bluuebunny/crossref_metadata_2025 huggingface dataset:
Large-Scale Laboratory Investigation of the Effects of Proppant and Fracturing-Fluid Properties on Transport
Authors: Brannon H. D. , Wood W. D. , Wheeler R. S.
Published: December 2007

The primary function of fracturing fluids is to provide the means and media for the transport and placement of a conductive proppant pack in the created fracture such that resident hydrocarbons may be more easily produced. In recent years significant effort and expense has been invested to develop an ideal fracturing fluid system. Such efforts have been often been akin to the proverbial dog chasing his tail, rather than on the addressing the engineering objective to place a conductive propped fracture. Development focus has been primarily on optimization of fluid rheological stability to get the treatment pumped and secondarily to mitigating any damage caused by new fluid system. Post-frac production analysis frequently demonstrates less than anticipated fracture area, suggesting excessive proppant-pack damage or that the proppant was not placed in designated areal location due to inadequate proppant transport.

Recent testing was conducted in a large-scale slot apparatus at the Well Construction Technology Center in Oklahoma to evaluate the relative effects of proppant slurry component characteristics and the proppant transport capability. The effects of various fluid specific gravities, fluid viscosities, proppant specific gravities, proppant sizes, slurry flow rates, and slot widths were investigated. Testing included fluids from slickwater to gelled, weighted brines, proppants from 40/70 Ottawa sand to 14/30 ultra-lightweight proppants, pump rates from 0.1 to 1.0 bbl/ft/min, and slot widths from 0.25 to 0.5". Evaluation of the proppant transport testing data and the comparative abilities of current fracturing slurry system technologies to achieve placement of a productive propped fracture will be discussed.
High-Temperature Multiphase Flowmeters in Heavy-Oil Thermal Production
Authors: Mehdizadeh P.
Published: December 2007

The accurate measurement of Oil, Water and Gas/Steam in heavy oil thermal production (SAGD and other Steam Flood Processes) is a very difficult task faced by the heavy oil industry. The accuracy of these measurements is critical for reservoir management and production diagnostics. Mulitphase flow meter technology has been used successfully around the world for over 10 years and in heavy oil "cold" production in Venezuela and other countries. But multiphase technology has never been used in Extra Heavy Oil Thermal Production. The Canadian heavy oil thermal producers regularly see production temperatures exceeding 200 C (392 F) and some wells are approaching 232 C (450 F). New technology is required to accurately measure wells producing at these elevated temperatures. The first field tests using a multiphase flow meter in a heavy oil thermal project was conducted by one of the major Canadian producers in the fall of 2004. Additional tests were completed during the summer of 2005 with another heavy oil producer. This paper will review the unique problems encountered with testing heavy oil in high temperature applications. The test results from multiple well tests and the accuracy of the multiphase flow meters when compared to the field reference will be presented.
Successful Rescue of a Sunken Oil Well With Innovative Coiled-Tubing Solution
Authors: Mahajan M. , Al Araimi N. , Portman L. , Terry A.
Published: December 2007

A 36" conductor had been set in 40m of water, offshore Brunei. A jack-up rig was being used to drill two wells through this single conductor. The first well (Well-A) was completed successfully with a smart completion in a 7" liner. The second well (Well-B) was under construction. Multiple millions of dollars had been spent on these two wells. It is at this point that the 36" conductor sank by 15 inches. This slumping of the conductor was enough to cause a failure of the well under construction (13-3/8" casing failed and the Drill string was lost in hole) and severe buckling in the already completed well. This event had potentially rendered the entire operation as nonproductive. Both 13 3/8" casings were cemented into the 36" conductor. The operator was desperately looking for any ideas to save the first well, which was expected to produce some 5000 BOPD.

This paper describes the thought processes, engineering and the job execution techniques involved with the rescue of this well. The cement bond between the casing and the conductor was removed and the casing was successfully re-tensioned. Several innovative techniques were utilized, using coiled tubing, a down hole camera and hydraulic jacks. This paper is intended to share the knowledge gained during this unusual intervention, which successfully brought the well on stream with initial gains of 5,000 BOPD.
Safety Is No Accident
Authors: Mahajan M. , Al Araimi N.
Published: December 2007

Well drilling and service operations generally involves heavy machinery, bulky equipment, heavy lifts, hazardous chemicals, challenging well conditions & worksites and tougher logistical elements. All these elements pose a challenge to the achievement of QHSE performance levels the oil and service companies aspire to achieve today. Over recent years, there has been a lot of learning, understanding and research work into these areas. These, coupled with a tremendous shift in awareness and attitudes towards the QHSE aspects of business, both in the operator and service sectors of industry, have brought in noticeable changes in the business environment. The role of QHSE performance now a days is not only limited to social dimension but it has become very decisive factor in the ultimate financial success of any business entity.

