bluuebunny/crossref_metadata_2025 huggingface dataset:
Critical Analysis of Exploratory Wells in a New Field Development in Trinidad and Tobago
Authors: Dwarkah D. R. , Boodoo C. S. , Rajnauth J. J. , Seecharan K.
Published: December 2007

This paper seeks to identify the causes and relative magnitudes of wellbore stability problems in a recently discovered, highly faulted field in Trinidad and Tobago. The two main factors that have been identified are reactive shales and tectonically stressed formations, which result in wellbore caving and seepage losses of mud under static conditions. Our data set includes every well drilled in the field to date. In order to determine whether problems are wholly formation related or are in part caused by drilling parameters, the following were analysed: Rate of penetration per day in the formation of interest. This data was used to determine if wellbore cleaning problems were associated with high rates of penetration. Models for wellbore cleaning employed ranged from the simplistic CCI model to the more advanced service company methods. Parameters such as pump rates were inherently a part of this assessment.Caliper logs to assess the degree of washouts in formations of interest.Mudlogging data to identify the degree to which formation problems are tectonic or chemical in origin.Comparison of mud type used in all wells to drill formations of interest in order to determine its relevance to the problem.Assessment of bit type used in an effort to find out whether there was a higher low gravity solids (LGS) content in the mud with one or other bit type. This influences the hole cleaning properties of mud such as PV and YP.

This paper documents a potential solution to the problems identified and details the drilling history of an exploratory well in a field where these conditions apply.

It is hoped that the results of analysis presented in this paper will provide guidance for future exploration and appraisal programmes on the east coast of Trinidad.
Third-Party Verification of a Company-wide Inventory System under the New ISAE 3000 Assurance Standard
Authors: Nordrum S. , Cain J. , Lee A. , Eddis M. , Woo C. M. , Shires T. , Campbell L.
Published: December 2007

Having completed its first post-merger greenhouse gas (GHG) emissions inventory in 2002, ChevronTexaco engaged KPMG LLP (UK) and URS Corporation to perform an independent review of the GHG data quality for both 2002 and 2003. A key objective was to enable ChevronTexaco to set GHG emissions goals with the assurance that the goals are based on sound and robust baseline data. The verification exercise also demonstrated the company's clear commitment to action on the climate change issue by implementing and verifying an enterprise-wide GHG emissions inventory. KPMG and URS conducted a phased approach to the verification process. Phase 1 consisted primarily of system, process and protocol reviews at the corporate level, and Phase 2 focused on system and process reviews at the business unit level. The third party verification process helped ChevronTexaco to more fully understand the challenges of reporting reliable GHG data. This paper presents the results of and key learnings from the third-party verification effort.
Bioreactors for Natural Gas Desulfurization
Authors: Fidler B. R. , Sublette K. L. , Jenneman G. E. , Bala G. A.
Published: December 2007

Approximately half of the reserve gas in the U.S. is subquality, meaning it contains contaminants such as hydrogen sulfide (H2S) or carbon dioxide. One of the most common problems in the gas industry is the removal and disposal of H2S also known as natural gas desulfurization or sweetening of sour gas. Many traditional methods of H2S removal are costly, energy intensive, and potentially dangerous. Therefore, these methods may not be suitable for some gas-production sites. Biological oxidation offers a safe, energy efficient, and cost-effective method for natural gas desulfurization. This laboratory has investigated biological oxidation of H2S for some time and the current research focuses on bioreactors to treat ‘stranded’ natural gas. Preliminary data were previously presented at EPEC 20021; this paper includes new designs and experimental data. Bioreactors utilizing the immobilization matrices Bio-Sep® and Bio-Sep®S (sufide-sorbing version) inoculated with Thiobacillus denitrificans have been used to treat a gas stream containing 10,000 ppm H2S. The desired removal efficiency is greater than 99%. Stirred-tank reactors were operated with both matrices for 3 and 8 months at maximum gas flow rates of 130 and 72 mg H2S/h for the original and sulfide-sorbing beads respectively, with removal efficiencies near 99.9%. Phospholipid fatty acid (PLFA) analysis revealed cell densities on the order of 1010 cells/g of bead. Packed-bed reactors will also be operated with both matrices. Feasibility studies will be conducted for both types of reactors. This research is ongoing with the goal of developing an economical bioreactor to treat ‘stranded’ natural gas.
Evaluation of Marine Sediment Qualities and their Effect on the Marine Closed Bottle Test for Testing the Biodegradability of Synthetic Drilling Mud Base Fluids
Authors: Roberts D. J. , Rabke Stephen , Bernier Rene
Published: December 2007

