bluuebunny/crossref_metadata_2025_split huggingface dataset:
Diagnosis of Formation Damage by Rock Deformation/Compaction Through Numerical Well-Test Simulations
Authors: Alcalde O. R. , Teufel L. W. 
Published: December 2007

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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.