In Feb 2005 a major international operator in the Asia Pacific achieved a milestone of 6+ years LTI-free coiled tubing/well servicing operations. Considering that each and every job conducted throughout this six year period involved some combination of the several high potential hazards as stipulated above, this is indeed an achievement to be proud of.

A critical review of the whole process has been attempted in this paper to identify and highlight the critical components, which have played vital roles in the achievement of this great milestone. It is demonstrated that Safety is no accident; it is something we achieve by hard work, deep dedication, tremendous efforts and relentless follow-ups. We believe that the learning from this study would greatly contribute to improvements in safety performance of similar operations worldwide.
Optimization of Hydraulically Fractured Wells in Irregularly Shaped Drainage Areas
Authors: Daal J. A. , Economides M. J.
Published: December 2007

In using hydraulically fractured wells for aggressive reservoir exploitation, the spacing of vertical wells and/or transverse fractures in long horizontal wells becomes quite an important consideration. The geometry and conductivity of single fractures in infinite-acting reservoirs have been related to productivity by the well known Cinco-Ley and Samaniego work. Later work by Valkó and Economides provided physical optimization under pseudosteady-state conditions in regularly shaped (circular or square reservoirs) using the novel concept of the Proppant Number as a normalizing and descriptive parameter.

However, the shape of the drainage is rarely square and, especially it is not so when a given drainage area is split by the drilling of in-field vertical wells or, in the case of a horizontal well, multiple transverse fractures are executed. The shape of the drainage, encompassing parallel, tightly spaced fractures, becomes a controlling variable for the calculation of the individual and total productivity indices. This is particularly important in our quest to maximize well performance, not just to fracture wells. Until now, such work was the realm of numerical simulation with all the associated benefits and problems.

In this work, the pseudosteady-state productivity index of a fractured well in reservoirs with different aspect ratios (ye/xe) was calculated using the Direct Boundary Method. For relatively small Proppant Numbers, there is a simple relationship that allows for the use of already developed correlations by Valkó and Economides for maximum productivity index and optimum fracture conductivity (and the indicated fracture geometry). For larger Proppant Numbers, this work provides factors labeled Fopt that account for the departure from the square optimum. These factors facilitate the calculation of the maximum JD in different reservoirs for any Proppant Number. The work allows for drainages of a large range of aspect ratios and any fracture penetration.
Diagnosis of Formation Damage by Rock Deformation/Compaction Through Numerical Well-Test Simulations
Authors: Alcalde O. R. , Teufel L. W.
Published: December 2007

Well Tests analysis is a useful tool to estimate and "visualize" properties and performance of reservoirs under production induced stress-sensitivity. Formation damage due to the irreversible nature of rock deformation reduces the permeability, and consequently alters the oil/gas production.

The objective of this study is to assess well tests analysis in stress-sensitive reservoirs to determine the mechanism of permeability reduction and the subsequent well formation damage along with production depletion. Therefore, conventional well test analysis must be modified to include the governing equations describing rock deformation and changing pore pressure.

In this work a 3D fully coupled fluid-flow/geomechanical model accounting for well testing and formation damage has been developed. The numerical model performs well test analysis such as draw-down, pressure build-up and multi-rate tests describing the permeability reduction in stress-sensitive reservoirs. The governing equations were developed in cylindrical coordinates to better simulate the flow geometry that characterize the drainage area in most well tests. Furthermore, it is assumed that the mechanical rock properties are function of the mean effective stress (i.e., nonlinear rock deformation).

For typical field conditions, the results show that a combined effect of rock deformation -caused by pore pressure depletion, and reservoir compaction -caused by the overburden, generates high formation damage approximately within 9.5 feet around the wellbore. This damage is irreversible, and the permeability can only be improved a few feet near the wellbore through well stimulation. It is observed that conventional well-test analysis techniques may lead to erroneous estimations of well performance due to formation damage in stress-sensitive reservoirs. New results illustrate that Reservoir Pressure Distribution plots can be used as a "visualization" tool to identify formation damage by deformation/compaction in well test analysis. Premature diagnosis of the above-mentioned combined effect will provide evaluation and picturing of formation damage for field development strategies.
Acrolein Application To Mitigate Biogenic Sulfides and Remediate Injection-Well Damage in a Gas-Plant Water-Disposal System
Authors: Penkala J. E. , Reed C. A. , Foshee J. D.
Published: December 2007

The unique and reactive chemistry of acrolein enables a 3-fold approach to oilfield problems stemming from sulfate reducing bacteria (SRB): 1) it is an effective biocide, 2) it scavenges H2S, and 3) it dissolves iron sulfide.

In this study, the utility of acrolein for remediation of problems with SRB and biogenic sulfides in a gas plant water disposal system at an facility near Mobile, Alabama is presented. The disposal system, designed to handle produced water from offshore, process water from gas plant operations, and surface water drainage within the plant, was losing capacity due to iron sulfide fouling of the surface equipment and plugging of the disposal wells.

