bluuebunny/crossref_metadata_2025 huggingface dataset:
Downhole Capillary Surfactant Injection System Pilot on Low Pressure Gas Wells in the San Juan Basin
Authors: McWilliams J. P. , Gonzales D.
Published: December 2007

Depletion of the reservoirs in the San Juan Basin is causing production rates to drop below the minimum lift critical velocity (MCV) in a large number of wells.Traditional methods used to address this issue include plunger lift, pumping units, foam lift, and re-circulation for wells with a compressor and tubing.With declining reservoir pressures, both plunger lift and re-circulation become less effective and often times the expense of a pumping unit, both to purchase and operate, cannot be economically supported by the well.In some cases, injecting surfactant may offer the most cost effective method of removing fluids.

To date, foam lift operations in the San Juan Basin have been accomplished by two methods.The most common method of applying surfactant to a well is dropping "soap sticks." This is very inexpensive but it demands a large amount of time from field personnel and can yield inconsistent production rates.The other common method of delivering surfactant to the well is through continuous injection of surfactant at the wellhead.The major problem with this method is that surfactant must drip down the annulus or tubing, which limits its effectiveness due to plating out on the wall surface.

The problems described above are eliminated through the use of a Downhole Capillary Surfactant Injection System (DCSIS).The DCSIS delivers surfactant directly to the bottom of the well bore where it is needed to be effective.A capillary stainless steel tubing string is run in the well bore and is attached to a fluid pump and a chemical storage tank.The capillary string can be run inside the tubing, outside the tubing, or down the slim hole production casing.Once installed, a metered amount of surfactant is injected down hole to help unload the well.

This paper discusses the results of a 10-well pilot of the DCSIS in the San Juan Basin.The pilot's objective was to determine the physical parameters necessary to estimate the MCV for foam flow and establish better criteria for selecting future installations.To accomplish these objectives, it was necessary to analyze the positive and negative responses to the installation of the DCSIS and determine the factors that led to each response.The data was then analyzed using statistical modeling tools to determine the most important factors affecting the response variable, percent increase in production (% uplift).This paper will discuss the results of a regression model that was built to determine the significance of several factors and to aid in the candidate selection process for future installations.Practical methods of determining the physical parameters necessary to generate foam flow will also be presented.
Casing Burst Strength After Casing Wear
Authors: Wu J. , Zhang M. G.
Published: December 2007

Casing wear by drillstring results in a thinner portion of casing wall and a reduction on casing burst strength (the ability to hold internal pressure). How to estimate the reduced casing burst strength on such a "crescent-worn" casing has been an important issue in oil and gas industry, as it is directly related to how to safely design casing strings. A common approach is to estimate the reduction of casing burst strength of such worn casing from API burst strength equation with a linear reduction by the remaining wall thickness or the wear percentage, equivalent to a "uniform-worn" casing model, despite a question on whether such a linear reduction of casing burst strength is over-conservative and may result in a higher casing cost.

This paper presents a further study on hoop stress and deformation of such a "crescent-worn" casing and discusses the reduction of casing burst strength. The hoop stress in the thinner portion of such a "crescent-worn" casing is found close to that from a "uniform-worn" casing, when local bending in the thinner portion of "crescent-worn" casing is ignored. The reduction of burst strength of casing worn by drillstring may still be estimated from casing yield or rupture burst strength with a linear reduction by wear percentage for sweet service well conditions, while more and non-linear reduction of burst strength of casing worn by drillstring may be needed for sour service well conditions, to prevent an "earlier" casing burst on sulfide stress cracking.
Extending Commercial Viability Through Near-Real-Time Cost Control and Operations Optimization
Authors: Doyle R. , Ippolito J.
Published: December 2007

Although conventional wisdom might suggest otherwise, mature fields represent a significant source of potential value. Operators can tap into this value by concentrating their efforts in three key areas: ensuring safe operations, minimizing operating costs, and maximizing current production. This paper examines specific instances in which fit-for-purpose work processes, technology, and training have been utilized to create value for operators of mature fields by optimizing safety programs, procurement processes, and other operations activities that affect each of the three key areas.
Horizontal-Well Productivity and Wellbore-Pressure Behavior Incorporating Wellbore Hydraulics
Authors: Anklam E. G. , Wiggins M. L.
Published: December 2007

Horizontal well performance is typically estimated using a steady-state productivity index equation similar to Joshi's productivity index, which assumes constant wellbore pressure. The wellbore pressure in a horizontal well is not constant, and the pressure drop in the horizontal section can approach the reservoir drawdown. This paper presents a new model to estimate horizontal well productivity by incorporating wellbore hydraulics. The model is implemented in a program and calculates the well pressure throughout the length of the wellbore. The method reproduces the experimental results of two authors.
A Look at Seabed Environmental Monitoring for Trinidad and Tobago's First Deepwater Drilling Campaign
Authors: Rajnauth J. , Boodoo C. , Dwarkah D.
Published: December 2007

Several dry-hole wells drilled during the period 1999 to 2003 was the outcome of deepwater drilling to date in Trinidad and Tobago. One of the objectives though of the deepwater drilling phase was to monitor the seabed to assess the fate and effects of discharged cuttings at the drill-site locations.

