain problematic until comparisons with field performance (both failures and successes) can be made.
Choke Management Strategies for Hydraulically Fractured Wells and Frac–Pack Completions in Vertical Wells
Authors: Karantinos Emmanouil , Sharma Mukul M. , Ayoub Joseph A. , Parlar Mehmet , Chanpura Rajesh A.
Published: January 2016

When a well is brought on production, the selection of an optimum choke management strategy is aimed towards maximizing well productivity and minimizing the risk of typical wellbore failures during the early life of a well. In this study, a quantitative method is presented for the selection of a choke management strategy that minimizes the risk of the predominant failure mechanisms in hydraulically fractured wells and frac-pack completions. For example, in unconventional resources, an improper choke management strategy may trigger the back flow of excessive amounts of proppant, resulting in fracture closure and possible wellbore damage and loss of production. In frac-packs and high-rate water packs, an abrupt increase in the rate (or drawdown) may induce completion damage resulting in impaired production and possibly sand production, requiring excessive and costly workovers.

It is shown that in hydraulically fractured wells, choke management strategies should aim towards minimizing pressure gradients along the fracture, thus making proppant flowback and potential reduction/loss of fracture conductivity or its connectivity to the wellbore less likely to occur, for a given set of formation properties and closure stress. Choke management strategies are compared for a wide range of formation and fracture properties including fluid properties, matrix permeability, fracture conductivity and fracture length. Results indicate that in unconventional formations (k<0.01md) there is a unique choke management strategy, which consistently appears to be the best. The methodology is coupled with previous studies that have focused on determining the critical pressure gradient for which proppant flowback is observed.

In frac-packs and high-rate water packs, completion failure may occur due to excessive fluid velocities along the frac-pack or exaggerated pore pressure gradients at the completion sandface. Choke management strategies are compared for a wide range of formation and completion properties. Results indicate that in frac-packs and high-rate water packs, the selection of the optimum choke management strategy is similar to that of open-hole completions, with bean-up operations achieving a relatively higher reduction in pressure gradients for the case of low values of dimensionless fracture conductivity. The greatest reduction in pressure gradients can be achieved by considering bean-up operations during completion design.

The results of this study provide, for the first time, a clear methodology for selecting choke management strategies in hydraulically fractured wells and frac-pack completions for a wide range of reservoir and fluid properties.
Stability Determination of Acid Emulsions by Droplet Size Characterization With Static Light Scattering
Authors: Weissenberger Markus C. , Khalafpour Peyman
Published: January 2016

Acid emulsions as aqueous acid in oil emulsions are used widely as either acid delayed systems or to clean up formation damages. The stability of emulsified acid blends at room and elevated temperatures is a crucial factor for a successful job execution. To predict the stability and reactivity so far mainly indirect methods, such as visual inspections or conductivity measurements, are used in the industry. These methods are often inaccurate and subjective. They can also lead to a wrong interpretation of acid emulsion stabilities, especially at elevated temperatures. In this study we are presenting a new method of stability determination of acid emulsions by the detection of the droplet size through static light scattering. Static light scattering (or laser diffraction) is a widely used particle sizing technique for materials ranging from several nanometers up to several millimeters in size. This is the typical size range of emulsions. The technique by itself is well-established, allows rapid measurements, and does not need an external calibration. By using this method, we were able to correlate the droplet size of acid emulsions with their stability and to study the influence of different parameters such as solvent, surfactants or temperature. Only the change of the solvent (e.g., from xylene to diesel) can have a tremendous influence on the stability of a 28% hydrochloric acid emulsion. The study of acid emulsions was executed with different solvents, surfactants, acid strengths, and temperatures. Through the direct determination of the acid emulsion stability by measurement of the droplet size, we are able to predict the emulsion stability at elevated temperatures very accurately. This method is also suitable for such emulsions that possess remarkably high acid strengths.
Enhanced Oil Recovery Using Innovative Asphaltene Inhibitors in East Venezuela
Authors: Villard Y. , Fajardo F. , Milne A.
Published: January 2016

