bluuebunny/crossref_metadata_2025 huggingface dataset:
Effective Matrix Stimulation of High-Temperature Carbonate Formations in South Sumatra Through the Combination of Emulsified and Viscoelastic Self- Diverting Acids
Authors: Madyanova M. , Hezmela R. , Artola P. , Guimaraes C. R. , Iriyanto B.
Published: June 2014

The biggest challenges for successful matrix acidizing treatments on carbonate formations are the creation of an effective network of wormholes and obtaining uniform coverage. Typical matrix treatments often require low injection rates, and therefore hydrochloric acid cannot be used alone because rapid acid spending severely limits the acid penetrationat elevated temperatures. This high reaction rate causes face dissolution, fails to create a wormhole network long enough to effectively bypass the damaged zone around the wellbore that leads to the creation of dominating wormhole.

The Sungai Kenawang (SKN) onshore gas-condensate field, located at the southwest part of the Jambi Merang block in the South Sumatera Province, is a carbonate buildup, which is part of an isolated bank containing a group of buildups. The Baturaja formation, located at depths around 7,000 ft, is a thick gas condensate reservoir with permeabilities in the range of 10 to 350 mD, bottomhole temperatures range of 280 °F and 350 °F and the presence of H2S. The standard method used to stimulate these carbonates was pumping 15% gelled hydrochloric acid through coiled tubing. Production logs and pressure build-up analysis have shown positive skin values post stimulation and that the production was mainly coming from the upper zones, with minimal contribution from the lower zones.

This paper describes the application of a high temperature, highly retarded emulsified acid system that slows the reaction times by a factor of 5 to 15 compared to conventional HCl systems. The emulsified acid system combined with a selfdiverting viscoelastic surfactant based acid was able to achieve complete stimulation of a 197 ft long perforated interval without the need of coiled tubing. A pressure buid-up test showed a post-stimulation skin value of – 3.3 and the production log analysis demonstrated complete and uniform zonal coverage with the upper zones contributing with 53% of the total well production and the lower zone with 47%.
Mitigation of Calcium Sulfate Scale Formation When Seawater Is Used To Prepare HCl-Based Acids
Authors: He J. , Mohamed I. M. , Nasr-El-Din H. A.
Published: June 2014

The damaging effect of calcium sulfate precipitation on the permeability of carbonate cores when mixing hydrochloric acid with seawater for matrix acid treatments has been identified in our recent work (SPE 143855). The objective of this work is to mitigate calcium sulfate precipitation by using a suitable scale inhibitor in hydrochloric acid. Another objective is to determine the scale inhibitor type, concentration, and whether it is needed in the preflush or post-flush stages.

Core flood tests were conducted using Austin Chalk cores(1.5 in. × 6 in.) with a permeability of 5 md, to investigate the effectiveness of scale inhibitor. A synthetic seawater was prepared according to the composition of seawater in the Arabian Gulf. Calcium, sulfate ions, and scale inhibitor concentrations were analyzed in the core effluent samples. The minimum concentration of scale inhibitor was determined over a wide range of temperatures (77 to 210°F).

A scale inhibitor (sulfonated terpolymer) was found to be compatible with hydrochloric acid systems, and can tolerate high concentrations of calcium (30,000 mg/l). Analysis of the core effluent indicated that the new treatment successfully eliminated calcium sulfate scale deposition. The concentration of scale inhibitor ranged from 20 to 250 ppm, depending on the scaling tendencies of calcium sulfate. This work confirms that an appropriate scale inhibitor can be added to acid, to avoid calcium sulfate precipitation when seawater is used to prepare hydrochloric acid for matrix acidizing.
Observation of Gel Filter Cake Recovery by Dissolution in Flowback Fluids
Authors: Gdanski R. D. , Bryant J. E.
Published: June 2014

Wells completed in tight-gas sands often produce below expectations after fracture stimulation, with gel filtercake damage cited as a major cause of poor performance. These filtercakes have historically been viewed as immobile and insoluble in flowback water. However, recent field observations demonstrated conclusively that borate-crosslinked filtercakes delink and redissolve in flowback water. A fracture cleanup and chemistry simulator (FCCS) was used to discover and develop an appropriate rate law for the dissolution of gel filtercakes in flowback water. The simulator was validated by matching the observed gel contentin the flowback waters from a fracturing treatment.

