bluuebunny/crossref_metadata_2025 huggingface dataset:
Chemical Sand Consolidation as a Failed Gravel Pack Sand-Control Remediation on Handil Field, Indonesia
Authors: Mahardhini Antus , Abidiy Izzad , Poitrenaud Hugues , Wiendyahwati Shinta , Mayasari Fanni , Wood Timothy , Ariadi Dicha , Magee Ceallach
Published: May 2015

Handil field is a mature oilfield located in East Kalimantan Indonesia, operated by TOTAL E&P Indonesie (TEPI). By 2012, there were several wells completed with Gravel Pack completions that were producing sand during production phase. This condition created a hydrocarbon production limitation around 3700 bopd from three oil wells. TEPI were looking at technical solutions to improve well performance. Within the solution options that exist, chemical treatments - that consolidate the near wellbore area - can be a viable alternative for a number of completion types. Chemical sand consolidation can give a formation additional residual strength. This can enhance a maximum sand free rate (MSFR).

One chemical treatment developed is environmentally acceptable by North Sea standards and simple to deploy by in a ‘one pass’ pumping operation. Looking at the completion type and complication during sand control remediation pumping, this chemical was finally chosen. The simpler deployment operation, since there is no overflush, induces less risk during pumping the treatment. The active chemical reacts with connate water in the near well bore area and forms a polymerized network around and between the sand grains. This network imparts additional residual strength allowing the near well bore formation to withstand greater drawdown and fluid flow.

This paper discusses the experiences of TEPI with respect to using the organo-silane based chemical treatment in Handil field, Indonesia. A well intervention campaign treats a number of production zones which were treated separately by sliding sleeve door (SSD) selection. To ensure liquid cleanliness prior injection into formation, the use of coiled tubing was required and the treatment programs were adjusted from standard designs to accommodate this. Most of the operation performed resulted in an increase of the MSFR (leading to production increase). One job result however was not as per expectation. The lessons learnt from these treatments and improvements in candidate selection will be discussed here.

This first coiled tubing application of the organo-silane based chemistry and the need to manage multiple small batches of the water sensitive treatment in a humid and wet environment were challenges to overcome.
A Shallow-Penetration Polymer Sealant for Water and Gas Control: Case Histories and Lessons Learned After More Than 250 Well Interventions
Authors: Vasquez Julio , Curtice Richard
Published: May 2015

This paper presents the field implementation of a shallow-penetration conformance sealant (SPCS) system for water and gas control applications. This system combines an organically crosslinked polymer (OCP) gel system with fluid-loss control additives and noncement particulates. The additives/particulates provide leakoff control properties, which can lead to shallow matrix penetration of the sealant. This filtrate from the leakoff is then thermally activated at a predicted time. After exposure to the bottomhole temperature of the well, it forms a three-dimensional (3D) gel structure that effectively seals off the targeted interval. This system can be considered an alternative to conventional cement squeeze operations in scenarios where these types of treatments are not an option. The system can either be bullheaded into the wellbore or deployed with coiled tubing (CT). The limited and controlled leakoff into the matrix during the squeeze results in a controlled depth of invasion. Selective reperforation of treated zones is an option if the zone still has hydrocarbon potential. The system can be easily washed out of the wellbore compared to cement, which must be drilled out. Case histories are presented along with lessons learned from more than 250 treatments highlighting the diagnostic stage.

The SPCS system has been successfully tested to withstand a differential pressure of at least 2,600 psi and is resistant to acid, CO2, and H2S environments. (1) SPCS performance testing, (2) recent improvements to the system, (3) design considerations and best practices for field implementation, and (4) case histories are discussed. The working temperature range of this system is 40 to 400°F. To date, more than 250 treatments have been performed with the SPCS system globally to address conformance problems, such as perforation shutoff, gravel-pack isolation, fracture shutoff, poor zonal isolation, and/or casing-leak repair. Because of the capability of the SPCS system to withstand pressure, workover operations have been successfully performed in previously treated wells, including acid stimulation, sand control, and frac-pack treatments, among others. A primary objective of this paper is to help provide assistance during the candidate selection process and design of this particular sealant treatment.
Mitigating Formation Damage by Using Completion with Built-in-Casing Perforations Instead of Perforation with Explosive Charges
Authors: Rastegar Reza , Munawar Mohammed , Nowowiejski David , Granberg Ståle , Mehus Cathrine , Benson Andy
Published: May 2015

The downside of the conventional perforating method with explosive charges and guns is that it is risky. In addition to this, the method has a negative effect on the near wellbore permeability, and it creates mechanical damage. The impact stress associated with shaped charge and the outward travelling shock wave weakens the rock matrix, which increases the risk of sand production. Another negative impact of the shape charge is the creation of a low permeability zone, in which sand grains are forced toward the vicinity of the perforation chamber. For example, a perforation process with a 55% permeability reduction around the perforation tunnel led to 60% reduction in well productivity. An intended large underbalance differential pressure offers, to some extent, a solution to clean up the crushed zone. However, the de-bonded and weakened structure of the damaged zone is irreversible. The required surge pressure to clean up the perforations varies from 200 to 5,000 psi, because not all the perforations react the same way.