Biodegradation testing is one of the compliance issues for using Synthetic-Based Drilling Fluid (SBF) technology for drilling oil and gas wells off the US coast. In order to address this issue, the US EPA incorporated a modified version of the standardized biodegradation procedure ISO 11734 as a regulatory limitation for SBF discharges. The test uses marine sediments spiked with the test fluids and incubated anaerobically in closed serum bottles. The production of gas (CO2 and CH4) from the sediment is used to monitor the progress of biodegradation. The source of marine sediment is a critical factor affecting the rate and extent of olefin SBF degradation. This paper describes laboratory studies that investigated the potential of several marine sediments from around the Gulf of Mexico coast to serve as inocula for the anaerobic biodegradation test. Sediment performance was evaluated against chemical, physical, and biological properties in order to identify key screening parameters for selection of sediment in this test. Increasing numbers of sulfate-reducing bacteria, methanogens, general anaerobes, and aerobic hydrocarbon degraders correlated well with increasing degradation rates. The research identified a sediment screening tool that would optimize conditions for fluid degradation and may help avoid costly test-control failures. A study designed to test the effect of sediment storage revealed that sediment could be stored for up to 14 months and still pass the control criteria.
OSPAR-Compliant Technologies for Managing Drilling-Fluid Lost-Circulation Events
Authors: Fang C. C. , Thaemlitz C.
Published: December 2007

In the oil and gas industry, loss of circulation while drilling is a common problem. Lost drilling fluids typically go into fractures induced by excessive mud pressures, into pre-existing open fractures, or into large openings with structural strength in the formation. Loss of circulation can be costly and difficult to control. Severe losses can disrupt drilling operations for days. A wide variety of materials have been used or proposed [for patents] in attempts to cure lost circulation.1-5

One of many lost-circulation materials (LCM) used by drilling fluid companies is a super absorbent polymer (SAP). Crosslinked polyacrylamides, polyacrylate, or a combination of both are examples. These SAPs can be used alone or in combinations with other LCM to stop the fluid loss.6-9 SAPs function as LCM by expanding many times in volume when they encounter the fluids downhole and stop the fluid loss by plugging the fractures in formation. These SAPs have shown excellent technical performance; however, they have poor biodegradability, often less than 5% in 28 days (Organization for Economic Co-Operation and Development [OECD 306] Test for Biodegradability in Sea Water). Consequently, there are strong demands from both the regulatory and economic perspectives to develop more environmental friendly LCM to be used offshore.

The ideal LCM for offshore should be formulated with seawater and pose little or no risk to the marine environment, so that after the job is completed, the used LCM can be disposed of overboard. To achieve these goals, research is needed to develop an environmentally acceptable alternative. In this paper we report the results using a biodegradable super absorbent alternative as LCM. Our efforts include studies to further understand the key roles of absorption rate, efficiency and particle size in LCM. Experiments focused on the performance of candidate materials over wide ranges of temperature, pH, and salinity, and also their biodegradation and toxicity performance.
Effect of Residual Oil on the Particle Deposition Profile in Deep-Bed Filtration During Produced Water Reinjection
Authors: Ali M. A. J. , Currie P. K. , Salman M. J.
Published: December 2007

An on-line linear X-ray apparatus has been used to examine deep bed filtration during water injection in Bentheimer sandstone core samples. The aim of this project was to investigate the effect of residual oil saturation on the deposition profile of suspended solids in the injected water, and to compare that with a previous study at fully brine saturated cores. Hematite particles were used as suspended solids in the brine. The X-ray apparatus was used to estimate the amount of deposited material at any time and distance along the core sample. Permeability decline as determined by the pressure change and chemical analysis of hematite concentration were used to confirm the X-ray analysis.

The effect of residual oil saturation was seen in most of the samples. The presence of oil caused greater apparent damage (reduction of permeability). It was also observed that there is rather deeper invasion at residual oil saturation than at fully brine saturation, and it was inferred from the X-ray measurements that the external filter cake is thicker.
Small Propped Fracture to Remove Near Wellbore Formation Damage: An Example From the Veslefrikk Field in the North Sea
Authors: Haugland T. , Berg E. , Tjomsland T.
Published: December 2007

Preventing scale precipitation is one of the main issues for maintaining well productivity on the Veslefrikk Field 1. An oil soluble scale inhibitor treatment was pumped that reduced the initial productivity index (PI) from 21 Sm3/d/bar to 3 Sm3/d/bar. Reperforation only restored some of the productivity (from 3 to 7 Sm3/d/bar) indicating deeper near wellbore damage. A small hydraulic fracture stimulation was then performed, creating a propped fracture with a half-length of approximately 6 m. The PI then increased to 30 Sm3/d/bar, a 43% increase from the initial value. The stimulation was performed under pressure through a 2 7/8" work string run on Rig Assist Snubbing (RAS) with pumps and blenders rigged on the pipe deck.
Mineralogy Driven Scale Inhibitor Squeeze Designs
Authors: Gdanski R. , Funkhouser G. P.
Published: December 2007