Use of adsorption asphaltene inhibitors in mature oil fields in eastern Venezuela has reduced operating costs and deferred production. As is common in mature fields, some fields in the northern district of Monagas state, Venezuela, such as Furrial, Musipan, and Boquerón fields, have had increasing problems of asphaltene deposition for a number of years. Asphaltenes present in a crude oil under normal reservoir conditions will start to flocculate and precipitate in the critical near-wellbore matrix as the reservoir pressure drops, which greatly reduces the productivity of the reservoir. Conventional asphaltene treatment is a two-step process that involves removal of the deposits by pumping solvents and asphaltene dispersants into the formation using coiled tubing. The frequency of the treatments increases as the reservoir pressure drops, and, in some fields, it is common for wells to be treated every 30 days or less, resulting in deferred production and increased costs. Conventional asphaltene inhibitors precipitate in the pore spaces in the matrix of a formation and then slowly dissolve in the produced crude, preventing the flocculation of the asphaltene present in the crude. In contrast, the new generation of asphaltene inhibitors adsorb onto the surfaces of the pore spaces in sandstones or onto the fracture faces in carbonates, providing protection from asphaltene deposition in the formation, tubing, and flowlines over an extended period of time.

These adsorption asphaltene inhibitors were first used in Venezuela to treat wells in the Boquerón field that historically had been treated every 60 days to maintain production. Wells treated with adsorption asphaltene inhibitors maintained their production for over 180 days, greatly reducing both operating costs and deferred production. Results from laboratory tests on the adsorption inhibitors, field operations experience, and lessons from treatment evaluations were incorporated into a workflow that enables optimizing asphaltene inhibition for new fields.

The use of the adsorption inhibitors has reduced the logistics and time required to place these inhibitors in the formation and has greatly decreased the frequency of the treatments needed to maintain the overall production. The initial success of these treatments has led to additional asphaltene inhibition campaigns in other fields.
Comprehensive Field-Scale Injection Performance Analysis Associated with Injected Water Quality Parameters
Authors: Sabut Bangkong A. , Al-Hajri Nasser M. , Al-Ajmi Mohammed D. , Al-Zahrani Rashad M. , Nasr-El-Din Hisham A.
Published: January 2016

This paper presents a comprehensive injection performance analysis conducted in major carbonate fields in Saudi Arabia. The production from the fields under study is pressure-maintained by peripheral water injection. More than 190 case studies were examined to generate populated trends and draw relevant conclusions on parameters affecting injection performances. Petroleum engineering concepts/tools, such as pressure transient analysis, were heavily used in this work to establish the effective yearly injection decline rate for each well.

Extensive and dedicated sampling of injected water was carried out as part of water quality monitoring to ensure that well plugging and internal corrosion was minimized. The total dissolved solids, total suspended solids, particle count and size distribution, acidity, iron count, sulfide content, and bacterial growth data were measured and synchronized with the respective wells' injectivity indices to identify potential sources of well injection impairments. Major events, such as when starting or switching the water injection system, were thoroughly factored into the water quality analysis and its subsequent effect on the injection performances.

The well injection performance analysis was carried out using pressure-transient analysis data obtained from Fall-Off Test (FOT) surveys, where each well has a baseline II survey taken when the well was first drilled and completed. Dimensionless injectivity indices were defined to compute the injection potential of each well. Baseline surveys were then compared with the subsequent or the latest surveys, if any, based on which time-lapse measurement trends were generated and analyzed.

Several key findings and recommendations, regarding setting appropriate limits to water quality parameters and injection surveillance strategy, are presented in light of the performed analysis.