Bacterial monitoring indicated that SRB originating from the drain water had become established in the tanks and flowlines. These SRB were generating 8-10 ppm dissolved H2S that was ultimately responsible for the iron sulfide formation. The iron sulfide resulted in poor water quality (Millipore® rates = 200-300 ml/5 min), tank fouling, filter plugging, injection line scaling, and loss of injectivity due to near well bore damage in the disposal wells.

The treatment design consisted of 1) initial remediation of injection wells by acrolein squeeze stimulations using a coiled tubing unit, 2) removal of iron sulfide pads from the tankage and iron sulfide build up in the disposal lines, and mitigation of SRB populations via batch treatments with acrolein, and 3) preventive maintenance using a continuous and batch treatment program with acrolein.

Immediately following squeeze treatment of the disposal wells, a 30% increase in capacity was observed. The topside treatment program has resulted in a 400 to 500% improvement in Millipore® rates, decreased levels of SRB, greater than 90% decrease in soluble H2S and a 65% decrease in filter replacements. Overall benefits of the program include acceptable injection rates and pressures and reduced operating costs through decreased filter changes, remedial expenses to maintain the disposal wells, and water trucking expenses.
A Guideline to Optimizing Pressure Differential in Underbalanced Drilling for Reducing Formation Damage
Authors: Guo B. , Ghalambor A.
Published: December 2007

Underbalanced drilling (UBD) has been widely used as a means of reducing formation damage during drilling. The benefit of reduced formation damage results from the fact that the borehole pressure is intentionally maintained to be lower than formation pore pressure by a certain pressure differential during drilling the pay zone. It is generally believed that the higher the pressure differential, the less the formation damage, and thus the higher the well productivity. However, high-pressure differentials can cause problems in drilling operations such as wellbore damage due to borehole collapse and excess formation fluid influx to be handled at surface. Under given geological conditions it is highly desirable to find and use an optimum pressure differential to reach a balance between formation damage and wellbore damage.

The objective of this study was to develop a guideline to selection of the optimum UBD pressure differential. Borehole stability, formation fluid influx, and formation damage due to capillary-pressure-driven water imbibition have been considered in this study. The later was quantified on the basis of analysis of water imbibition into water-wet reservoirs. Result of analysis indicates that there exists a critical UBD pressure differential above which the formation damage due to imbibition of liquid from borehole is expected to be insignificant. The magnitude of the critical UBD pressure differential can be estimated using imbibition capillary pressure curve. A procedure for determining the critical UBD pressure differential is illustrated in this paper. This study provides petroleum engineers a guideline to the selection of optimum pressure differential for designing UBD operations.
Low-Sulfate Seawater Injection for Barium Sulfate Scale Control: A Life-of-Field Solution to a Complex Challenge
Authors: Jordan M. M. , Collins I. R. , Mackay E. J.
Published: December 2007

The injection of seawater into oil-bearing reservoirs to maintain reservoir pressure and improve secondary recovery is a well-established, mature operation. Moreover, the degree of risk posed by deposition of mineral scales to the injection and production wells during such operations has been much studied. The current deep water subsea developments offshore West Africa and Brazil have brought into sharp focus the need to manage scale in an effective way. To this end, the challenge of scale control during the lifecycle of water injection, production and onto produced water reinjection has been reviewed for a number of fields by the authors.

This outlines the risk assessment process that should be undertaken to select the most economical and effective scale control methodology (which for sulfate-based scale could be seawater injection with scale inhibitor squeeze treatments to maintain production, or sulfate reduction of the injection water - with or without the need to scale inhibitor squeeze). In the case of sulfate reduction, parameters to be investigated include the degree of desulfation required to minimise the scale risk of downhole scale formation, the impact that the degree of fluid mixing will have on the resulting brine (from injection to production) and the impact that the desulfated brine will have on scale control during produced water reinjection.

The paper draws upon a wide range of technical inputs to make scale management decisions including: computer modelling techniques (e.g., deposition models that incorporate the kinetics of sulfate scale formation at low supersaturation ratios); reservoir simulation of fluid mixing and reaction; the resulting produced brine chemistry; laboratory generated coreflood data to assess chemical selection for scale inhibitor squeeze and produced water application; and field results that will demonstrate the impact of the type of injection water source on the long term manageability of such deepwater projects. Finally, the paper outlines in detail the particular issues associated with the full economic assessment of low-sulfate water injection versus full sulfate seawater injection.
Simulation Study of Re-Entry Drilling for Gas/Condensate Reservoir Development
Authors: Luo S. , Barrufet M. A.
Published: December 2007

Gas-condensate reservoirs usually exhibit complex flow behavior due to the near-wellbore condensate bank build-up when bottomhole pressure drops below the dew point. Such an accumulation of condensate liquid in the near-wellbore region forms a ring that may significantly reduce the gas relative permeability and consequently the well productivity. Also, when reservoir pressure drops below the dew point, a big portion of condensate liquid will remain in the reservoir and will not be produced.