Previous work demonstrated that behavior of gel filtercakes in proppant packs from fracturing treatments was more complex than expected. Particularly interesting were recent observations of significant concentrations of gelling agent across several hundred barrels of flowback fluid from a fracturing treatment with good documentation. Ionic composition of the well returns was first matched with the FCCS. Matching of the gel recovery profile required discovery and development of a rate law for dissolution of gel filtercake by water inflowing from the fracture face. Potential rate laws using flow of water down the length of the fracture were not able to match the observed profile. Parametric studies were then conducted and showed a gel displacement regime and a dissolution regime for gel recovery, with the controlling regime dependent on gel phase saturation in the proppant pack. The gel phase saturation in the proppant pack should be 50% or less to be in the dissolution regime for efficient gel recovery.
Converting Static Friction to Kinetic Friction to Drill Further and Faster in Directional Holes
Authors: Skyles Lane P. , Amiraslani Yosef A. , Wilhoit James E.
Published: June 2014

Since the dawn of directional drilling with downhole mud-motors, Operators and Directional Drillers (DD’s) have been continuously frustrated by the difficulties encountered during "sliding" operations. The challenge has always been how to overcome static friction between the drill pipe and the hole wall while the pipe is not rotating. Overcoming this static friction becomes more and more difficult as the DD leaves 0° inclination and works toward 90°. Some of the challenges to overcome are weight stacking, sinusoidal and helical buckling of the drill pipe, stick slipping, inability to hold tool face, slow ROP, etc. The good news is that static friction while sliding can now be greatly reduced by effectively converting it to kinetic friction; kinetic friction being much less inhibitive to drilling operations.

The following paper introduces a drilling tool that breaks static friction while sliding. This tool has repeatedly shown to break this friction without detriment to other downhole drilling tools or operations. Drilling with kinetic friction instead of static friction saves time, money and frustration. The Introduction of the following paper demonstrates the stated problem by showing the basics of friction resistance in the drill string while directionally drilling. The paper then describes this downhole tool and how it cures symptoms that frustrate the DD. The final section will present a Case Study conducted in a Barnett Shale horizontal drilling application in Tarrant County, Texas. It will strive to graphically illustrate and emphasize the effect of the tool on drilling operations.
An Improved Dynamic Well Control Response to a Gas Influx in Managed Pressure Drilling Operations
Authors: Bacon William , Tong Albert , Gabaldon Oscar , Sugden Catherine , Suryanarayana P. V.
Published: June 2014

Managed Pressure Drilling (MPD) offers the capability to control an influx dynamically, without conventionally shutting-in. Some current methods use applied-back-pressure (ABP) to force flow exiting the annulus to equal flow entering the drill-pipe, which is interpreted as influx cessation. However, solely ensuring flow continuity does not imply influx cessation, unless the annular fluids are incompressible. In this work, the impact of compressibility on dynamic well control is investigated. The transient response of compressible, multiphase flow in the annulus is examined using mass conservation over a control volume.

Limitations of Qout = Qin indicating influx cessation are explored, and an improved ABP dynamic well control technique is proposed. The new technique is applicable in MPD operations where conditions warrant dynamic well control rather than conventionally shutting-in.

It is shown that with some current methods, influx may not cease once flow out is constrained to equal flow in. It is also shown that in some situations, influx ceases before flow continuity is achieved, resulting in excessive bottomhole pressure. These outcomes are consequences of in-situ gas compressibility, making it invalid to solely rely on Qout = Qin to indicate influx cessation. The proposed technique is shown to offer accurate determination of influx cessation, even when compressibility is significant. New pressure and pressure derivative based parameters that carry the signature of influx cessation are defined. It is shown that consideration of these parameters appreciably increases the likelihood of successful well control. Several examples are shown to illustrate the new approach with the use of the new signature parameters.

Numerous transient, multiphase flow simulations have supported the key analytical conclusions from this work.

The results of this work are expected to improve the reliability of dynamic well control using ABP during Managed Pressure Drilling operations. Further, the new signature parameters are easy to monitor and interpret, and together with flow rate provide valuable additional information to assist dynamic well control.
Hydrodynamic Loads, Soil and Structure Interaction in Conductor Design for Offshore Platforms and Jack-Up Rigs
Authors: Pilisi Nicolas , Lewis David
Published: June 2014

The design of a conductor casing is significantly different than that of the other tubulars in a well. Conductors are drag-dominated structures that enable conducting drilling operations from offshore fixed platforms or jack-up rigs through the seawater column. To date, the majority of technical papers concerning conductor design have focused on a particular aspect of the conductor pipe but very few of them have detailed the design of conductors in response to the combination of hydrodynamic loads, external and internal loads acting on this casing string as well as the soil-conductor interaction.

This paper discusses the design of both platform conductors and jack-up supported conductors used in open water by first providing the essential steps (i.e. deriving and presenting equations) that need to be followed to ensure the structural integrity of the conductor casing along its entire length. Then, in order to illustrate the methodology, four case studies were performed to investigate the performance of well conductors at different shallow water locations (the Gulf of Mexico, South America, the North Sea and South-east Asia).