This paper will discuss several aspects of how formation mineralogy can affect treatment designs. The paper will show how the mineralogy can be used to create a first good estimate of the adsorption isotherm, which is normally the primary controlling mathematical function that describes how the scale inhibitor will return from the formation. This was accomplished by first determining the true equilibrium adsorption isotherms of an example scale inhibitor on various single minerals. Short-core tests are often used to determine whether issues of formation damage might be relevant. However, this paper will show that scale inhibitors, particularly at pH less than 5, are reactive with formation mineralogy and can lead to fluid conditions not achievable in short-core testing, and therefore not generally anticipated during the squeeze treatment. Consequently, short-core tests may not always be a reliable indication of damage potential. This paper will discuss how an evaluation of the formation mineralogy can lead to insight into ways to avoid many damage mechanisms unobservable in short-core testing.
Production Enhancement From Sand Management Philosophy: A Case Study From Statfjord and Gullfaks
Authors: Andrews J. , Kjørholt H. , Jøranson H.
Published: December 2007

Statfjord and Gullfaks are "Brown" fields operated by Statoil in the Tampen area of the North Sea. The production from these fields is characterized by large volumes of water and increasing sanding tendencies. The operator has for many years followed a strategy whereby sand produced with the wellstreams has been handled topsides prior to on-site disposal. The adoption of a sand management strategy has been crucial for prolonging economic reservoir development during tail production. By choosing to deal with sand topsides the operator has been able to pursue low cost slot replacement drilling where wells are completed without sand control equipment. The cased-hole functionality has facilitated multitarget drilling and is suited to selective production of each sand member through cheap plug/perf interventions.

Significant gains in production (acceleration) and reserves (IOR) have resulted from the pursuance of sand management in these fields. Examples of wells showing productivity improvements as a direct result of allowing intervals to produce sand are presented. In addition, production gains achieved from replacing choked back "sand free" production with "maximum acceptable sand rate" production are presented. Increased sand tolerance has also led to reserve increases in some wells as unproductive intervals that were previously sanded up have cleaned up and started to flow. It will be argued that this strategy negates many concerns with formation damage during well work because such damage is produced out with the sand and the wells clean up naturally.

The transient nature of sand production is discussed and the production gains observed in each field is presented. Such a strategy requires that the sand production is managed in a safe and controlled manner where the negative consequences of sand production are manageable and predictable. This paper will also discuss the improvements made in sand detection and on-line erosion mapping required to improve the sand tolerance of these facilities.
Certifying Reserves Certifiers: The Time Has Come
Authors: Harrell D. R.
Published: December 2007

The E&P industry is taking steps to educate, test and certify qualified petroleum geologists and engineers in the specialty practice of evaluating and estimating petroleum reserves. The primary benefit of the elective certification program would be to heighten understanding and upgrade competencies through a rigorous curriculum designed by experts in the field. A secondary benefit would be to help restore a loss of investor confidence in publicly reported reserves estimates. This loss occurred after several major reserves writedowns during the first quarter of 2004. Also, the self-administered program may head off current initiatives to make third-party reserves audits mandatory, creating an opportunity for industry to take the lead before government does.

For justification, one should look no further than the value of world proved reserves and lesser, yet very significant value of reserves reported to the U.S. Securities and Exchange Commission. At $35/bbl and $5/thousand cubic feet (Mcf), for example, which is significantly lower than fourth quarter 2004 prices, reserves owned by U.S. companies reported to the SEC and investors represent a total value of more than $2 trillion (U.S.). This is a mere 3 percent of worldwide reserves, which are reported in a variety of ways. Inarguably, these staggering values should be estimated in accordance with internationally accepted practices by highly competent evaluators. Evaluator certification is a step in that direction.

Engineers or geologists certified as specialists would be recognized by the administering organization as having advanced skill levels as well as substantial experience in accepted methods. Requirements for accreditation would include prescribed levels of education and special training, experience and job history, knowledge and scoring on certification exams.
Development and Field Application of a Shallow Perforation Shutoff System for HP/HT Oil Wells
Authors: van Eijden J. , Arkesteijn F. , van Batenburg D. , van Vliet J.
Published: December 2007

Water production in a oil field in Syria has increased significantly in recent years. As a result oil production is currently constrained by facilities throughput. PLT surveys combined with a reservoir study on the field showed that some layers still have high hydrocarbon saturation whilst others are already swept by water. Good-quality sands are not properly swept, probably due to poor connectivity in the reservoir. By shutting of the watered-out sands the high oil saturation un-swept sands can contribute to the production. However, no mechanical through tubing technologies are currently available, due to the high expansion ratio, the high differential pressure (up to 3000 psi) and the high temperature of 150 °C.