Many condensate reservoirs have been producing with vertical wells. This paper presents a practical strategy of rejuvenating gas-condensate reservoir production through multilateral sidetrack reentry drilling technology. Simulation studies show that reentry drilling through vertical wells can help break the condensate bank damage and significantly increase well productivity.

Sensitivity analysis of fluid type, reservoir permeability, lateral length, and reentry drilling time on production performance, is conducted. Results show that multilateral reentry drilling represents a very promising technology for developing medium/low permeability gas-condensate reservoirs.
Case Histories: Damage Prevention by Leakoff Control and Cleanup of Fracturing Fluids in Appalachian Gas Reservoirs
Authors: Paktinat J. , Pinkhouse J. A. , Williams C. , Clark G. A. , Penny G. S.
Published: December 2007

The primary purpose of surfactants used in stimulating Sandstone reservoirs is to reduce surface tension. Conventional surfactants adsorb rapidly within the first few inches of the sandstone formations, thus losing their effectiveness as the treating fluid leaks off. This results in trapped fluids and poor post fracturing fluid recovery. A surfactant solvent system in the form of a microemulsion can also be used to not only lower surface tension at very dilute concentrations, but alter contact angle and lower capillary pressure to further improve recovery. The unique microcells are also effective in controlling leakoff.

This study describes the laboratory experiments and field case studies of various surfactants used in the oilfield. Several surfactants including an ethoxylated linear alcohol, a nonyl phenol ethoxylate and a microemulsion system were investigated to determine their adsorption properties when injected into laboratory sand packs. Laboratory studies were also conducted to compare the leakoff and water recovery properties from gas wells.

Field data collected from Bradford and Speechley sandstone formations confirms experimental sand pack and core flow investigations. Reservoirs treated with microemulsion fluids demonstrate exceptional water recoveries when compared with conventional surfactant treatments. Wellhead pressures, flowing pressures and production data were collected and evaluated using a production simulator to show effective fracture lengths and drainage areas with various fluid systems.

Lab and field data collected in these studies from Appalachian Basin reservoirs illustrates that the addition of a microemulsion to a fracturing fluid exhibits significant advantages over the conventional surfactant treatments when water recovery, increased effective fracture length and well productivity are of concern to the operator.
A Critical Review of Chirag Field Completions Performance—Offshore Azerbaijan B
Authors: Powers B. S. , Edment B. M. , Elliott F. J. , Gilchrist J. M. , Twynam A. J. , Parlar M.
Published: December 2007

Chirag field was the first of three fields put into production in the Azeri – Chirag – Guneshli (ACG) megastructure, located in the Azeri sector of the Caspian Sea and operated by BP on behalf of Azerbaijan International Operating Company (AIOC). Production commenced in late 1997 after completion of the Chirag A01T1 well. A number of different sandface completion types have been installed in Chirag injectors and producers during the Chirag Early Oil Project (EOP), and significant data have been collected to evaluate the performance of each completion type. Completion types include cased and perforated, open hole gravel packs (OHGP) using wire-wrapped, pre-packed and alternate path (shunt-tube) screen technology, stand-alone porous metal fiber premium screens, and expandable screens. To date, 29 completions have been installed in 19 of 24 available well slots in primary and sidetrack wells.

Many of the producing wells are equipped with permanent downhole pressure-temperature gauges, the flowlines are equipped with acoustic sand detection devices, and an active separator production test and surveillance program has resulted in a quality data set to evaluate completion performance under initial "dry oil" (water free) conditions, and upon the onset of produced water. This quality data set has greatly assisted the completions performance analysis, which has helped shape completion decisions and technology requirements for full field development.

The paper will review the completion evolution in Chirag field, the relative performance of completion types over a broad range of indicators, and will include a discussion about measures taken to improve open-hole gravel pack performance from a reservoir damage perspective, with a focus on producers.
Openhole Gravel Packing With Oil-Based Fluids: Implementation of the Lessons Learned From Past Experiences Leads to the Best Producer in Okpoho Field, Nigeria
Authors: Ofoh E. P. , Wariboko M. E. , Uwaifo F. E. , Parlar M.
Published: December 2007