For all analyses, the conductor pipe has been checked for three failure modes: strength, stability and fatigue and finite element analyses have been computed to solve the hydrodynamic loading, the statically indeterminate problem and the complex soil-structure interaction. The results show that, in general, stability controls the conductor design which means that the conductor will buckle before it yields; and therefore, there is a requirement to apply tension at the Texas Deck for a jack-up. Also, in some instances (i.e. rougher water environments) or with smaller size conductors (13.375-in. and 20-in.), the fatigue analysis may become the most important failure mode for both the conductor pipe body and the connectors.
Special Considerations in the Design Optimization of High Rate, Multistage Fractured Shale Wells
Authors: Sugden Catherine , Johnson John , Chambers Mike , Ring Gary , Suryanarayana P. V.
Published: June 2014

Typical shale well completions involve massive, multistage fracturing in horizontal wells. Aggressive trajectories (with up to 20°/100 ft dog legs), multistage high rate fracturing (up to 20 stages, 100 bpm), and increasing temperature and pressure of shale reservoirs result in large thermal and bending stresses which are critical in the design of production casing. In addition, where cement voids are present and the production casing is not restrained during fracturing, thermal effects can result in magnified load conditions. The resulting loads can be well in excess of those deemed allowable by regular casing design techniques. These loads are often ignored in standard well design, exposing casing to the risk of failure during multi-stage fracturing.

In this work, the major factors influencing normal and special loads on production casing in shale wells are discussed. A method for design and optimization of shale well production casing design is then introduced. The constraints on the applicability of different design options are discussed. Load magnification effects of cement voids are described and a method for their evaluation is developed. It is shown that thermal effects during cooling create both bending stress magnification and annular pressure reduction due to fluid contraction in trapped cement voids. This can result in significant loads and new modes of failure that need to be considered in design. The performance of connections under these loads are also discussed. Examples are provided to illustrate the key concepts described. Finally, acceptable design options for shale well production casing are presented.

The results presented here are expected to improve the reliability of shale well designs. They provide operators with insight into load effects that need to be considered in design of production casing for such wells, and with options for adequate design.
Inhibited Gas Stimulation To Mitigate Condensate Banking and Maximize Recovery in Cupiagua Field
Authors: Franco C. , Zabala R. , Zapata J. , Mora E. , Botero O. , Candela C. , Castillo A.
Published: June 2014

Condensate banking has been identified as one of the most potential damaging mechanism affecting the well productivity in Cupiagua Field. This gas-condensate giant field has reached an average recovery factor of 42% with recovery values of ~60% in some layers of field. The mitigation of condensate banking phenomena, among the other important damaging mechanism currently interacting along the entire productivity zones, has been one of the most relevant stimulation practice in the development strategy.

The mitigation of condensate banking led to optimize common stimulation practices to recover the productivity of gascondensate wells, massive hydraulic fracturing and matrix stimulation with inhibited diesel and alcohol have been the most common practices implemented and optimized to mitigate condensate banking in Cupiagua field.

Since the field is being operated by ECOPETROL (Jun-2010), the mitigation of condensate banking was recognized as one of the most important stimulation challenges to be worked by stimulation team. The effective mitigation of condensate banking is a key to reach and even exceed the production targets set by ECOPETROL short and long term.

This paper describes all the engineering work carried out to implement a new stimulation technique based on the injection of inhibited dry gas. The performed lab job, the simulation runs, the engineering design and the field results are clearly described in the paper, the preliminary results are showing that now we have available a successful stimulation technique to remove and mitigate condensate banking. At the moment this stimulation strategy has been focused in to remove liquid saturation (condensate and water) and organic solids (especially asphaltenes) by incorporating alcohol and surfactants inside the gas stream. Future engineering job will be addressed to find a chemical blend that can improve the gas-treatment life, probably reducing critical liquid saturation or/and reducing the size of no mobile condensate rings.
Experiment and Simulation Study of Proppant Pack Compression
Authors: Ye X. , Tonmukayakul N. , Weaver J. D. , Morris J. F.
Published: June 2014

Realistic laboratory simulation of fractures propped with sand, engineered ceramic proppants, and resin-coated proppants to determine the impact of temperature, stress, and stress cycling on proppant-pack structure and pack permeability is both difficult and expensive. Large, specialized testing equipment and long testing times are required, which can lead to high testing costs. This paper presents a new dynamic compression device (DCD) that permits rapid proppant-pack analysis to optimize proppant selection.

Understanding the mechanical and fluid dynamics of hard granular particle packs subjected to high closure stress and cyclic stress is important for understanding fracture conductivity and the impact of production operations. Few experimental studies have been reported where the compression of proppant with variable stress rates was used that also includes simultaneous direct visualization of the proppant structure.

The DCD imposes a controlled strain on the proppant pack while measuring the stress response, up to a compressive loading of 7,100 psi. Simultaneously, the liquid permeability and a detailed visualization of the proppant-pack structure are acquired. The stress loading and unloading process, performed in either a single or repeated (cycling) protocol, can be performed with precise measurement of the resulting system-level strain. Permeability results obtained using the DCD were comparable to those obtained using standard API linear conductivity determinations. Particle rearrangement by direct visualization during stress cycling was comparable to that predicted by use of a popular, commercial, three-dimensional particle-flow numeric simulator.