On the other hand, built-in nozzles cause no damage to the formation, because no charge or shock is imposed to the formation. Furthermore, there is no longer an impact from underbalance or overbalance pressure differential between wellbore and formation. In this paper, we will introduce the engineering and mechanism of built-in casing (BIC) nozzles. With BIC, nozzles are activated from surface with deployment of specific activation tools. Once the tool engages with the targeted profile, the nozzles are opened and projected to the wellbore fluid. With circulation of cement-dissolving fluid, cement breaks and formation connection is initiated. Quantity and size of nozzles are engineered as per downhole production design criteria.

In unconsolidated or poorly consolidated reservoirs, the strength of the rock structure should be evaluated to reduce the risk of sand production. Ultimately, the differential pressure shall be high enough to effectively clean the perforations, but not so high as to cause sand production.

As mentioned above, there are a great deal of scenarios and variable parameters involved in perforation with shape charges that have to be taken into consideration to ensure an effectively performing set of perforations. Because such a study and remedial approaches are costly and not always guarantee results, an alternative method is to use BIC perforations.
Stabilizing CO2-Foam using Nanoparticles
Authors: Emrani Arezoo S. , Nasr-El-Din Hisham A.
Published: May 2015

Foamed fluids have been used for decades to diminish formation damage in nearly all kinds of unconventional reservoirs with a wide range of pressures. Although water-based fluids are widely used in the oil industry as one of the most economic hydraulic fracturing methods, foams are another substitute to fracture water-sensitive reservoirs at which damage to pore throats is caused by swelling clays or fines migration. The mixture of CO2 and surfactant as a CO2-foam not only reduces formation damage by minimizing the quantity of aqueous fluid which enters the formation, but significantly improves sweep efficiency. Even though it is common to utilize surfactants in order to generate and stabilize foams, surfactants tend to degrade at high temperatures and in high salinity environments. Adding nanoparticles can solve the aforesaid problems and can increase foam stability.

The choice of surfactant concentration is a critical step in preparing more stable foams. In the present work, using CO2/alpha olefin sulfonate (AOS) solution as a new foaming solution is introduced for optimizing surfactant concentration in order to generate a stable CO2-foam in unconventional reservoirs. Several experimental studies were conducted to obtain the optimal surfactant concentration using a pendant drop method for CO2/solution and CO2/nano solution. Moreover, the effects of temperature, pressure, salinity, and surfactant concentration on surface tension and the critical micelle concentration (CMC) value were studied at high pressure and high temperature (HP/HT). In these experiments the temperature ranged from ambient conditions to 302°F, while the pressure increased from atmospheric up to 435 psi. AOS solutions were prepared using different brine concentrations ranging from 1 to 10 wt% of NaCl and different surfactant concentrations from 0 to 1 wt%.

Experimental results indicated that the CMC value increases as temperature increased. It also decreased while salt concentration increased. Furthermore, for a given temperature and salinity, the results did not exhibit changes in the CMC value when the pressure increased. The addition of nanoparticles decreases the CMC value.

A number of research studies have been conducted to investigate the CMC value and surface tension for AOS at ambient conditions using N2. However, minimal work has been performed in order to determine such characteristics at reservoir conditions. The present work will provide a new foaming solution in order to evaluate and optimize surfactant concentrations. The present work will also investigate the effect of mixtures of surfactant and nanoparticles on the formation of stable CO2-foam in unconventional reservoirs.
GLDA/HF Facilitates High Temperature Acidizing and Coiled Tubing Corrosion Inhibition
Authors: Reyes Enrique A. , Smith Alyssa L. , Beuterbaugh Aaron , Calabrese Tristen
Published: May 2015

An existing limitation of chelant-based fluids available for sandstone acidizing with hydrofluoric acid (HF) is the presence of sodium in the concentrate of the aminopolycarboxylate fluid, which is common in all chelating agents soluble below pH 3.5. The presence of sodium complicates stabilization of the fluid during acidizing processes because of the myriad of chemical reactions that can impact the outcome of a treatment. The use of chelating agents has expanded the temperature range as well as the type of clay minerals that can be exposed to an HF fluid; however, limitations still exist. Core flow testing at 360°F and corrosion testing from 265 to 360°F were conducted. Flow tests were performed using outcrops of two types of sandstones and inductively coupled plasma (ICP) analysis was conducted to elucidate the ionic composition of the spent fluid. Results reported stem from core flow testing with glutamic acid diacetic acid (GLDA) containing HF at very high temperatures (360°F). To encompass a broad range of mineral composition, two types of sandstone cores were employed—heterogeneous (Bandera, 65% quartz) and clean (Leopard, 95% quartz). Corrosion inhibition of the GLDA/HF fluid for use with coiled tubing (CT) was achieved up to 320°F, employing varying classes of inhibitors. The GLDA/HF fluid exhibited lessened corrosion tendencies and could be inhibited for at least 6 hours at 360°F for drillpipe (mass loss rates of 0.025 to 0.05 in./ft2 were obtained).