A large majority of the recent deepwater developments in West Africa require sand control applications. Openhole gravel packing is the preferred sand control technique adopted by many operators in this region. It is considered one of the proven methods of sand control from both reliability and productivity standpoints, and allows access to larger reserves through fewer wells. Since most of these reservoirs contain reactive shale streaks, they require synthetic/oil-based drilling fluids (S/OB). Considering that the openhole gravel packing in the industry deals primarily with water based fluid environments, new challenges for gravel packing of the associated wells are thus introduced. A significant level of progress has been made in recent years towards overcoming the challenges through new developments in fluids application, tools and techniques. These developments have resulted in successful gravel packing of wells drilled with oil-based (OB) fluids, which have yielded well productivities, which, in many instances, exceeded those completed in water-based drilling fluid environments. Currently, techniques and fluid systems are available for gravel packing with either a water-based (WB) or an oil-based gravel packing fluid. Both approaches have been practiced in various regions in the world. A common and critical element of both approaches is the proper assessment of potential plugging of the sand control screens during installation and subsequent displacement processes, since the screen installation often must be accomplished with solids-laden fluids (conditioned oil-based mud) in the wellbore, due to logistical challenges and economics.

An OB carrier fluid was recently used for openhole gravel packing of a well in Okpoho field, offshore Nigeria. The application resulted in the best producer in the field. This paper details the steps taken through the design and execution stages of the treatment, incorporating the lessons learned from two previous applications of the OB carrier fluid. A detailed description of the yard tests conducted in Nigeria and the onsite QA/QC procedures with screen samples are also included. A simple approach is proposed for quantification of the impact of screen plugging test results on field practice. This allows operators to evaluate how much, if any, screenplugging can be expected with the particular conditioned OBM as the screens are run in hole and during subsequent displacement processes, so that the operator can decide whether further conditioning, and thus the additional rig time, is worth the associated cost.
Evaluating Bottomhole Pressure for Foamed Acid Stimulation
Authors: Ejofodomi E. A. , Zhu D.
Published: December 2007

Evaluation of bottomhole pressure from measured surface pressure during an acid stimulation treatment provides necessary information to determine the evolution of skin factor as the treatment proceeds. Calculation of bottomhole pressure could be very complicated when compressible fluids are involved in the injection process, such as when foam is used as a diverting agent.

This paper presents a mathematical model for predicting bottomhole pressure from measured surface pressure. With the aid of the continuity equation and the equation of state, we developed a unique solution to the steady-state mechanical energy-balance equation. The density variation is included through an equation of state (EOS). Viscosity variation is considered through the Reidenbach's viscosity model, which is a laminar flow model of a yield pseudoplastic fluid with viscosity dependent on foam quality and fluid rheological properties. For different stimulation fluids injected into the wellbore, the length of each fluid column has to be tracked as the treatment proceeds, and the reduction of column length for compressible fluid as it flows down the wellbore is considered for accurate bottomhole estimation.

The model was tested against previously published data with satisfactory results. We illustrate in this paper the applications of the model by showing the complex surface pressure behavior that can occur when foams are used in acid treatments. The model is flexible and reliable, and can easily be adapted to a skin factor calculation model in matrix stimulation for stimulation treatment evaluation.
Delayed-Release Acid System for Cleanup of Al Khalij Horizontal Openhole Drains
Authors: Leschi P. , Demarthon G. , Davidson E. , Clinch D.
Published: December 2007

It is well known that the use of hydrochloric acid to clean up and restore permeability of open holes drilled in limestone formations is a questionable procedure. It is necessary to remove, not only the filter cake at the well bore face but, more importantly, the low permeability crushed zone created during the drilling operation. To achieve uniform treatment of the entire openhole section with hydrochloric acid is difficult: the rapid reaction of the acid in downhole conditions often creates a localized loss zone, through which most of the treating fluid is lost so that treatment of the entire section is inefficient.

Traditional completion practice on Al Khalij field (Qatar) involved cemented casing, perforations and subsequent stimulation of the limestone with retarded emulsified hydrochloric acid and ball sealers. This paper describes a new and different approach, which involves leaving drains in openhole condition and using a slow acting stimulation treatment for damage removal and stimulation. The stimulation treatment comprises a starch enzyme to degrade the most troublesome polymer and an organic compound that reacts with the carrier brine to release organic acid in situ over a period of several hours. The breaker fluid is introduced to the openhole section in a neutral pH condition, thus enabling it to be distributed over the entire interval of interest. Enough acid is generated over the subsequent 12 hours to remove the filter cake and clean up the crushed zone.

This system has recently been used on several occasions on this field, with openhole drain length ranging from 530 to 1890 m (1,740 to 6,200 ft) and treatment volumes ranging from 20 to 115 m3 (125 to 725 bbl). Losses from these wells occurred after the predicted elapsed time. Details are provided of how the jobs were carried out and the results achieved.
The Effect of Fluid Leakoff on Rock Failure Mechanisms During Frac-Pack Treatments
Authors: Gil I. R. , Roegiers J.
Published: December 2007

Frac-pack treatments are commonly used on highly permeable and unconsolidated (hence, highly productive) formations as a means of preventing the occurrence of sanding while bypassing the damaged zone around the wellbore. These treatments are currently designed using hydraulic fracturing models that assume planar symmetrical geometries, tensile rock failure, and - usually - one-dimensional fluid leak-off schemes. However, it is not uncommon to find that the pressure predictions from these models and the ones measured in the field differ substantially.