The DCD is a small, bench-top device that uses a small proppant sample. It has been demonstrated to be an efficient tool to experimentally determine the impact of closure stress, stress-change rate, proppant-packing properties, and the effect of multiple stress cycles on liquid permeability, while providing direct proppant-pack structure visualization. This new device enables rapid testing to determine the impact of expected downhole production conditions on proppant-pack permeability and permit selection of optimum proppant and proppant coatings.
Dynamic Filtration: Seepage Losses on Tyrihans
Authors: Van Der Zwaag C. H. , Omland T. H. , Vandbakk T.
Published: June 2014

Drilling of the Tyrihans reservoir sections was affected by significant seepage losses. These added up to ~1000 m3 after drilling five wells with 13 reservoir sections, including pilots and laterals, and a total exposed reservoir length of ~15000 m.

In this study, we estimate whether the reported losses can be explained by dynamic filtration mechanisms and related seepage losses. Daily drilling reports were evaluated to reconstruct the downhole drilling environment. Accumulated dynamic and static filter loss periods were calculated. A dynamic filtration HPHT filter press was used to measure dynamic filter losses of laboratory and field samples of the drilling fluid used on Tyrihans. Measurement results were evaluated and extrapolated to field scale. Finally, losses experienced in the field and calculated values were compared.

Results strongly indicate that the reported losses on Tyrihans were dynamic seepage losses and that these losses dominate the total loss volumes clearly. The filtration volumes measured in the laboratory were significantly influenced by the shear rate applied. High shear rates caused a larger dynamic filtration component. There are indications that a reduction of coarse bridging particles during drilling and an increase of finer particles relative to the optimum particle size distribution increases the dynamic filtration component.

Dynamic fluid losses may in magnitude be misinterpreted as lost circulation into microfractures or in developing fracture systems. A correct assessment of the nature of the losses is essential to select an efficient treatment. Elevated downhole and circulation temperatures as well as long reservoir sections creating large filtration areas cause increased dynamic seepage losses. To reduce these losses higher viscosity base oil could be considered in OBM or a less turbulent flow regime should be engineered. The latter can be achieved for example by increasing drilling fluid viscosity, reducing pump rates or choosing a smaller drill pipe diameter. Efforts should be put into maintaining the optimum particle size distribution of filtercake-building bridging particles. Such changes in fluid design should be carefully evaluated, as they can have a negative impact on other fluid parameters such as equivalent circulation density, swab and surge or reduced hole cleaning efficiency. Research should be initiated to develop low-dynamic-loss fluids. This requires a better understanding of dynamic loss mechanisms and the identification and verification of additives that protect filtercakes against shear and erosion.
Fracturing Fluid With Low-Polymer Loading Using a New Set of Boron Crosslinkers: Laboratory and Field Studies
Authors: Williams N. J. , Kelly P. A. , Berard K. G. , Dore’ E. L. , Emery N. L. , Williams C. F. , Mukhopadhyay S.
Published: June 2014

Guar-based crosslinked fluids are most commonly used in hydraulic fracturing to stimulate oil and gas wells. When crosslinked with boron, the fluid not only provides high viscosity, it is also able to recover its rheological properties after being subjected to a mechanical shear. Altough borate crosslinked guar systems are environmentally favorable, the gelled fluids generate a significant amount of insoluble residues upon breaking down with oxidizers or enzymes, commonly known as breakers. The amount of residues formed in the broken fluid is directly related to the type and the quantity of the polymer used. Studies have shown that these residues can cause significant damage to the formation and to the proppant pack conductivity. So it is highly sought-after to formulate an efficient boron-crosslinked fluid system with lower polymer loading without compromising its rheological properties and proppant carrying ability. In addition, the recent global shortage of the guar beans specifically required for the oil & gas industry has driven our efforts further toward this goal.

Studies have shown that crosslinking efficiency is dependent on the availability of the crosslinking sites and the chemical and structural properties of the crosslinkers. Considering these factors two different approaches were taken in order to reduce the polymer loadings of the fracturing fluid: 1) Use of a high yielding, fast hydrating, non-derivatized guar system with appreciably less insoluble materials and 2) Use of a new set of chemically modified boron crosslinkers with higher crosslinking efficiency. This paper will describe the laboratory testing involved in developing this new generation of low-cost, low-polymer, and environmentally responsible fracturing fluids. The fluid is operable in a broad range of temperature and compatible with breakers and additives commonly used in the industry. This system has the capacity to withstand high salinity and high shear rates, and is capable of rapid re-heal, which decreases shear degradation as the fluid is pumped through gravel pack tools. The paper will also discuss our recent fluid testing in preparation for pumping in the Gulf of Mexico.
Pushing the Limits: HT Carbonate Acidizing
Authors: Jimenez Bueno O. E. , Ramirez G. R. , Quevedo Z. M. A. , Resendiz Torres J. T. , Tellez Cisneros F.
Published: June 2014

The Mexico South Region produces more than 520, 000 bopdl from mature carbonate reservoirs. These reservoirs have widely varying reservoir pressures, presence of natural fractures and temperatures up to 350 degF. The extremely high temperatures makes even more challenging the stimulation process with conventional systems resulting in excessive corrosion and very inefficient wormholing.