A new particle-gel has been developed for solving the above-described problem in a cost-effective manner. The particle-gel system is a further development of the previously published gel-cement system.1 The system may be placed via coiled tubing similar to a cement squeeze. The particles in the system will create a diverting filter cake resulting in a uniform and shallow placement of the gel of typically less than 1 inch. The gel used as make up water of the slurry will be squeezed into the matrix creating a shallow matrix shut off after it is set. Selective perforation of the hydrocarbon zones can re-establish the oil production. Additionally, the shut off zones can be re-opened later in the well's life when artificial lift has been installed.

The system showed superior shut off performance in the laboratory compared to normal cement squeeze techniques. In the first field application the system was tested in vertical oil well with a static bottomhole temperature of 146 °C. A total of 186 meters of perforations were squeezed of with the particle-gel in a single attempt. Post-job PLT data confirmed that the shut off was complete because the sealed zone showed no inflow.
Prediction of Skin in Openhole Sand Control Completions
Authors: Jones C. , Tollefsen M. , Somerville J. M. , Hutcheon R.
Published: December 2007

Formation damage in openhole sand control completions comes from a variety of sources. The drill in fluid filtrate can cause near wellbore permeability alteration and in the case of a gravel packed completion, leak off from the gravel pack slurry can increase the damage. Once the gravel is in place, poor filter cake clean up and pack damage can further increase the skin.

Careful design and execution of the gravel pack can result in a low skin. However there is one additional damage mechanism, which is impossible to avoid, that of permeability alteration by rock failure. There is a high probability that rock failure takes place at some stage in the life of an openhole sand control completion and the effect of rock failure on the skin depends on the change in permeability produced by failure and on the completion type.

An objective of this work was to measure the effect of rock failure on permeability for a weak sandstone.

A yield zone model was used to determine the depth of rock failure away from the wellbore and the effective stresses in the yield (failed) zone. The permeability changes were coupled with the yield zone model to predict the evolution of skin during depletion for a variety of completion options. Using the properties for the rocks tested, the model predicts for a compliantly expanded expandable sand screen completion an initially zero or slightly negative skin that increases slightly as depletion proceeds. For a non-compliant screen the model predicts a slightly higher initial skin, which again increases slightly with depletion. The predicted values are commensurate with observed skin values for openhole expandable sand screen completions.
Mud-Induced Formation Damage in Carbonate Reservoirs: Consequences on Productivity of Open-Hole Horizontal Wells
Authors: Al-Taq A. , Bazin B. , Ding D. , Egermann P.
Published: December 2007

An integrated approach including laboratory testing and numerical modeling was used in a study focused on mud-induced formation damage in carbonate open-hole horizontal wells, related to a field application in Saudi Arabia. This approach incorporates (1) evaluation of damage from laboratory flow experiments; (2) interpretation of flow testing results by two-phase flow modeling, and (3) integration of the physical data describing the formation damage into a numerical near-wellbore model for the evaluation of skin value and well productivity.

In the laboratory investigation, drilling and clean-up fluids were applied to two different reservoir core samples representing two classes of permeability. Two cleaning fluids were compared: a conventional mild acid wash and a new product system comprising a retarded acid and an enzyme breaker. Although laboratory testing is helpful for the selection of drilling and clean-up fluid, it cannot be directly used to evaluate well performance. Hence, a numerical model, which takes into account near-wellbore formation damage mechanism and laboratory testing data, is used to estimate potential productivity loss.

The modeling of the lab results shows that the heterogeneity of the cores has a determinant effect on the flow parameters (second drainage). This interpretation of the lab results is fundamental for the well modeling. Well productivity after drilling was evaluated with a dedicated software for Modeling Inflow Performance (MIP). The improvements brought by the new cleaning fluid were evaluated by both laboratory experiments and numerical simulations. The results obtained show comparable skin values between model prediction and field data.
Increase of Accuracy in Determination of Skin-Effect and Perm Thickness Product For Low Permeability Reservoirs
Authors: Diyashev R. N. , Iktissanov V. A.
Published: December 2007

Pressure build-up time upon shutting-in a well depends on filtration parameters of formation, increasing with their impairment. Therefore, incomplete pressure build-up curve for low permeability reservoirs frequently occurs. In this case the segment, offsetting by 1.5 of log cycle from derivative maximum, is not achieved. Interpretation of such pressure build-up curves, using known programs as Pansystem, Saphir, Fekete etc., leads to a significant error. This is confirmed by skin pressure drop with the absolute values considerably exceeding depression, as well as unreal flow efficiency.