This paper addresses the issue of hydraulic fracturing stimulation treatments in poorly consolidated formations without the handicap of using such assumptions. In this study, the discrete element method (DEM) was used and the program was calibrated in order to reproduce the mechanical and hydraulic responses of a selected unconsolidated sandstone1. During this process, both its mechanical properties (Young's modulus, Poisson's ratio, stress-strain curve, and compressive strength) as well as its hydraulic characteristics (permeability) were matched.

The modeling effort presented here allows fracture propagation to be a direct consequence of the interaction of shear and tensile microcracks induced in the material during the injection process. Thus, à priori assumptions on the final geometry of the macro-scale fracture are not required.

For the modeled rock, it was found that the nature of fluid leak-off as well as the pumping rate determine the fracture propagation process. The shape of the curves representing the number of induced cracks changed as a function of the fracturing fluid viscosity. The effect of pressure differential was also found to be important during the fracturing process.. A remarkable finding by exercising this model was that, in the particular case of the Antler Sandstone (and possibly for other unconsolidated formations), shear failure seems to be more important than tensile failure during the hydraulic fracturing process. The "normal" planar macro-scale fracture was deemed to be the consequence of microcracks interactions. In addition, a "process" zone was found to exist around the wellbore. This conclusion is in clear contradiction to what has been traditionally accepted in the oil and gas industry, and could explain the difference observed between standard model predictions and the conditions encountered in the field.
Production Forecasting in a Limited-Data Environment: Evolving the Methodology in the Yamburgskoe Arctic Gas/Condensate Field, Russia
Authors: Shumakov Y. , Burov A. A. , Butula K. K. , Zynchenko I. A.
Published: December 2007

Though there are many proven ways of predicting productivity in hydraulically fractured wells in medium-permeability oil reservoirs, there is still no simple, practical production forecasting methodology for hydraulically propped fracturing stimulations for the gas and gas-condensate wells in the Western Siberian Arctic sector.

The candidate selection process, including production prediction, is at an infant development stage and is additionally hampered by the lack of, or ambiguity in, the reservoir and production data.

This is particularly true for the Yamburgskoe gas condensate field, where the wells are completed in a series of medium- and low-permeability reservoirs. Some wells cannot maintain stable production rates and have either been shut-in or are on intermittent production. Factors may include low reservoir quality, reservoir pressure, and specific production conditions. A reliable methodology for selection of candidate wells for stimulation treatments was clearly needed.

This paper describes the comprehensive methodology derived from integrated analysis of the fracturing treatments performed between 2003 and 2005 in the Yamburgskoe gas- condensate field.

The analysis revealed a series of correlations and elaborated an engineering approach that reduced the assumptions in the estimation of hydraulic fracturing efficiency, particularly for the wells that were completed but were unable to maintain stable production. Although the certainty of the final, stabilized production rate remains a challenge for the production and stimulation engineer, recent production results showed that hydraulic propped fracturing can bring many wells to economical production.
New Method To Estimate Damaged Formation Permeability With Well Testing
Authors: Zhang L. , Dusseault M. B. , Xu B.
Published: December 2007

Most composite solutions used in modem well test interpretation use the "step-permeability" model where the altered formations are divided into two or more concentric zones, each with constant permeability. Depending on the causes of alteration or variation, this model can deviate significantly from the real condition. A formation can be altered because of stress redistribution, drilling damage, solids co-production, mineral precipitates, and drilling mud invasion, each factor more likely to generate spatially-varying permeabilities rather than constant k zones. Experimental data confirm that a continuous permeability model is more realistic than the step permeability model.

A new semi-analytical solution with smooth radius-dependent permeability has been developed to analyze well test results from such altered formations. The altered formation is approximated as a concentric two-zone composite model: an exterior intact zone that retains the original unaltered permeability, and an interior zone where the permeability values have been altered and change as a function of radius. The permeability in this near-well zone can change continuously to the original permeability or to a different value at the boundary with the exterior zone, where there is a step-change in permeability. The choice of an increase or decrease of permeability with radius within the altered zone depends on the nature of the actual alteration. The permeability can also be simulated as a step-wise function if appropriate parameters are used; in such situations, the model collapses to conventional step-wise composite models. Other parameters such as formation porosity and compressibility of each zone can also be different, but they are assumed constant for this derivation. The new solution is derived in Laplace space, and numerical Laplace inversion is used.
Waterflooding Conformance and Water Quality: Flow Partitioning During Produced-Water Injection
Authors: Abou-Sayed A. S. , Sarfare M. D. , Zaki K. S.
Published: December 2007