An innovative solution, considering a chelating agent as treating fluid, has proved to be an effective approach to stimulate these reservoirs. The post treatment production in two different wells showed outstanding results with higher rates than previous treatments and the trend of the production declination was smoothed. This new stimulation solution aided with a good candidate selection has led it to be the preferred solution for HT wells.

Well A was treated with 15.0 m3 of the fluid based on chelating agents as main system, with a solvent preflush and overflush. Previous to this job two stimulation treatments were performed pumping a mixture of conventional acid systems. In both occasions the production increased, however, the production declined to pre-treatment rates in a matter of days. When treated with the new solution the production increased 254 bpd with almost no decrease with time (monitored for three months), indicating a more efficient stimulation treatment, and greatly improved on the economical indicators.

Well B was stimulated with 20.0 m3 of chelating agent fluid after three previous attempts using conventional systems. The production increased 726 bpd. Post-treatment behavior was the same as well A.

Wells A and B showed an increased production of 1.7 KBD with a very limited production declination because of more efficient wormhole creation due to retarded reaction rates allowing a wide contact with the reservoir thus improving production performance, Np and eliminating post-treatment neutralization and testing surface equipment requirements.
A Sequential Polymer Injection Treatment Using RPM: Effects of Multilayer Adsorption of Cationic and Anionic Polymers
Authors: Chung Taemoon , Bae Wisup , Koh Hyunjin , Oh Sangmin , Kim Seungtae , Nguyen Huy X.
Published: June 2014

Relative permeability modifiers (RPMs) have proven to be an effective technology to control water production without significantly damaging hydrocarbon-production potential. Systems most commonly used for this purpose are single solutions of water soluble, high molecular weight polymers that adsorb onto the pore surface and change the flow properties of the porous media. However, these adsorbed polymers are only developed thin single film layer on the pore surfaces, resulting in a moderate success to maximize the water controlling efficiency. Moreover, high molecular weight injecting polymers can cause inaccessible pore volumes (IPVs), resulting in the failure of controlling water production for a long period of time. Because blocking polymer chains in front of IPVs can easily be penetrated due to strong water resistance after the treatment.

To overcome this unsuccessful scenario, this paper presents the laboratory development of a novel polymer injection system, which is a sequential injection of polymers considering ionic characteristic as well as controlling molecular weight, injection volume and concentration.

When cationic and anionic polymers are injected sequentially into a sandstone formation, a first injected cationic polymer induces preferential adsorption onto the negatively charged sandstone pore surfaces. Thereafter, anionic and cationic polymers are injected stepwise. These injecting polymers will be adsorbed and stacked making multiple adsorbed layers by electrostatic interactions, which results in a higher level of hindrance to water flow while still maintaining the minimal effect on hydrocarbon flow. Furthermore, increasing molecular weight and concentration of polymers can be injected sequentially to reduce IPVs. Injection volume can be designed to decrease to simulate maximum water controlling efficiency near wellbore regions.

Experimental results from Berea cores showed that there are improvements in Frrw values (up to 9.29) and Frrw/Frro ratios (up to 3.34) in a sequential injection process compared to conventional single injection processes. Frrw/Frro ratios showed an improving tendency with pore volume injected until the ends of experiments. The obtained results clearly indicate the effectiveness of sequential injection method in verifying improved RPM performance.
Investigation of the Mitigation of Lost Circulation in Oil-Based Drilling Fluids Using Additives
Authors: Guo H. , Voncken J. , Opstal T. , Dams R. , Zitha P. L.
Published: June 2014

Fluid loss control is an essential property of oil based mud (OBM) which can impact the success of drilling operations. The paper presents an investigation of the mitigation of lost circulation in OBM using leak-off control additive. A simple physical model was developed to describe the static filtration process considering the formation and properties of the filter cake. Both HTHP API press and core flow filtration experiments were performed to evaluate the leak-off behavior of OBM. Core filtration experiments were carried with the aid of a CT scanner to monitor the invasion of the filtrate into the sandstone core at time intervals. In the long time limit the model predicts that the fluid loss follows the classical Carter equation, i.e. the leak of volume increases as the square root of time for the static filtration through a filter paper and through the sandstone core. Dual mode filtration diminishes the rate of fluid loss. The model provides also a relation between pressure drop and filtrate rate, which can be used to estimate the permeability of filter cake in the experiment. The leak-off behavior with additive observed in the experiment is well explained by the microstructure of rapid built-up filter cake which is mainly responsible for the control of fluid loss. The role of different components of OBM, e.g. solid particles, emulsion droplets and additives is discussed in the light of our observations.
An Automated Software Workflow To Optimize Gulf of Mexico Lower Tertiary Wilcox Sand Reservoirs
Authors: Dusterhoft R. , Strobel M. , Szatny M.
Published: June 2014