The presence of sodium in GLDA/HF could be managed, leading to effective permeability improvement of the Bandera core, while the Leopard core underwent a decrease in overall permeability; this latter observation was attributed to the formation of metal fluorides. Neither the presence of CaCO3 in the Bandera substrate or the use of KCl brine substituting for the usual NH4Cl led to permeability impairment. The overall results indicated that 1% HF and 0.6 M GLDA with an auxiliary agent could circumvent the expected problems associated with HF acidizing and modification, volume minimization, or elimination of preflushes. The use of the GLDA chelant facilitates, when using CT to deliver fluid to hot zones (which can be susceptible to formation damage if aggressive fluids based on HCl or formic acid are used, or if acetic acid is employed), could be jeopardized because of the difficulties inhibiting the corrosive effects of HF, HCl, formic, or acetic blends.
Making Clays Water Resistant: New Technology That Minimizes Formation Damage
Authors: Monroe Terry , Bhaduri Sumit , Koch Amber , Lant Kimberly
Published: May 2015

Formation damage and the resultant reduction in hydrocarbon production rates due to clay expansion are long-recognized problems (Ohen, 1991). The clay damage may occur during the drilling, completion and production phases of well operations. Often the remediation of clay damage is inadequate, providing only temporary improvements in hydrocarbon production. The prevention of clay expansion presents a challenge; fit-for-purpose chemistries exist, and are a function of clay identity and operational phase of the well.

Two broad subsets of clay damage mechanisms are chemical and mechanical considerations (Bennion, 2002). The focus of this study is to evaluate the minimization of clay hydration by coating clays to prevent chemical or reactive damage. An example of chemically induced formation damage would be clay swelling. On exposure to introduced aqueous fluids, other than interstitial water, sensitive clays will hydrate detrimentally. The end result can be subsequent hydrocarbon flow restrictions due to a decrease in pore space and detrimental formation softening allowing embedment of proppant. Chemical methods of ameliorating clay expandability potential fall into two broad categories: temporary and permanent stabilizers. The temporary clay control additives prevent clay swelling by increasing the ionic strength of treatment fluids, e.g., potassium chloride. Permanent clay stabilizers create a protective sheath around the clay.

The formation of a self-assembled monolayer (SAM), where the chemical covalently bonds to the siliceous formation surface, offers a more robust chemical coating on the clay surface. This coating acts as a chemical shield, which prevents subsequent wellbore fluids from interacting with the formation surface.

A new chemical treatment has been evaluated and, as discussed in this paper, the laboratory test results indicate the application of a hydrophobic coating offers substantial clay protection in water sensitive environments.
Systematic Engineering and Candidate Recognition Methodology for Stimulation in Depleted Fields leads to Multifold Increase in Production
Authors: Barasia A. , Pankaj P. , Venkateshwaran R.
Published: May 2015

Candidate recognition in mature brown fields and depleted fields for stimulation has always been a challenging task. It has become a common practice for many operators that when all else fails they turn to stimulating the well. The application of fracturing for any poor producer in a brown field does not guarantee success. Since traditional reservoir engineering methods like skin analysis via build-ups cannot be applied in these depleted reservoirs alternative techniques have to be used.

Identifying and stimulating key wells requires a systematic candidate recognition process with emphasis on the ability of the well to deliver post stimulation. Having a method to score completion and production integrity based on its petrophysical and geomechanical characteristics and thoroughly understanding the operating environment ensures a much better chance for these wells to be successful. Comprehensive candidate selection methodology with available data was devised to identify best stimulation candidates from existing set of wells. Comparative Petro-physical log evaluation, Mechanical Earth modelling and oriented perforations in selected wells was deployed to further understand reservoir and rock mechanical properties and limit surface pressures by minimizing near wellbore perforation and tortuosity effects.

Further to estimate economic viability; analytical modelling and Arps production decline was combined utilizing local learnings and experience to predict post fracture production. Full set of diagnostic tests was done to make a robust model that can simulate fracture propagation and help in optimizing fracturing design to place desired fracture in place. Post fracturing cleanup and well activation was closely monitored with design and recommendation on required Artificial Lift techniques as and when required. Production results achieved after applying this workflow exceeded initial expectations set by operator. Payout period achieved for total investment in this project was 75-150 days. Due to these encouraging results, same workflow was applied in number of depleted fields in Cambay basin with similar results.