Flow distribution plays an important role in Produced Water Re-Injection operations. This is especially true when the injection horizon contains isolated hydraulic units that are individually capable of accepting part of or the entire injection rate. The hydraulic units maybe separated by an impermeable barrier, shale, and/or have variations in the minimum horizontal stress. Under normal operating conditions fractures initiated in one or more of these units would not intersect or combine. The fracture growth becomes a coupled problem where growth in one hydraulic units is dependent on growth or retardation in other units. Retardation might be caused by solid and oil deposition in the fracture that would plug its tip and damage its faces. Plugging would decrease available fracture length for leakoff below the actual total length of the fracture. Such scenarios become difficult to control if not initially planned or designed for and can lead to undesirable effects such as inefficient sweep or uncontrolled fracture growth.

In the following discussion the design and monitoring criteria for such problems will be addressed. We will review some available tools and prominent parameters and/or variables that affect this behavior both from a time dependent and independent point of view. Particular attention will be placed on the damage mechanisms, total suspended solids (TSS) and oil in water (OIW), and their effects on altering the injection rate distribution as a progressive time dependent phenomena.

Finally, two scenarios will be presented, as practical examples of field cases where flow partitioning issues presented a particular concern as a result of inherent reservoir properties.
Perforation Damage Removal by Underbalance Surge Flow
Authors: Bolchover P. , Walton I. C.
Published: December 2007

In cased completions, perforations provide the essential link between the wellbore and the reservoir. Productivity of the completion is promoted by optimizing perforation characteristics such as geometry, phasing and density, but unfortunately it is restricted by the perforation damage zone— a region of low permeability material surrounding the perforation tunnel, and created by the impact of the shaped charge jet on the rock fabric.

Perforating underbalanced has become the primary means of removing perforation damage and maximizing productivity, though the mechanism by which it does so is still not very well understood. Underbalance perforating also serves to remove some or all of the comminuted sand grains that fill the perforation tunnel immediately after penetration of the rock by the shaped charge jet. Predictions of the required undeibalance to remove the damage zone or remove the comminuted fill are at best uncertain.

In this paper we describe the development of mathematical models that predict the pore pressure in the rock surrounding the perforation tunnel as the wellbore pressure drops during, for example, a dynamic underbalance operation. From this we calculate the magnitude and duration of the induced surge flow. The third stage in the analysis investigates the mechanisms through which the damage zone is removed.

As a result of these calculations we are able to predict the surge rate (and associated underbalance) required to remove the damage zone. Moreover we predict the perforation skin that results from incomplete removal of the damaged zone and for the first time we are able to determine how the skin depends on the degree and rate of underbalance.
Sustaining Conductivity
Authors: Weaver J. D. , van Batenburg D. W. , Parker M. A. , Nguyen P. D.
Published: December 2007

Rapid loss of fracture conductivity after hydraulic fracture stimulation has often been attributed to the migration of formation fines into proppant pack or the generation of fines derived from proppant crushing. Findings presented in this paper suggest that diagenesis-type reactions that can occur between proppant and freshly fractured rock surfaces can lead to rapid loss of proppant-pack porosity and loss of conductivity. Generation of crystalline and amorphous porosity filling minerals can occur within the proppant pack because of chemical compositional differences between the proppant and the formation, and the compaction of the proppant bed due to proppant pressure solution reactions.

This damage mechanism is applicable to all propped, fracture-stimulated wells; however, it is more significant in high temperature and high stress wells. It provides a possible explanation for the difference often observed between reservoir simulation of production after fracturing and actual production.

Studies indicate as little as 25% of the initial proppant- pack porosity may remain after only 40 days at 300°F and 6,000-psi closure stress. The rate of porosity loss can be influenced by the surface treatment of the proppant, which indicates that some control of this process may be accomplished.

Significance of this discovery has great impact on the economic life of a fracture-stimulation treatment. It affects the choice of proppant composition and post-fracture cleanup procedures, and adds an additional dimension to the appropriate laboratory determination of fracture conductivity that might be expected with the use of a particular proppant.
Case Study of Multiple Hydraulic Fracture Completion in a Subsea Horizontal Well, Campos Basin
Authors: Neumann L. F. , Fernandes P. D. , Rosolen M. A. , Rodrigues V. F. , Silva Neto J. O. , Pedroso C. A. , Mendez A. , Torres D. S.
Published: December 2007

This paper provides a case history of the first hydraulic fracture on a subsea horizontal well in the Quissamã formation, a low permeability limestone reservoir, in Campos Basin, Brazil.

The well was drilled in the direction of the expected fracture growth, thus evolving longitudinal fractures along the horizontal section. It is part of a research project to evaluate selective stimulation methods for subsea horizontal wells. Every single aspect since the drilling, completion, and evaluation of the well, was done with the end in mind of hydraulically fracturing it in several stages.