Much has been written about the deepwater Lower Tertiary Wilcox trend in the Gulf of Mexico, which spans hundreds of miles from Alaminos Canyon to Keathley Canyon to Walker Ridge (as well as adjacent areas). The estimated ultimate recoverable oil from these reservoirs is significant: 3 to 15 billion barrels. However, significant technical and reservoir challenges remain because of the water depth (typically greater than 5,000 ft), reservoir depth (typically greater than 20,000 to 30,000 ft below the mud line (BML)), and high pressures (greater than 20,000 psi bottomhole pressure (BHP)). Combining these issues with the thick, low permeability reservoir intervals (more than 1,000 ft thick in the tens of mD) requires new tools as well as new planning and optimization methods.

These new planning tools require system-wide (holistic) integration across multiple domains and completion software applications to produce a truly optimized completion. This type of integration is provided by an automated software workflow. Previous papers have provided details about the benefits derived from the automation of operations, engineering, and production workflows in general. Lower Tertiary Wilcox reservoirs were deemed good candidates by a major service company to implement the automated workflow concept, given the reservoirs’ low productivity index (PI), high-cost wells, high pressure/high temperature (HPHT) technical challenges, and production uncertainty.

This specific workflow seeks to optimize hydraulic fracture design within Lower Tertiary Wilcox reservoirs by stipulating the maximum net present value (NPV) that satisfies all well, completion, and reservoir constraints. Hydraulic fracture design is an example of what is largely a manual process that requires interaction with several software applications to obtain fracture geometry, production constraints, production sensitivity criteria, and NPV scenarios. When the goal is an optimized fracture design, the process is especially arduous because it requires iterative interactions with reservoir simulators, nodal programs, economics models, well tubular design systems, and stimulation design tools to arrive at a suitable design. Enabling coupled simulations technology, this fracture workflow provides a unique holistic combination of tools, which are linked to reflect the actual economic values.
Solving Deep 22" Carbonate Drilling Challenges in Northern Kuwait
Authors: Al Saleh Ali , Shehab Adnan , Al Khaldy Meshal , Portwood Gary , Ghoneim Osama , Maliekkal Harish
Published: June 2014

The operator must drill a deep, vertical 22" hole-section in a HP/HT environment to efficiently tap Jurassic reserves in the North Kuwait gas fields. The borehole starts at approximately 6050ft and continues to 9350ft. Interbedded lithologies encountered include carbonates, sandstones and shales with compressive strength between 6000-25,000psi. The section can take 350hrs to reach total depth (TD).

Historically, the section has been drilled with PDC and rollercone TCI bits. TCI had unacceptable ROP with short life requiring multiple runs. Frictional heat in Mutriba was causing inserts to crack/chip leading to total failure. The abrasive Burgan and Zubair with pyrite were causing extensive insert wear. PDC bits could deliver acceptable ROP, but inconsistent run lengths and vibration induced impact damage were driving up field development costs. Neither bit type could consistently complete the hole section in one run.

To solve problem a forensic investigation of TCI bearing, carbide materials and insert shapes was conducted. The study resulted in new impact resistant carbide grades and unique insert geometries specifically tailored for Middle East carbonate/sandstone drilling. A dynamic twin-sealing system ensures long bearing life. The design was tailored to maximize ROP while retaining a high level of cutting structure durability. The bit was run on RA-414 with outstanding results setting a new Kuwaiti 22" record drilling 3311ft in 335 hours (9.8ft/hr) reaching deep into abrasive Zubair sandstone. It is the most footage drilled by any bit type in the application and the first TCI to penetrate Zubair. It was dull graded 3-5 with all three seals effective in spite of turning two million revolutions. It eliminated multiple bits/trips to complete the hole section reducing rig-time expenditures, bit spend and the expense of a motor required for PDC. With additional modifications, it’s probable the bit will drill the section in one run in the near future.
Used Approaches for Carbonates Acidizing Offshore Brazil
Authors: Pereira A. Z. , da Silva M. G. , da Paixao L. C. , de Oliveira T. J. , Fernandes P. D.
Published: June 2014

Although the new Brazilian carbonate reservoir discoveries represent a huge undertaking, on acidizing terms, many of the challenges faced nowadays are very similar to those found in the old carbonate reservoir fields. Problems like high permeability contrast, heterogeneous porosity distribution and long production intervals have their complexity increased by the completion and production needs. Despite all these problems, the use of conventional approaches, applying basic techniques, has produced good results leaving some time to the development of more specific solutions, once there are still some limitations to overcome. Among those conventional techniques, pilot zones associated with chemical diversion have been intensively used although mechanical diversion has been limited by the completion arrangement.