This paper will summarize the workflow used for revitalizing production from some of the major fields including Candidate selection methodology, Petro-physical evaluation, Mechanical earth modelling, diagnostic tests for fracturing design, production forecasting, post fracture well activation and artificial lift design. In the end, possibilities of deploying this workflow for re-vitalizing other brownfields will be discussed.
The Implementation of State-of-the-Art Channel Fracturing Technique in High Permeability Layered Reservoirs in the Sinai Peninsula
Authors: Kortam Mostafa , Anwar M. , Mousa Doaa , Fouad Ahmed , Yosry Mohamed , Mathur Anil , Abbas Nelly Mohamed , Sahli Mohamed El
Published: May 2015

The Abu Rudies field in the Egyptian Sinai peninsula produces mainly from the South Gharib formation that is characterized as a complex, heterogeneous, thick and laminated, but permeable, slightly oil wet rock and depleted sandstones consisting of sands with an average permeability in the range of 150-550 mD and Young's Modulus in the order of 1.0 - 2.5 million psi. Conventional hydraulic fracturing and Frac & Pack techniques have been traditionally deployed to produce hydrocarbons and for sand control. The added complication is the reduction in the effective permeability to oil due to the rock being oil wet.

Conventional fracturing techniques have had limited success especially in the highly permeable compartments of the field due to premature screenouts that were encountered extensively, residual polymer in the intergranular porous rock and the flowback of formation sand and proppant.

This paper describes the application and production enhancement efforts for the first time with a novel channel-fracturing technique combined with rod-shaped proppant in selected production targets in the Abu Rudies field in Egypt. The channel fracturing technique introduces channels within the proppant pack that significantly increase conductivity and effective fracture half-length leading to increased productivity. Rod-shaped proppant when used as tail-in in fracturing treatments increases near- wellbore fracture conductivity and completely prevents proppant/formation sands flowback as demonstrated by zero flowback due to its particular geometry.

This paper describes actual case studies of fracturing a high-permeability layered reservoir using the channel fracturing technique, the problems encountered due to high leak off, low closure pressures, reservoir heterogeneity and the complexity due to adjacent water bearing layers. Finally, we demonstrate the well performance with the channel fracturing technique compared with alternate techniques.
A Case Study for Effective Perforation and Gravel Placement in a Complex Dual Casing Completion
Authors: Vigo Morounranti , Obanor Nelson , Munro Jock , Shumakov Yakov
Published: May 2015

Perforation performance can be greatly reduced when encountering multiple casings where depth of penetration and crucially reduced entrance holes prevent effective gravel placement. A practically proven case study is presented on the design, equipment selection and execution of a successful cased-hole gravel-pack campaign in dual casing completions of an injector well.

An integrated approach and workflow is implemented to enhance the gravel pack efficiency. It involves the combination of firstly, a high efficiency perforation system that optimizes tunnel geometry and penetration in a dual casing completion. Secondly, an innovative approach on the gravel pack installation using a viscous slurry to pump at slightly higher rates above the fracture gradient in order to create a small fracture around the wellbore. The success of the gravel pack installation is further assured by the application of an “alternate path” concept.

Packing the perforation channels is achieved by selecting a big-hole gun system that provided optimal performance through the multiple casings including highly phased large casing exit holes resulting in a large area-open-to-flow. The cased hole gravel pack completions is installed using a high rate gel pack technique creating short, highly conductive fractures enhancing connection of the reservoir to the wellbore. Furthermore, annular pack integrity is achieved using an alternate path design ensuring uniform gravel placement over the sizable reservoir interval. Injectivity into the formation is proven via constant tubular and annular pressure; indicating minimal permeability impairment to the formation. The production zone is flow tested using an electric submersible pump with trace of solids 0.01% WT received at surface confirming the integrity of the gravel pack completion.

With the increase of more complex reservoirs and completion techniques, practical application and solutions of such complexities add to the industry knowledge base. This paper shares a practical and proven integrated approach to providing solutions for installation of gravel pack in a dual-completions. This concept is based on many years of operational experience and lessons learned on the field.
A Non-Damaging Polymer Fluid System for Conventional and Unconventional Formations
Authors: Wang Xiaolan , Sun Hong , Zhou Jia , Guerin Michael , Li Leiming
Published: May 2015

Most conventional fracturing fluid systems are based on guar and guar derivatives. Therefore, fracturing costs are strongly influenced by guar price. In addition, when pumped in unconventional formations, these fluid systems can cause significant formation damage due to insoluble protein components in guar. While Polyacrylamide (PAM) based copolymers are often used in unconventional formation stimulation, they are often considered to be hard to break.

A possible solution that can mitigate the problems associated with the conventional fracturing fluid systems is a new fluid system based on a carefully designed synthetic polymer. The synthetic nature of the polymer translates into a stable operating cost without being impacted by market fluctuations like in the case of guar. This new synthetic polymer system is crosslinked and applied similarly to polysaccharide-based fluids. To alleviate concerns that synthetic polymer is hard to break, this polymer incorporates special linkages, periodically distributed along its backbone, to make it easily broken into small fragments with conventional oxidative breakers under downhole conditions to leave minimal formation or fracture damage. The polymer also incorporates functional groups that resist damage from water hardness. In addition, the polymer hydrates almost instantaneously and allows rapid viscosity generation and adjustment without a hydration unit, which greatly reduces footprint of hydraulic fracturing treatments.