In this connection, a method for interpretation of pressure build-up curve has been elaborated, allowing to increase accuracy in determination of formation and bottom-hole zone filtration parameters. This is achieved by combined consideration of wellbore storage and prehistory of filtration using numerical methods. In so doing, knowledge of initially unknown formation pressure and boundaries, on which it is maintained constant, is not required.

The method received wide practical approval for reservoirs with permeability of 0.1-300 mD. The results showed that actual value of perm thickness product, calculated by suggested method, is smaller then by well-known methods. The difference is increasing at short pressure build-up time and also for reservoirs with low perm thickness product. Therefore, the most effect from application of the suggested method is achieved while interpretation of pressure build-up curve with low perm thickness product. The method has also been used to estimate efficiency of different stimulation methods for wells, drilling-in and completion methods in Tatneft JSC fields. Results of interpretation allowed to give practical recommendations on selection of most efficient technologies.
An Experimental and Modeling Investigation of Acid-Created Channels in Sandstone
Authors: Xie T. , Li C. , Pournik M. , Zhu D. , Hill A. D. , DeVine C.
Published: December 2007

Wormholing is a common phenomenon in carbonate acidizing. These macro-sized channels, which are several orders of magnitude larger in diameter than natural pores, provide a magnified flow path, and hence enhance productivity. As the acid mainly attacks the larger pores, acid can penetrate much farther into the formation and bypass the formation damage rather than dissolve it. There is experimental evidence that wormholing on a smaller scale can occur in sandstone formations. The purpose of this study was to determine the treatment conditions and formation characteristics required for such wormholes to be created in sandstone through experimental and modeling work.

We have conducted extended experiments with samples of varying properties at different treatment conditions. Meanwhile, a theoretical model was built to simulate the process and visualize the acid etching pattern in the laboratory core samples. The findings from this study show that there are many parameters that affect the etching pattern. The most important factor that determines etching pattern is the heterogeneity of the rock sample. The spatial variation in permeability, porosity, and mineralogy are the driving force for the acid to channel through certain paths, developing highly permeable channels or wormholes in sandstone. The simulation results show that high permeability channels result when the initial porosity distribution is non-uniform, especially with existence of high porosity streaks. Such wormholes are not likely generated in homogenous rocks, even with an extremely high concentration HF acid solution at a high temperature. Uniform dissolution patterns are created in such samples as supported from our experimental work.
Effect of Natural Fractures on Hydraulic Fracture Propagation
Authors: Potluri N. , Zhu D. , Hill A. D.
Published: December 2007

Various fracture interaction criteria were reviewed and a systematic study is presented to analyze the effect of natural fractures on hydraulic fracture propagation. From the literature review, the approach of Warpinski and Teufel was adopted to evaluat the fracture propagation that would occur after a hydraulic fracture intersects an existing natural fracture. The study determined the conditions of differential stress, angle of intersection, and fracture toughness for which dilation of the natural fracture would occur. Criteria for the subsequent modes of fracture propagation are then presented.
Guando Field: Underpressured-Field Development
Authors: Amaris O. H. V. , de Freitas L. C. S. , Gomes H. P. , Pereira J. R. B.
Published: December 2007

The purpose of this paper is to present the main challenges involved in the Guando field development project, how they were addressed, the lessons learned, and in a more general sense, describe how a severely underpressured, partially naturally fractured reservoir was successfully developed using a phased approach to water injection implementation.

The field appraisal and phased development approach utilized resulted in a technically and commercially successful project, despite the high degree of uncertainty that initially existed.
Application of a Fully Viscosified Scale Squeeze for Improved Placement in Horizontal Wells
Authors: James J. S. , Frigo D. M. , Townsend M. M. , Graham G. M. , Wahid F. , Heath S. M.
Published: December 2007

Nelson is a platform development in the Central North Sea approximately 180km east of Aberdeen, producing 38° API oil from a Forties type reservoir with seawater injection pressure support. The high-salinity formation water contains up to 370 mgl-1 of barium, creating a significant scaling risk to the wells upon sea-water breakthrough. The majority of current wells are highly deviated but several horizontal wells with variable permeability exist, which pose a considerable challenge in terms of scale-squeeze placement. N19z is a horizontal well in the North Central region of the reservoir with a 500m cased/perforated producing interval in which breakthrough of sea-water has been confirmed. The well has previously been squeezed, both non-diverted and diverted with wax beads, each with varying success. Earlier reports have examined the effect of applying lightly viscosified fluids on placement of treatment fluids across long intervals to overcome friction and crossflow effects with the potential to assist in treating zones with permeability contrasts1. This approach was pursued to improve the effectiveness of squeeze treatments in long-reach horizontal wells in Nelson, culminating in the successful squeeze of well N19z with a precipitating inhibitor in which all squeeze stages were viscosified. The paper reviews the advantages of the viscosified approach, reports laboratory testing, compares the performance of the squeeze relative with non-diverted and wax-bead-diverted treatments, and highlights some of the pitfalls in applying fully viscosified treatments in both Nelson and other field horizontal or high permeability contrast wells.
Suggested Modifications to the Reporting Requirements for a Company's Oil and Gas Reserves
Authors: Verbeek G. E. H.
Published: December 2007

The recent restatements by several Oil and Gas companies of their petroleum reserves has created a lot of short-term publicity, but not a fundamental and widespread discussion regarding the process that is followed to determine a company's reserves.