This paper describes acidizing techniques that have been applied on Brazilian offshore carbonate fields, some observed problems and present some trends related to the development of new acidizing techniques.
Umbilical Deployed Stimulations for Asphaltene Related Damage in Offshore Oil Fields
Authors: Peruzzi T. , Coulon T. , Fauria J. , Frey D. , Marechal H. , Sloan R.
Published: June 2014

In the Deepwater Gulf of Mexico, twelve stimulation jobs were pumped down chemical injection umbilical tubing to remediate suspected asphaltene related productivity decreases. All twelve jobs were done on dry tree wells but the procedures could be adapted for wet tree application.
Stressed Rock Penetration Depth Correlation
Authors: Harvey J. , Grove B. , Zhan L.
Published: June 2014

Downhole shaped charge depth of penetration (DoP) prediction has historically been largely determined by API Section I unstressed concrete performance. As previously reported [1, 2], reliance on unstressed concrete performance is flawed for several reasons and a review of industry models motivated a new approach based on stressed rock experiments.

As a result of a multi-year extensive experimental program, shaped charge DoP into stressed rocks is found to decrease exponentially with an empirically determined formation parameter; the ballistic indicator function, FBI. This parameter which combines formation intrinsic properties (UCS, porosity) and extrinsic properties (overburden stress and pore pressure) is described as well as its integration into an improved downhole shaped charge prediction model.

The development of the ballistic indicator function required approximately 600 single-shot experiments spanning 4 shaped charges, 10 different rocks (sandstones and carbonates), overburden stresses from 1 ksi to 20 ksi, and pore pressures from zero to 10 ksi. A recommended test program is presented which currently requires as few as 12 single-shot experiments for each charge to determine two charge-dependent parameters: the reference DoP, DoPref, and the exponential coefficient, α0. These two coefficients are sufficient for FBI<25 ksi which represents the majority of reservoirs currently being perforated world-wide. For reservoirs in excess of 25 ksi, DoP approaches a non-zero limit which is charge-dependent, and a preliminary discussion of this limit is included.

This model was initially developed based on sandstone targets. A preliminary extension of this model to carbonate targets is also presented. In general, carbonates behave differently than sandstones with less stress dependence and shallower penetration depths.
A CT Scan Aided Core-flood Study of the Leak-off Process in Oil-based Drilling Fluids
Authors: van Overveldt Andrea S. , Guo Hua , de Blok Gerard , Bedrikovetsky Pavel , Zitha Pacelli L.
Published: June 2014

The leak-off of oil-based mud (OBM) into sandstone cores was studied both theoretically and experimentally. Simple models were used to describe the build-up of the external filter cake and the internal filtration of small particles. Then systematic static leak-off experiments were done using an innovative method where CT scans taken at time intervals were used to visualize and accurately quantify infiltration of fluids into sandstone cores. This method allowed the monitoring of the leak-off process in a way that could not be done by the traditional API filter paper press test. The composition of oil based drilling fluids was varied, to investigate the influence of various particles on the leak-off process. Scanning electron microscopy (SEM) was used to characterize the external filter cake and internal filtration. The core flow experiments were matched to the theory for linear static filtration. The results lead to new insights concerning the build of external filter cake and internal filtration. This work creates a basis for future improvement of oil-based mud, by providing a better understanding of mechanisms involved in leak-off process and its control.
Simulation of Shale Gas Field Development: An Example from Western Australia
Authors: Göedeke Stefan , Hossain Md Mofazzal
Published: June 2014

Shale gas exploration activities have been growing rapidly in Australia. A flow rate of up to 2 MMSCFD has been reported recently from the first exploratory vertical well in the Cooper Basin in South Australia. Perth and Canning Basins in Western Australia are also reported to be highly prospective. However, shale gas production differs from conventional reservoirs primarily because of extremely low permeability and other petrophysical characteristics. Commercial production requires massive hydraulic fracturing often in long horizontal completions.

The potential development of a shale gas field in Western Australia has been simulated to optimize production and minimize development cost through sensitivity analyses. Conditions in Australia are particularly challenging often because of significantly higher costs in drilling, completion and fracturing than those of the US. The minimum number of wells and the maximum Net Present Value (NPV) was iterated by simulation. The factors influencing their overall success of the field development project were investigated in order to generate a workflow model suitable for a variety of cases. The influence of well fracture and other parameters such as completion length, fracture geometry, permeability and gas price was tested against NPV to optimize the development. Optimization of any development should be possible by iterating on any parameter and the related variables. Whilst in conventional gas there is a clear understanding of what is economically viable, this is not the case in shale gas particularly in Australia. Before embarking on any drilling, testing or development activities simulation sensitivity studies of this nature are essential.
Comprehensive Approach to Production Stimulation of Massive Cold Heterogeneous Carbonate Formation using Coiled Tubing
Authors: Dnistrjanskij Vladimir , Mokshaev Aleksander , Bogatyrev Oleg , Ilgildin Ruslan , Kayumov Rifat , Burdin Konstantin , Lobov Mikhail
Published: June 2014