While this new polymer system can be used in slickwater hydraulic fracturing and linear gel applications, laboratory testing also showed that it can be effectively crosslinked with conventional metal crosslinkers. This paper investigates the possibility of using this new polymer as a total package to be applied throughout hybrid fracturing operations for tight formations besides using it as fracturing fluids for conventional formations. Laboratory work also investigated other applications of the new polymer such as acid gelling, acid fracturing, and diversion, to name a few. This paper presents the laboratory performance and the underlying mechanisms of the novel polymer fluid system.
Wellsite Mineralogical Data Acquisition; Understanding Results from Multiple Analytical Sources
Authors: Davis Brian "BJ" , Koch Amber , Braun Gerald , O'Connor Cassie , Frost Elton , Quinn Terry , Ly Chi Vinh , Oliver Guy , Spence Graham , Whatley Bill , Cardy Neil , Wilson Michael
Published: May 2015

Technological advances in both equipment and computer software have enabled the implementation of new approaches in generation of mineralogical datasets at petroleum wellsites. These datasets are currently utilized by hydraulic fracturing engineers to assist in designing optimized fracture stage intervals in horizontal wellbores, rather than using evenly spaced intervals between treatment stages. Mineralogical data is generated by downhole wireline logging tools, and on drill cuttings, conventional wholecores, and rotary sidewall coreplugs utilizing a variety of analytical instrumentation techniques. This paper documents a study undertaken to assess mineralogical datasets generated on comparable samples, focused on evaluating analytical limitations and variances, toward obtaining consistent mineralogical results.

Instrumentation typically used to generate these datasets include x -ray diffraction (XRD), x-ray fluorescence (XRF), scanning electron microscopy-energy dispersive spectroscopy (SEM-EDS), fourier transform infrared spectroscopy (FTIR), and inductively coupled plasma techniques (ICP mass spectroscopy or ICP optical emission spectroscopy). Variables introduced into the analysis in addition to the different analytical techniques include sample types and sizes, sampling methods, sample preparation, drilling mud contaminants, lithological heterogeneity, and depth correlations between cuttings, cores, and wireline measurements.

As the study evolved it became clear that wellsite sampling and preparation protocols needed to be properly defined to assure sample quality and accurate sample depth reference. Analytical equipment limitations must be fully understood, as should differences in measurement technologies both in the laboratory and at the wellsite. Equipment destined for wellsite analysis was evaluated in a controlled laboratory environment using reference mineral standards and standard mixtures to understand testing limitations and refine mineral phase calculations. Mineral terminologies, classifications, compositions, and the resulting databases were reviewed for consistency. Multiple cuttings and core sample sets from conventional sandstones, carbonates, and current mudrock plays such as the Eagle Ford and Marcellus shales were sub-divided and analyzed to allow direct comparisons of generated datasets. Complementary testing was conducted to confirm data quality.

This study yielded increased confidence in wellsite and laboratory analyses, including caveats where necessary, procedural guidelines for each analytical technique, and verification of deliverables appropriate to unconventional mudstone reservoirs. Example datasets, graphical comparisons, and report formats are included. The resultant wellsite datasets, in tandem with additional wellsite analytics, enhance confidence in optimized fracture stage interval decisions.
The Effect of CO2 Gas Flooding on Three Phase Trapping Mechanisms for Enhanced Oil Recovery and CO2 Storage
Authors: Peksa A. E. , Wolf K.-H. A. , Daskaroli M. , Zitha P. L.
Published: May 2015

Release of CO2 as a by-product of industrial and domestic operations around the world is undesirable due to its negative impact on the environment climate. As an option for reduction many efforts are made to develop methods for the capture and storage of CO2. One potential option, the CO2 enhanced oil recovery (CO2-EOR) technique, is already in use for decades and widely accepted as a promising solution for mobilization and recovery of residual oil in water wet rock. It is also a mitigation prospect for CO2 reduction and an opportunity for permanent storage after the production stage. For better understanding of the mechanisms controlling the oil displacement and CO2 sequestration, the interaction between pore system, flow and phase equilibrium were conducted in a series of CO2 flooding experiments. As an improvement, we propose to inject CO2 as a 2nd stage EOR action after water flooding and accurately monitor and measure CO2 in the system.

The experimental part involves brine injection into vertical positioned cylindrical Bentheimer sandstone (BS) cores at residual oil saturation, which mimic depleted oil reservoirs. Next, CO2 is injected at the bottom side of the column to recover oil and to trap CO2. The trapped and residual saturations are measured by mass balance and visualized by a CT - scanner during the experiment to discriminate different phases through time. The oil recovery and trapped saturations of oil and gas are determined as functions of initial oil and gas saturation.

Different from previous experimental studies, a continuous CO2 injection technique was used for coupled CO2 sequestration and EOR. The experiments show for CO2 flooding experiments an increase in the back pressure between tests that result in higher CO2 storage and in higher oil recovery. The laboratory results are used for upgrading and building of a model for three phase flow in sandstone reservoir.