This paper also discusses production engineering efforts to mitigate the decline in well injectivity, including: water quality control, well stimulation initiatives to enhance injectivity, and analysis of well plugging characteristics/profiles and their relation to reservoir permeability.
An Innovative Approach to Gel Breakers for Hydraulic Fracturing
Authors: Fuller Michael J.
Published: January 2016

Gelled fluids are routinely used in hydraulic fracturing to deliver fractures with higher propped width, due to the fluids' abilities to deliver higher proppant concentrations than their lower-viscosity analogues. The most common of these gels (borate-crosslinked polymers) have been used successfully in fracturing for decades, routinely exhibiting viscosity >100cP in conventional high-pressure, high temperature (HPHT) viscosity measurements. Recent studies have found that the viscosities of borate gels at actual downhole pressure conditions may be 80% less than that measured using standard HPHT rheometer measurement (which uses 400 psi top-pressure). A proposed mechanism for this phenomenon is a pressure-induced shifting of the crosslink/temperature stability near the "melt temperature" of borate-crosslinked gels, leading to a reversible thinning. A novel approach is posed in the current work to exploit the "pressure effect", by capturing the pressure-thinned fluid in a thin state and irreversibly breaking the gel viscosity.

As existing crosslinked-gels with oxidative breakers rarely achieve >50% retained pack-permeability, an improved break mechanism based on pressure could yield sizeable productivity-gain in propped fractures. A series of candidate breaker materials with potential affinity for the crosslinker was screened for gel-breaking performance in the current work. Preliminary screening of these additives led to one preferred alternative gel breaker material which demonstrated superior performance in pressure-induced breaking behavior. This study will illustrate advanced characterization of the breaker performance utilizing realistic sequences of temperature, pressure and shear rate that would be expected for a fracturing treatment. The advanced characterization also included fracture-conductivity measurements comparing a control gel with and without the alternative breaker.

Under these conditions, the fluids containing the candidate breaker material showed persistent viscosity-break, while the control fluids recovered their viscosities upon pressure-release. The preferred breaker material performance was further confirmed through a series of experimental conditions varying temperature, pressure (up to 10,000 psi), gel concentration, and breaker concentration. In fracture conductivity measurements, the gel which contained the preferred breaker also showed improved conductivity compared to control fluids without breaker.

The current study proposes a new method of achieving break of gelled fracturing fluid, which avoids some of the risks and disadvantages of oxidizer chemicals. These results will suggest the most preferred fluid conditions for applying the new breaker material in hydraulic fracturing.
Removing Formation Damage From Fines Migration in the Putumayo Basin in Colombia: Challenges, Results, Lessons Learned, and New Opportunities after More Than 100 Sandstone Acidizing Treatments
Authors: Reinoso Wildiman , Torres Fredy , Aldana Manuel , Campo Pablo , Alvarez Emilce , Tovar Erika
Published: January 2016

This paper summarizes a wide variety of sandstone acid stimulation case histories, highlighting different aspects, such as mechanical conditions and operational practices. These include injection sequence changes, injectivity factor calculations, treatment volumes, quality control during pumping, pressure response, and the influence of each on treatment performance.

To date, more than 100 sandstone acidizing treatments have been performed in several Colombian oil fields, targeting the Villeta and Caballos formations in the Putumayo basin. Fines migration has been the main damage mechanism treated with this type of chemical stimulation. Three main steps were performed when sandstone acidizing treatments were conducted: preflush, primary treatment, and post-flush. A fines-control retarded hydrofluoric (HF) acid system was selected as the primary acid system. This retarded system removes deep damage caused by fines and swelling clays and helps prevent fines migration.

Challenges, results, lessons learned, and new opportunities from the understanding of theoretical aspects, acid-removable skin analysis, and integration of coreflooding tests with computer simulations as well as post-treatment results showing several-fold increases in oil productivity are presented in this paper. Treatments developed in reservoirs with a temperature of 180°F, as well as use of scale inhibitors and treatments assisted with relative permeability modifiers (RPMs) to control water production, are discussed. Also, results of testing with a biodegradable chelating agent that could provide an alternative treatment for some scenarios are presented. The aminopolycarboxylic acid (as described by Reyes et al. 2013) used is soluble in a low-pH aqueous medium and is compatible with HF acid.