The Orenburg oil, gas and condensate field (OOGCF) is one of the largest fields in the Volgo-Urals region of Russia. It is characterized by complex formation lithology, underlying water, low bottomhole temperature and significant reservoir depletion making successful matrix acidizing particularly challenging. Existing wellbore equipment prohibits the use of inflatable packers. Therefore only chemical diverters can be used for treatments. Thorough engineering and previous acidizing experience in this region lead teams to select the following technologies to account for all challenges in stimulation on OOGCF: Viscoelastic self-diverting acid (VSDA). Based on viscoelastic surfactant, VSDA initially has low viscosity. However, while the acid spends, the fluid viscosity increases, redirecting flow to less permeable zones. After the treatment, viscous VSDA losses its viscosity when it comes in contact with hydrocarbons and/or solvent pumped in the preflush stage. Absence of polymers in VSDA eliminates risk of formation damage.Selective diverter for temporarily blocking water-producing zones. This water-based fluid with viscoelastic surfactant initially has high viscosity. During matrix acidizing treatment, the selective diverter is injected into all zones. Its viscosity sharply drops in the hydrocarbon-saturated zones while maintaining stability in water-saturated intervals, thus preventing acid injection in undesirable zones.Foam diverter allows foam to be generated in the matrix and temporarily plug the pore spaces. This causes temporary plugging of the acid-etched channels and allows unstimulated zones to be treated. The main advantage of foam diversion is fast and efficient cleanup, which is especially important for depleted formations.Highly retarded emulsified acid helps create wormholes while treating long intervals with low pumping rate through coiled tubing (CT).CT placement with pumping foam diverter through CT and HCl through CT - Tubing annulus simultaneously to block known thief zones.

Up to date 3 stimulation treatments were successfully performed with average incremental gas production of 61% that could not be achieved before on this field. A combination of all solutions and technologies mentioned above allowed to address all challenges related to matrix acidizing on OOGCF field.
Application of Novel Technologies Helps Unlocking Deep Omani Gas
Authors: Briner Andreas , Curtino Joe , Al-Siyabi Hisham , Judd Tobias
Published: June 2014

In 2009 Petroleum Development Oman LLC (PDO) started an ambitious tight and deep gas exploration programme exploring for previously untapped reservoirs. The exploration strategy is focusing on both conventional tight gas plays as well as deep unconventional gas resources. These resources are typically in previously undrilled formations at great depths, with high temperatures and unknown pressure regimes, and uncertain fluid fill and composition. The unique geological properties of this type of reservoir require different strategies and technology deployment in order to make them viable and sustainable.

With unique geomechanical, reservoir, and geological properties, some of the large gas-bearing prospects within the Fahud Basin in the Sultanate of Oman require innovative drilling and completion practices. A revised drilling and completion workflow, with specific technology deployment and operational flexibility, has been developed in order to account for such reservoir complexity. This workflow includes the incorporation of rock strength acquisition and stress state of the reservoir prior to completion, in order to identify targets for hydraulic fracturing and quantify hydraulic fracturing performance versus reservoir deliverability. The unparalled challenges encountered whilst exploring for these resources required resolving to new technologies from outside the region and adapting them to local conditions.

This paper demonstrates the need of integrating various unconventional data sources to enhance the chance of successful reservoir characterization that leads to better understanding of presence of hydrocarbons and reservoir quality. It will also show that classical evaluation methods fail and will not lead to unambiguous interpretations. Recent experience has shown that several independent data sources need to be applied to confidently evaluate well results.

The successful application of a technology plan covering aspects of geomechanics, well completions, perforation and formation breakdown, hydraulic fracture placement and treatment yielded positive results that will be of interest to other regional operators facing similar challenges.
Correlation between Rock Permeability and Formation Resistivity Factor-A Rigorous and Theoretical Derivation
Authors: Ling Kegang
Published: June 2014

Rock permeability is one of most important rock properties for fluid flow in reservoir. According to Darcy’s law flow rate is proportional to permeability holding other variables constant. The methods to get permeability include direct core measurement, well test interpretation, estimating from nuclear magnetic resonance (NMR) logs, and calculating from other properties such as porosity using correlations. It is noted that these methods have their own limitations. Core measurement is expensive, time consuming and limited by core availability. NMR logs are high cost. Correlations are often obtained from scatter data point thus their reliabilities cannot be guaranteed. Therefore new method needs to be found to get permeability.

Starting from multiple-capillary tubes concept, we derived a rigorous relationship between permeability and formation resistivity factor. Through this correlation permeability can be calculated from known formation resistivity factor or vice versa. Since formation resistivity factor is often obtained from lab experiment, the new correlation provided an important supplement in permeability estimation without additional cost. In other words, if permeability is known, the new correlation can be used to verify the formation resistivity factor measured from lab experiment, again, without adding cost. The new correlation also provides a unique approach to quantify the radius of capillary tube, which is not available in the literature before this study.