To minimize the chance of reserves misstatements in the future, some have called for the certification of the individuals preparing a company's petroleum reserves or even the use of outside auditors to certify the reserves claimed, much like the certification of the financial reports by an independent auditor.

This paper will review both sides of such an approach, but conclude that a solution in line with the thinking behind the Sarbanes-Oxley regulations governing a company's financial reporting is more appropriate.

However, while this approach clearly defines the responsibility for the reserves estimate, the reporting of this estimate has to be expanded to ensure more transparency. This paper will recommend that the reserves statement uses a set of probabilistic numbers rather than a single deterministic number.

Finally, the objective of this paper is not necessarily to answer all questions surrounding the process to be followed by a company for stating its reserves, but rather to ensure that there is a fundamental discussion regarding that process, and that in the end the methodology is improved in a practical manner that provides added transparency and accountability.
Novel CO2-Emulsified Viscoelastic Surfactant Fracturing Fluid System
Authors: Chen Y. , Pope T. L. , Lee J. C.
Published: December 2007

The solid-free viscoelastic surfactant (VES) fluid has good proppant transport and excellent cleanup capabilities. Coupling the benefits of a VES fluid with a carbon dioxide (CO2)-emulsified system will further enhance cleanup in a depleted reservoir, extend the application to water-sensitive formations, and maintain reservoir gas saturation to prevent any potential water blocks. This paper reports on a new multisurfactant VES fluid system developed specifically to provide a robust surfactant-base fracturing fluid with supercritical CO2. The field test results indicate the new system is CO2 compatible and still possesses all the attributes normally associated with VES systems.
A Mechanistic Model for Formation Damage and Fracture Propagation During Water Injection
Authors: Abou-Sayed A. S. , Zaki K. S. , Wang G. G. , Sarfare M. D.
Published: December 2007

The majority of injectors are likely to be fractured (intentionally or unintentionally) during their life cycles. Assessment of facture conductivity damage and associated surrounding formation damage is an essential step for maximizing and maintaining injector performance during produced water injection for water flooding. Fractured injectors experience less injectivity decline over time in comparison to matrix injectors.

The current paper will present a mechanistic model for the plugged fracture behavior and discuss its applications to field cases. In addition, implications, recommendations and best practices for optimized produced water injection will be addressed within this context.

The well undergoes two distinct processes that alternate over its life to create the sustained injectivity behavior associated with this scheme. Injectivity damage can occur particularly in pseudo-matrix conditions, where a stationary fracture progressively plugs (in addition to permeability impairment of the surrounding reservoir rock), resulting in pressure buildup and injectivity decline. As solids are deposited in the fracture, the "effective" exposed surface area is gradually reduced, at least partially, as a function of the injected amount of solids. Furthermore, fracture face damage (external filter cake build-up) and accumulated surrounding formation damage (internal filter cake build-up) progress as the volume of injected water increases. This plugging process continues until the injection pressure required for the designated injection rate reaches a critical value, which is greater than the pressure required to re-fracture the formation and/or to extend or propagate the plugged fracture. At such pressure a sudden fracture propagation or further breakdown of the formation is evidenced by a sudden increase in the Injectivity Index or similarly, a sudden drop in the Reciprocal Injectivity Index – RII - (unit injection pressure per unit constant injection rate). Thereafter, the required pumping pressure drops and/or the injection rate increases with the newly created surface area that has been caused by fracture propagation or initiation. The process then repeats itself. As the pressure rises it approaches and finally exceeds the fracture pressure required for further propagation, resulting in a saw-toothed shape pressure-time (or rate-time) behavior. The slopes of the bounding lines are controlled by the damaged formation and fracture characteristics, as well as the injected water quality. The slopes can be made to diverge, converge or remain almost parallel. The third option indicates a well optimized injection scheme.