The step-by-step procedures identify the parameters that have the most influence on treatment performance and provided outstanding results. The resulting lessons learned can be applied for future applications in many more candidate wells with similar conditions.
Effective Resin Consolidation Treatment Methods and Compositions for Clay-Laden Formations
Authors: Rama Mallikarjuna Shroff , Songire Sumit , Meher Pratiksha , Kristanto Tutus Agung , Latief Riyanto , bin Zulkapli Mohd
Published: January 2016

Resin consolidation of the near-wellbore (NWB) region is often performed to control sand production. However, when the formation is composed of a higher content of clays and fines, particularly when the swellable clay content is higher than 4%, it can be challenging to treat the formation and obtain good consolidation with acceptable retained permeability. Possible reasons for this include: 1) smaller grain size and smaller pore throats can hinder any resin coating, affecting the retained permeability and 2) the resin can enter into the interlayer and swell the clays infinitely, eventually blocking the pore throats.

Improved methods to provide consolidation to clay-laden formations are described based on laboratory testing and analysis. The effects of various treatment methods, such as using clay-control agents during the preflush stage of the resin treatment and reducing the viscosity of the resin treatment fluid to obtain optimum consolidation and retained permeability, are discussed.

The present method uses cationic organic polymers (COPs) in the preflush that can control swelling clays followed by less-viscous resin treatment fluid, which can form a thinner coating around grains and provide acceptable strength without significantly compromising regain permeability.

Laboratory testing was performed on various formation sands having higher clay content, 5 to 10%, combined with fines ranging from 5 to 15%. The results showed that traditional resin consolidation treatments do not provide acceptable retained permeability and consolidation strength. Using COPs in the preflush provided improved retained permeability. Using a combination of COPs in the preflush and a diluted resin treatment provided significantly improved results. This shows that COPs help prevent clays from swelling. The resin cannot enter the interlayer and swell clays any further, thus improving retained permeability. Additionally, when the treatment fluid is diluted, it can penetrate uniformly throughout a sandpack, providing a thinner but sufficient coating of the resin to achieve good consolidation and also good retained permeability.

A novel method and composition for a resin consolidation service to obtain effective consolidation strength and acceptable retained permeability in clay-laden formations is demonstrated by means of laboratory testing of the actual formation sand.

Previously, it was impossible to consolidate a formation that possesses large amounts of fines and clays while maintaining retained permeability in an acceptable range. This new method is applicable in the field without requiring additional tools or more stages during the treatment procedure.
Perforating Large High-Pressure Wells with Low-Shock and Low-Debris Gun Systems
Authors: Baumann C. E. , Smart M. E. , Stulb C. , Brinsden M. S. , Gavric Z. , Le C. V.
Published: January 2016

Many large wells have been drilled in the Gulf of Mexico's Lower Tertiary play. These wells are completed with single-trip multizone systems, and they have gross perforated lengths exceeding 1,500 ft. The main difficulty in perforating these wells is the high-pressure environment (~20,000 psi). Under these conditions, the challenges are to create sufficiently large entrance holes in the casing, minimize the high-risk of equipment damage due to gunshock, and minimize the amount of perforating debris created.

Perforating several intervals in a single run is required to complement single-trip multizone systems. Perforating all zones simultaneously in one trip saves time and reduces risks when compared with stacked completions requiring multiple trips for each zone. Safety and cost reduction are extremely important in deepwater operations. Risk control is very important because gunshock and/or debris problems can lead to multimillion dollar losses in non-productive time, and in extreme cases, gunshock problems can lead to lost wells.

To undertake these challenges, a new Low Perforating Shock and Debris (LPSD) gun system was used. In comparison with standard high-pressure guns, the LPSD gun system produces much less gunshock and negligible amounts of debris; thus, minimizing gunshock risk and reducing cleanup runs typically needed to recover perforating debris. LPSD guns produce negligible amounts of debris because LPSD guns contain all the metallic components, including the shaped charge cases, which remain virtually intact inside of the guns. A key element in planning these perforating jobs is gunshock prediction to evaluate if the equipment will be able to withstand the transient loads produced by the perforating guns. The gunshock prediction process is described in detail in this paper.