This paper gives a better understanding of three phase trapping mechanisms and shows results on gas phase behavior with various injection flow rates. In addition, we assess whether the flow and pressure schemes are feasible and we show prospective recoveries and storage efficiency. The experimental results help to improve up-scaling conditions for recovery at field scale.
Mechanical Properties and Natural Fractures in a Horn River Shale Core from Well Logs and Hardness Measurements
Authors: Yang Sheng , Harris Nicholas , Dong Tian , Wu Wei , Chen Zhangxin
Published: May 2015

This paper addresses factors that influence rock mechanical properties and the development of natural fractures of Horn River Group, a major shale gas play, using cores and well log data of well Maxhamish D-012-L/094-O-15. The majority of natural fractures in the Horn River shale are narrow fractures, sealed with carbonate mineral. In this study, the formation of observed fractures is primarily determined by the lithology type, mineral composition, bed thickness, the lithology of the surrounding bed and the rock mechanical properties. The different cement types in the fracture aperture also control the fracture reactivation by hydraulic fracturing.

Brittleness is one of the most important mechanical properties controlling fractures formation, because brittle shale is more easily fractured than ductile shale and fractures in brittle shale tend to perpetuate when the fracturing pressure is released. In this study, a hardness value measured by the Equotip Bambino 2 hardness tester is found to be a good proxy for the brittleness of shale layers. The hardness measured an Equotip Bambino 2 hardness tester and the brittleness calculated from well logs show a good correlation. An orthogonal regression method is applied to deeply investigate their relationship. For different members of the Horn River Group, the correlation relationship is different, which is mainly affected by the changes of the Si and Ca mineral content. As shown in this paper, the hardness measured by an Equotip Bambino 2 is a good indicator of the log-derived brittleness, because of its high resolution and more accuracy. A hardness value is also more sensitive to the mineral composition changing than a brittleness value. Based on a statistical analysis, the hardness more accurately predicts the distribution of natural fractures, so that when a hardness value is over 550, natural fractures will be developed. These relationships can also be used to predict natural fractures and the targets of hydraulic fracturing when dipole sonic and density well logs are not available.
Pore-Level Experimental Investigation of ASP Flooding to Recover Heavy Oil in Fractured Five-Spot Micromodels
Authors: Sedaghat M. , Mohammadzadeh O. , Kord S. , Chatzis I.
Published: May 2015

Although Alkaline-Surfactant-Polymer (ASP) flooding is proved to be efficient for heavy oil recovery, the displacement mechanisms/efficiency of this process should be discussed further in fractured porous media especially in typical waterflood geometrical configurations such as five-spot injection-production pattern. In this study, several ASP flooding tests were conducted in fractured glass-etched micromodels which were initially saturated with heavy oil. The ASP flooding tests were conducted at constant injection flow rates and different fracture geometrical characteristics were used. The ASP solutions constituted of five polymers, two surfactants and three alkaline types. The results showed that use of synthetic polymers, especially hydrolyzed polyacrylamide, with high molecular weight as well as cationic surfactant increases the ultimate oil recovery. In addition, location of the injection well with respect to the fracture system plays a significant role in the performance of the ASP flooding. For instance, an increase in the angle associated with the longitudinal extension of fractures with respect to the main flow direction resulted in enhanced oil recovery and also postponed the wetting phase breakthrough time. Mechanistic study of this displacement process revealed that dispersive and diffusive behavior of ASP front enhanced the fluid transport from fracture to matrix as well as increased the microscopic displacement efficiency, which both were more pronounced for the case of longer fractures. In addition, emulsification and coalescence mechanisms are responsible for ASP frontal advancement as well as flow of the ASP phase in the invaded portion of the models. Residual oil in the invaded region, which was observed in the form of discontinuous oil ganglia dispersed in the invaded pore bodies or in the form of pendular bridges formed around some of the solid particles, was mobilized in the form of oil wads through the droplets of the displacing phase. In this study, the mechanisms responsible for recovery of the in-situ oil by ASP flooding were mechanistically investigated along with quantitative parametric study on the effect of different fluid/porous media properties on ultimate recovery factor.
A Water Swelling Polymer for Fracture Shutoff to Improve Injection Profile During Secondary Recovery: Case Histories and Lessons Learned After More Than 600 Well Interventions
Authors: Vasquez Julio , Rodriguez Levi
Published: May 2015

Nonmatrix reservoir features, such as fractures, fissures, karsted zones, and/or eroded out permeability zones, can detrimentally affect injection profiles and sweep efficiency of secondary recovery techniques, such as waterflooding. Current available technologies, including conventional cement squeezes, foamed cement treatments, resins, or temperature-activated low- to medium-viscosity polymer gel systems etc. present limitations to plugging these undesired features because of their inability to withstand influxes of water in a fractured environment, which can cause dilution of the materials and prevent them from activating/curing. This paper presents the field implementation of a water swelling polymer (WSP) for fracture shutoff to help improve the injection profile to overcome such challenges. Case histories are discussed highlighting the diagnostic stage.