The final section of this paper will imply lessons learned, mitigation strategies, conclusions and recommendations based on analyses of field data from a number of produced water injectors. Pressure transient analysis and results from pressure fall-off test will be presented to verify the study results.
Maximizing Inflow Performance in Soft Sand Completions Using New One-Trip Sand Control Liner Completion Technology
Authors: McElfresh P. , Williams C. , Garfield G.
Published: December 2007

Maximizing inflow performance for any completion involves balancing the natural forces of the reservoir with the operational limitations of the well or field. In the case of soft or unconsolidated sand, completion procedures often dictate equipment or procedures that can potentially limit the inflow area by way of various forms of formation damage. There are three major types of formation damage: the filter cake and fluid loss damage associated with drilling; the skin increase due to compaction and debris associated with perforating; and, the skin added to the completion by the gravel or frac pack. While there are treatments that can remove or reduce the effects of damage, all of them involve subsequent intervention into the well, which elevates risk and as increases rig time. This paper discusses a recently developed one-trip completion system that has been successfully used to eliminate or reduce these causes of formation damage and improve inflow area and performance.

This new system provides a means of deploying a production liner, perforating, primary cementing, removing filter cake, and controlling sand production in a single trip. The one trip system is especially beneficial in wells needing sand control. The procedure utilizes a telescoping conduit that can be expanded hydraulically, mechanically, or both, to seal onto the formation face. The conduit is then cemented into place. The sand control media is inside the telescoping conduit in the form of appropriately sized stainless steel beads. The damage typically associated with the perforating phase is eliminated because there is no explosive discharge during the deployment of the system, and the well is brought on production normally. Studies have shown that decreasing initial perforation damage results in a more productive well over its lifetime. This new completion method also eliminates gravel packing, minimizes the amount of intervention into the well completion, and saves substantial rig time due to its one trip operation. Additionally, the authors will illustrate how the new completion simplifies operational logistics, especially in remote or offshore environments, because it is not dependent on large fluid pumping treatments nor does it require excessive pumping horsepower.
Simple Thermal Efficiency Parameter as an Economic Indicator for SAGD Performance
Authors: Shin H. , Polikar M.
Published: December 2007

A new economic indicator, called simple thermal efficiency parameter (STEP), was developed to evaluate the performance of a SAGD project. STEP is based on CSOR, CDOR and RF for the time corresponding to SOR = 4. STEP was found to be a useful quantitative economic criterion, with a value of 1 for an economic case (CSOR of 3, CDOR of 0.111 m3/d/m of horizontal well length and RF of 0.5).

To validate this new economic indicator, STEP was calculated based on data from two published studies in which SAGD related simulations were performed. The first study, which provides no economic parameters, shows that most of the optimal cases always have the highest STEP values. The second study, which provides economic parameters (ROR and NPV), shows a good linear relationship between ROR and STEP. STEP is greater than 2 in the case of the economic SAGD scenarios.

This study has validated the usefulness of STEP as an economic indicator. STEP can be used as a financial metric quantitatively as well as qualitatively for this type of thermal project.
External Filter Cake Erosion: Mathematical Model and Experimental Study
Authors: Al-Abduwani F. A. H. , Bedrikovetsky P. , Farajzadeh R. , van den Broek W. M. G. T. , Currie P. K.
Published: December 2007

In this article a system of equation to describe the steady state external filter cake thickness profile along the cuboid crossflow filtration setup geometry as well as the well bore geometry are introduced. The first equation is obtained from the analysis of forces acting on a deposited particle at the outermost limit of the external cake. The second equation is obtained from the volume conversation of the transporting fluid in the given geometry. Coupling the two equations yields an implicit solution of the cake profile. Boundary conditions are required as well as the quantification of an empirical factor that can be quantified experimentally.

Experiments conducted were analysed and the empirical friction coefficient was quantified and presented. Simulations based on the developed solution are also presented.
Analysis of the Performance of Hydraulic Fracturing Treatments and Quantum Design Improvements
Authors: Demarchos A. S. , Economides M. J. , Diyashev I. , Svaykin V. A.
Published: December 2007

Hydraulic fracturing has emerged as the compelling completion and stimulation procedure in Russian petroleum production credited to a large extent for the impressive production enhancement experienced in the last several years. We present in this paper approximately one thousand hydraulic fracturing jobs from Western Siberia and their performance is analyzed and compared with design and execution variables.

The well performance is measured through, among other things, the actual, field-derived, dimensionless productivity index (JD) and is compared against our concept of Unified Fracture Design (UFD) which has been used to physically optimize and maximize the productivity index from a hydraulic fracture treatment. We have demonstrated in the past that for a given mass of proppant there is a specific dimensionless fracture conductivity, which we called the optimum, at which the JD becomes maximum. The Proppant Number is a seminal quantity unifying the propped fracture and the drainage volumes and the two permeabilities, those of the proppant pack and the reservoir.