Hydraulically fracturing a horizontal well has become a more accepted practice in our industry. The procedures used on fracturing of vertical wells must be taken into consideration when fracturing a horizontal well, to avoid re-fracturing work. Near-wellbore (NWB) problems are usually the main cause why fracturing work are not completed. This paper describes hydraulic fracture treatments with detailed discussion on analysis of calibration tests, fluid efficiency tests, and lessons learned.

Results of the pumping work will be presented showing theory and common practices played a key role for a successful application of techniques used. Laboratory tests are presented performed with cores taken from the well itself such, as rock mechanics, proppant embedment, compactation measurements, and basic mineralogy.

Production results will be presented and compared to conventional methods used on other subsea horizontal completed wells in Campos Basin.
Expandable Sand Screens and Drilling Fluids: Laboratory Testing For Successful Field Application
Authors: Beare S. P. , Ballard T. J.
Published: December 2007

There are two considerations related to the drilling mud when installing sand screens: plugging of the filter media when running the screens into the wellbore, and then transporting the filtercake back through the screen when the well is produced. For compliantly expanded sand screens producing the mud filtercake is potentially more problematic as the screen is pressed into the cake during installation, and there is no annulus to allow the cake to break up and disperse before reaching the screen.

This paper describes laboratory tests for evaluating drilling fluids for use in the reservoir section when expandable sand screens are to be installed. Several examples of the results of the laboratory tests are related to well performance in the field to establish the relevance of test results. Only partial removal of the mudcake is required to give good return permeability in laboratory tests, and so field performance is predicted from comparing results with and without the screen filter medium present. This method correlates to the field, where low skins and good production have been observed with muds which give similar return permeabilities independent of screen presence in laboratory tests. Furthermore, forcing the screen into the mud filtercake during installation does not generally impede filtercake removal.

Based on these results some limitations on drilling mud formulation and conditioning for successful screen applications are established. The effect of screen presence on chemical clean-up treatments is briefly discussed, and an example is given where a failure in the field was related to poor mud conditioning prior to running the screen.
Thermal Decomposition of Thiocyanate Corrosion Inhibitors: A Potential Problem for Successful Well Completions
Authors: Ke M. , Qu Q.
Published: December 2007

Salts of thiocyanate (SCN-) have been widely used as corrosion inhibitors in halide-based brine completion/packer fluids for many years. When applied, they have unique characteristics over conventional amine-based inhibitors (excellent solubility in high-density brines and ability to control corrosion of brines on carbon steels and low alloy steels at high temperatures). However, SCN- may decompose at high temperatures to produce H2S or free sulfur. When SCN- thermal decomposition occurs in zinc bromide (ZnBr2)-based completion/packer fluids, H2S or byproduct of free sulfur can react with zinc ion to form zinc sulfide (ZnS) scale. The ZnS scale can cause formation damage and plug downhole tubular assemblies. Additionally, sulfide (S2-) can induce sulfide stress corrosion cracking (SSC) of high-strength and high-alloy steels under downhole environments. The presence of ZnS scale and SSC of downhole tubulars requires subsequent workovers to restore well productivity.

This paper presents the results of laboratory evaluation on thermal decomposition of SCN- inhibitors. Evaluation primarily focuses on the effect of temperatures on decomposition of thiocyanate inhibitors in ZnBr2 brines. Heat-aging tests of ZnBr2 brines inhibited with SCN- inhibitor, along with SEM/EDS techniques, were conducted to determine the decomposition temperature of SCN- and its potential to form ZnS scale. Results indicate SCN- thermally degrades at temperatures lower than those published in the literature. Evaluations of stress corrosion cracking (SCC) behavior of a high-strength and high-alloy steel in the presence of NaBr and CaBr2 brines treated with a SCN- inhibitor also are presented. These results reveal the decomposition of SCN- could cause SCC of high-strength and high-alloy steels even in chloride-free brines such as NaBr and CaBr2.
Sand Retention Testing: The More You Do, the Worse It Gets
Authors: Ballard T. J. , Beare S. P.
Published: December 2007

Sand retention testing is often required when selecting screen media and media size. It has also been used to define the limitations of retention for different media1. However, the results from such tests are very dependent on experimental conditions and prone to artefacts. Small and apparently innocuous changes to the test conditions can cause wide variations in results. Some of the factors affecting test results are discussed. The problems of artefacts can be overcome, at least in part, by considering trends in data rather than absolute results.

A previous paper described the performance of Dutch twill weaves (DTW) and identified a selection criteria based on particle size distributions measured by laser light scattering1. This paper extends that work to include sintered media from other premium screens and wire wrap screens. The general trend in the data from a number of tests shows good correlations between some aspects of the sand distribution and retention performance of the individual media. From these data, an aperture sizing criteria for sand screens based on laser particle size measurements is proposed, and screen selection parameters considering both retention and "plugging" performance are identified.