The WSP system is capable of absorbing up to 400 times its own weight in water. The rate of absorption can be controlled based on salinity of the carrier fluid. As the WSP enters the nonmatrix reservoir features, the systems begin absorbing water, expanding, and filling this “empty” space. Most of the WSP treatments are mixed on-the-fly and bullheaded into the wellbore as it will not invade the rock matrix because of particle size. Treatments are usually pumped in stages because the fracture, void, or fissure capacity is unknown. Ideally, placement of the WSP system should reflect an increase to pressure, which is an indication that the fracture system has received a sufficient treatment volume to fill the void space and subsequently achieve diversion of the injection fluid. The WSP particle size varies from 40 μm up to 4 mm. This system remains stable in H2S and CO2 environments.

This water swelling polymer presents an innovative technology for fracture, fissure, and highly eroded out permeability shutoff to help improve sweep efficiency of water, gas, and water alternating gas (WAG) injection. In addition, this conformance technology is also applicable to loss circulation problems while drilling and performing casing repairs. A variety of case histories are discussed in detail in this paper. To date, more than 600 treatments have been performed using this technology.
New Insights into the Critical Role of Geology in Modeling and Prediction of Low Salinity Waterflooding
Authors: Dang Cuong T.Q. , Nghiem Long , Nguyen Ngoc T.B. , Chen Zhangxin
Published: May 2015

Although the advantages of Low Salinity Waterflooding (LSW) have been widely reported, studies of LSW in the past two decades have mainly focused on the underlying mechanisms through core flooding experiments. For more successful and broader applications of LSW in the field scale, it is required to have a comprehensive understanding of the LSW performance with complex geological features on a large scale that has never been addressed in the past. This paper presents insights on field scale modeling and prediction of LSW to address the current challenges with: (1) an equation-of-state compositional simulator fully coupled to multiple ion exchanges, geochemical reactions, and wettability alteration; (2) incorporation of critical geological properties important in LSW; (3) effective closed-loop reservoir management for design and prediction of the LSW process; (4) LSW evaluation in a full field scale.

A mechanistic LSW model and a closed-loop modeling approach are introduced in this paper that can efficiently capture the critical effects of geology on the LSW process by integrating the use of geological software, a reservoir simulator and a robust optimizer. First, eighty geostatiscal realizations with different facies and lithology properties and distributions are generated to evaluate the effect of reservoir geology, in particular the critical effects of clay, on LSW. A wide range of recovery factors from 19% to 40% indicate that the effectiveness of LSW strongly depends on geological factors such as facies properties, clay distribution and clay proportion. In consistency with the laboratory and field-scale observations, wettability alteration has been identified as the dominant effect that contributes approximately 58% to 73% to the incremental oil recovery from these realizations. Detailed analyses of the key factors were addressed to allow the design of optimal injection strategies to maximize the oil recovery by LSW. LSW is then evaluated in a closed-loop reservoir management for a sandstone reservoir in both secondary and tertiary modes. It is found that secondary and tertiary LSW give about 6% and 4.1% incremental OOIP over high salinity waterflooding, respectively. The simulation results also indicate that the sooner the LSW process is started, the better the benefit is.
Petrofacies Determination in Unconventional Reservoirs Driven by a Simulation-to-Seismic Process
Authors: Ramsay Travis , Yarus Jeffrey
Published: May 2015

It is well-understood that hydraulic rock types categorize flow unit regimes in porous media such that modeling of these regimes according to hydraulic conductivity is possible in a reservoir simulator. This hydraulic characterization is necessary in reservoir simulation to spatially dictate multiphase flow behavior throughout the modeled reservoir. The spatial delineation of these multiphase data then relies on a singular relationship between petrophysical properties, which can be used to assign the multiphase properties to the simulation grid; the properties and requisite relationship of choice are between absolute permeability and porosity.

This paper illustrates that a simulation-to-seismic modeling approach can be used to reconcile large-scale flow disparities in the dynamic reservoir model, resultant of diminished spatial constraints during the creation of the static petrophysical model with seismic attribute array data. The results demonstrate that the assignment of multiphase hydraulic descriptions to petrofacies have considerable control on simulated rates and produced volumes. The examination of selected simulation scenarios leads to the conclusion that petrofacies, when derived considering petrophysical cutoffs and hydraulic rock types, provide an alternative to incorporating depositional facies constraints during the modeling of select shale reservoirs, wherein the understanding of a regionalized modeling constraint is limited. Additionally, it is shown that geologic facies are not flow units while they are considered regionalized variables. The uncertainty associated with unconstrained petrofacies is then recognized as broad; but, it is accepted that this modeled petrophysical system allows for the described petrofacies to be used as a proxy for hydraulic conductivity in the absence of a facies-based spatial constraint.