One of the important observations of our analysis is that the distributions of the achieved JD follow the theoretical curves, however there is a gap between the theoretically achievable and actually achieved JD. We evaluated the gap and identified measures to improve our fracture designs.

Conventional fracture designs can be extended considerably by injecting large proppant masses with far better proppant-pack permeabilities within reasonable field and logistical constraints. It is against these two concepts, the desired optimum fracture conductivity for the injected fracture size, and the would-be "pushing the limits," design that we compare the already executed treatments. We provide critique and offer suggestions for design improvements.
Investigation of a Novel Chemical for Bullhead Water Shutoff Treatments
Authors: Elewaut K. , Stavland A. , Zaitoun A. , Krilov Z. , Zitha P. L. J.
Published: December 2007

Traditionally bullhead water control consists of the placement of water-soluble chemicals without mechanically isolating oil layers. In order to be successful, bullhead treatments should block water-bearing layers without affecting the permeability of the oil-bearing layers too much. This paper reports an experimental investigation of an innovative water shutoff chemical deemed suitable to accomplish this task. The chemical is soluble in oil without any reaction, and is transferred into and reacts with water to form a stable gel. Core flow experiments consisting mostly of the injection of either oil or water in cores containing the chemical dissolved in oil were performed to investigate the ability of the gel to reduce water permeability while maintaining oil permeability. To ensure that the results are relevant for designing field applications, the experiments were performed under conditions encountered in various sandstone reservoirs in the North Sea, Croatia and other regions. Permeabilities and temperature ranging from 100 to 300 mD and 70-900C were therefore considered in this study. The influence of the other physical parameters, such as viscosity, concentration of active chemical in oil chemical, injection rate, etc., was also investigated.
Impact of Intelligent Well Systems on Total Economics of Field Development
Authors: Sakowski S. A. , Anderson A. , Furui K.
Published: December 2007

Intelligent well technology, referring to the implementation of fundamental process control downhole, has advanced rapidly over the last decade in the upstream oil and gas industry. Application of this technology has continued to expand since recent installation results have demonstrated the value of these completions with a high success rate that operators find attractive.

In this paper, we present an economic evaluation procedure to quantify the benefit of Intelligent Well Systems based on net present value (NPV) calculations. Reducing well count and eliminating or reducing interventions by using Intelligent Well Systems has the potential to add many millions of dollars to well NPV, since drilling rig and workover costs may be very expensive, especially in offshore deepwater environments. Delayed revenue associated with production shut-in also must be considered and reduced by discount rate at the same time that intervention and well operating costs increase by inflation rate.

The use of Intelligent Well Systems not only reduces or eliminates some capital and operating costs, but also allows operators to accelerate oil production, increase the ultimate recovery and reduce water handling cost, which result in significant benefits in NPV of a project. Thus, Intelligent Well Systems are becoming economically attractive for modest-cost onshore operations as well as for the high-cost offshore environments for which they were initially deemed applicable.
Visualization and Interactive Filtering of Strategy Driven Portfolios as an Alternative to LP Optimization
Authors: Rasey S. M.
Published: December 2007

Linear Programming approaches to Portfolio Optimization require much effort to "teach the computer" the Petroleum Business. We must described to the optimization program the costs, potential rewards, and uncertainties of every investment opportunity. For an optimizer to generate realistic, executable, investment programs, we must also encode constraints that define the strategic and geologic dependencies between investments, the timing flexibility that exists within and between each opportunity, the working interests that exist or can be negotiated, and their competition for scarce resources such as rigs, people, and partners’ approvals. Strategy gets encoded as portfolio goals to be met.

Perhaps we can employ this effort more effectively. We ought not search for one magical optimum portfolio dependent upon one strategy masquerading as thousands of LP constraints.

This paper describes a portfolio analysis process that quickly creates near optimum executable portfolios on each of thousands of strategies and portfolio value criteria. Each portfolio and its measures, including confidence curves, accumulate in a database. We use laptop-capable visualization software to display and compare the portfolios on dozens of performance measures. Using interactive filtering we can apply portfolio goals and resource constraints to the cloud of portfolios quickly narrowing down to a few portfolios that meet all our criteria. Finally, from these best portfolios we learn which opportunities are funded in all, most, some, or none of the final portfolios. In the end, this is the information we seek: what are the smart investment decisions to make, not which one portfolio we should execute.

Businesses who adopt this process benefit several ways: 1. Using interactive filtering to apply constraints means you can change resource levels very late in the process. 2. You can better set goals and negotiate resources after seeing beneficial potential trade-offs between portfolio measures. 3. You define your constraints using the measures of total portfolio performance you save to the database, including nonlinear measures from uncertainty distributions. This way is easy to apply constraints such as "P90 of NPV >= 500" or "Number of Funded Projects <= 30"; constraints which are impossible with linear programming.