For a typical 4-zone 1,500 ft gross length perforating job, the time needed from picking up the first gun to laying out the last gun averages 84 hours. All zones are simultaneously perforated, which eliminates three perforating runs per well, saving approximately 9.2 days per well while minimizing personnel exposure. By perforating the largest high-pressure wells in the Gulf of Mexico's Lower-Tertiary play with LPSD guns, we minimized personnel exposure, minimized debris and reduced execution time up to 72%.
Applied Buildup Well Test Interpretation: Field Testing of Conventional and Deconvolution Methods
Authors: Rosario Omar , Martinez Mauro , Baumann Carlos , Ardila Mario
Published: January 2016

Well tests are typically used to evaluate formation damage before and after workovers. Buildup tests are the most commonly used transient because less flow rate measurement uncertainties leading in more reliable results, and they have a robust mathematical foundation. To take in account the flow rate history and its uncertainties several deconvolution algorithms were developed. These algorithms also are applicable to minimize the initial distortion in the reservoir's pressure response due to wellbore storage, with the expectation of improving the permeability and total skin estimated in shorter logging times.

This paper presents a comparative study of conventional well test methods, and direct and indirect deconvolution techniques in several field cases. This study includes buildup tests of real-time sandface rate measurements during the after-flow period. These field cases were analyzed using conventional well test methods and three deconvolution techniques; namely, straight line approximation, material balance deconvolution, and modified "β" function.

We determined that the three deconvolution methods are preferable to conventional well test methods because they require much shorter logging times; however, their reliability depends on the real-time data acquisition quality.

The well tests analyzed show that we cannot rely solely on the new deconvolution techniques for well test interpretation in shorter times; however, these new methods improve the reliability in the main matching parameters, permeability and total skin, at no additional time and cost. As a result, the new methods are excellent additions to the techniques used for well test interpretation.
Novel Perforation and Stimulation Approach to Maximize Production from HPHT Sour Gas Wells: Kuwait Jurassic Best Practices
Authors: Pradhan San P. , Al-Otaibi Yousef M. , Al-Mutairi Abdullah B. , Mahmoud Wael , Abdelbagi Mamoun. E. , Slama Hedi
Published: January 2016

Optimized perforation and stimulation approach was developed to maximize production and overcome heavy oil based mud (OBM) associated damage for HPHT condensate wells (matrix-dominated flow) from Jurassic formation in Kuwait. This paper shares the challenges, approach and results of this novel methodology that led to significant production enhancement.

Heavy OBM is the drilling and completion fluid for deep carbonate formation of Jurassic era reservoirs in Kuwait. Conventional tubing conveyed perforation (TCP)/Wireline perforation requires well killing to run final completion. Production tests carried out before and after running final completion showed significant drop in production of hydrocarbon. Conventional coil tubing acid jobs was performed to bypass the damage but still production was well below expectations. After analyzing pros and cons of multiple perforation and completion methodologies, finally gun hanger shoot and drop perforation system was re-introduced for Jurassic wells.

Robust design and completion process was developed for successful execution as previous attempts of gun hanger shoot and drop system was not successful due to extreme environment (16,000 ft Depth, 11,500 psi Reservoir Pressure, 4% H2S, 3% CO2). Successful execution using gun hanger shoot and drop system with ‘just in time’ firing facilitated underbalanced perforation with immediate production tests and no requirement of further killing of well. Engineered perforation and gun design helped in optimizing space available below zone of interest for any well intervention activities. Initial well tests showed encouraging production result with significant oil and gas flow. Thick walled coil tubing was successfully deployed in live well to perform well activation in extreme environment to bypass formation damage caused during drilling process and improved acid placement. Combination of acid and produced hydrocarbon led to In-situ generation of emulsified acid providing deeper penetration of acid. Acid pumping rate and pressure was optimized to generate conductive acid etched channels and avoid creation of inefficient fractures. Cross-segment collaboration led to successful execution in challenging conditions leading to five-fold increase in production post stimulation.

Gun hanger shoot and drop system was successfully re-introduced for underbalanced perforation in extreme Jurassic environment. Coil tubing operation was performed for the first time in a live Jurassic well with bottom hole pressure close to 15,000 psi and H2S close to 4%.