A novel approach is introduced in this work to construct petrofacies from log curves and core data to relate hydraulic rock types and petrophysical properties to the simulation grid using a methodology that honors the available seismic. The mathematical formulation used to describe petrofacies can be modest or elaborate; however, they differ from geologic facies, which can be described as regionalized variables. Unlike geologic facies, petrofacies do not adhere to interpretable geometries and thus might not be considered as regionalized variables or functionally modeled with deterministic or stochastic algorithms.
Successful Deployment of Unconventional Geomechanics to First Zipper Hydraulic Fracturing in Low-Permeability Turbidite Reservoir, Mexico
Authors: Murillo Guillermo Gutierrez , León Javier Mendez , Leem Junghun , Rojas Carolina Henriquez , Salguero Javier , Reyna Juan
Published: May 2015

Project “Hectarea Fracturada” by the Operating National Mexican Company was the first simultaneous stimulation of two parallel horizontal wells (i.e., zipper hydraulic fracturing) project in Latin America, implementing a reservoir-specific approach by integrating geological, geophysical, petrophysical, and geomechanical assessments. The project was executed in fields located in a basin in the north region of Mexico, which consists of alternating shales and thin bedded sandstones. The target sandstone formation at the location of two horizontal wells is deemed tighter (i.e., > 1 md) than the other area in the basin.

Initial production from the two horizontal wells after a total of 32 hydraulic fracture stages was 8, 320 BOPD. The initial production was greater than 15 times the average initial production from conventional single-frac wells in the area and was approximately 40 times greater than the initial production from the vertical offset well. The production from the two horizontal wells stabilized at 2, 517 and 1, 011 BOPD, respectively. A typical conventional well in this area produced 220 BOPD, while the offset well yielded 100 BOPD. The two horizontal wells had 240, 000 bbl of 90-days cumulative production, which exceeded 14 times the average cumulative production from the conventional wells in the fields. Application of the completion technology was considered successful and was extended to other not conventional and mature fields, with similar successes.
Assessment and Ranking of EOR Strategies for Giant Extra-Heavy Oil Fields
Authors: Coll R. , Escobar E. , Carrera M. León , Pérez S.
Published: May 2015

This paper presents an integral methodology to evaluate and rank Enhanced Oil Recovery (EOR) strategies for heavy oil fields, together with preliminary results for a real case study in the Orinoco Oil Belt (OOB) where thermal EOR processes are planned to be used in a very large scale.

The decisions around EOR deployment are diverse, including EOR process selection, wells placement, injection conditions and scheduling. Typical decision parameters are: incremental oil recovery, Net Present Value, injection cost and environmental impact. Full field incremental recovery and injection requirements are estimated from reservoir simulation using a sectoring approach and taking into consideration the project development plan. Injection cost is highly dependent on the EOR process to be applied, as well as on specific project constraints, such as location or resources and infrastructure availability. The decision workflow uses the previously estimated full field production and injection profiles to size the surface facilities for each particular comparison case, and estimate the respective associated costs. Incremental drilling and completion costs for the EOR operations are also considered within the methodology. Environmental impact is assessed by estimating CO2 and H2S emissions, as well as energy and fresh water demands. The automation of the workflow allows the fast but meaningful assessment of hundreds of alternative strategies, including variations on EOR process conditions, surface facility configurations, deployment schedules and geological or commercial scenarios.

This workflow has been applied to a field in the OOB to support the decisions about EOR deployment strategy to be taken during the project conceptualization phase. The main objective was to identify the EOR process that could provide the best incremental recovery without infringing any project constraint, primarily target production plateau and fuel and fresh water availability, and, at the same time, minimizing cost and environmental impact. Being an extra-heavy oil field, thermal EOR processes were considered, more particularly: Cyclic Steam Stimulation (CSS), Steam Flooding (SF), Steam-Assisted Gravity Drainage (SAGD) and Horizontal Alternating Steam Drive (HASD). About one thousand cases were evaluated under uncertainty using information from different domains: geology, reservoir, wells, facilities, HSE and commercial. The comparison results provided very useful insights on the advantages, risks and drawbacks of each EOR strategy, and set the basis for a high quality decision.
PaHigh Resolution Image Log and Leached Porosity Analysis in Complex Carbonate Reservoirs
Authors: Zeghlache Mohamed Larbi , Akbar Mahmood
Published: May 2015

This article addresses the geological characterization of carbonate reservoir in the Middle East, using the high definition imager tool combined with other logs. In the logged wells, two main categories of open fractures were observed; 1) thin-layer-bound and 2) thick-layer bound fractures. The first category of fractures has limited vertical and lateral extents, hence may be considered as permeability enhancing at local and smaller scale. On the other hand, the second type of fractures may have larger vertical and lateral extents, hence may have larger influence on fluid movement at the reservoir scale. A conceptual fracture model was developed around one particular well path to understand their distribution and relationship with the formation layering.

In addition to fractures, the heterogeneities of these carbonates were examined through the use of newly introduced techniques. Through this analysis the total porosity measured by the petrophysical logs was dissected into leached porosity (connected and isolated ones), fractured porosity and matrix porosity.