A monitoring plan was prepared by the operators to assess the amount, extent and effect of synthetic cuttings depositions. These effects include toxicity, water column effects and whether synthetic based muds bio-accumulate or biodegrade. Synthetic based mud is frequently used in deepwater drilling to assist in difficult drilling situations such as well bore stability, high temperatures and pressure, hydrate formation prevention and drilling time reduction. Computer model predictions were done on synthetic based mud cuttings deposition. The monitoring program includes video surveys, using sedimentary gauges and sedimentary traps.

The focus of this paper will be to look at and assess the monitoring plan, discuss the results from the monitoring surveys and compare with computer model predictions.
Controls On Soap Scale Formation, Including Naphthenate Soaps — Drivers and Mitigation
Authors: Turner M. S. , Smith P. C.
Published: December 2007

Soap deposits, which can manifest as emulsion soaps (carboxylates) or hard deposits (naphthenates), are an increasingly recognized cause of some unique flow assurance and crude marketing problems in oilfield processes. This paper illustrates the physical and chemical drivers for the generation of soap scales in a number of differing and challenging production system environments. Mitigation options for the successful treatment of soap scales are also discussed. Where possible, data presented in this paper are taken from field trials in order to illustrate these drivers and the impact of successful mitigation strategies.

An understanding of the key fluid characteristics allows pre-screening of fluids from new field developments that are likely to develop naphthenate/soap deposits and allows diagnosis of the likely soap scaling problems. The critical fluid characteristics required for the generation of naphthenate soaps are different from those required for generation of carboxylate soaps. An empirical approach to predicting the degree of risk for soap generation, based on oil and produced water properties, can be adopted, although there are knowledge and data gaps that increase the uncertainty of this approach.

Physical parameters, such as pressure, are known to influence soap generation. However, other physical parameters that are key in the design and operation of an oil-field process can also influence the soap severity. These parameters include temperature, shear, electrostatic fields, water cut and fluid-fluid incompatibility; examples of each are discussed. This information can be used in the design stages of an oil-field process where engineers must think beyond the conventional process designs.

Despite the fact that the impact of a soap problem can be considerably reduced by adjustment of physical design and operating parameters, chemicals are usually required to provide complete mitigation of soap. Chemical mitigation (acid and non-acid) guidelines are discussed with field examples and the need for a chemical management and monitoring programme.
Taking Coiled-Tubing Heave Compensation to the Next Level
Authors: Patton B. , Escobar J. C. , Schuurman R. , Mallalieu R. , Polsky Y.
Published: December 2007

As the number of deepwater installations increase, so will the number of coiled-tubing (CT) operations that are needed to support these deepwater fields. This need will grow significantly as rigs on spar platforms and tension leg platforms (TLP) are eventually demobilized for work on new installations, leaving CT as the most economical option for performing future well maintenance on these platforms.

The need to operate without a rig is a critical factor in the success of future coiled-tubing work in the deepwater environment. Rigless operation is complicated by the fact that each platform type has its own unique heave-compensation issues that must be addressed for an effective CT operation to take place.

An additional challenge to deepwater CT operations has been the assembly and installation of tension lift frames or heave-compensated jacking frames. This equipment is typically cumbersome and time-consuming to install and has many safety-related risks associated with the installation of coiled-tubing components.

A new coiled-tubing heave-compensation system has been created to address issues associated with rigging up and operating coiled tubing on deepwater installations. This system was designed with particular focus on operational safety and efficiency to meet the complete range of floating platform coiled-tubing deployment scenarios. There are three primary modes of operation. As a stand-alone system, it can operate as a heave-compensated jacking frame; with a rig, it can operate as a standard tension lift frame or as a self-compensating tension lift frame. The adaptive heave-compensation system uses automated process control to maintain wellhead loads within the American Petroleum Institute-specified allowable stress limits. A specially designed proprietary titanium flex joint incorporated in the system reduces the effect of lateral loads and bending moments transmitted to the wellhead.

The total heave-compensation package is composed of three skids (injector tension frame, blowout preventer (BOP) tension frame, and hydraulic power unit). The injector, gooseneck, and all well control equipment come preassembled within the injector and BOP tension frames. This improves the overall efficiency of the rig-up and eliminates most safety issues associated with the rig-up/rig-down process. The heave-compensation system not only improves the efficiency of the rig-up process but also makes tool changeouts more efficient.

The initial field test data and the associated job case history establish the benefit that this new heave-compensation system has brought to the deepwater market.
Predicting the location of barium sulfate scale formation in production systems
Authors: Collins I. R.
Published: December 2007

Mineral scale formation and deposition on downhole and surface equipment is a major source of cost and reduced production to the oil industry. This paper describes a novel semi-quantitative kinetic approach to predicting the location of barium sulfate formation and deposition. The key conclusions of this work are: There is probably negligible formation damage arising from barium sulfate deposition in the near well bore region.There are three kinds of barium sulfate precipitation in the well depending upon the scaling tendency (saturation ratio) in the produced brine (it is assumed that the higher saturation ratio values for barite at the bottom of the well is a consequence of mixing of high sulfate brine from sea water breakthrough with high barium brine formation water). The location of the scale formation can be predicted from knowledge of the nucleation induction time coupled with mass transfer arguments. The equations describing these have been developed in this paper and applied to some general illustrative cases demonstrating the applicability of the approach. In particular, a method has been developed for predicting the location of scale formation and deposition at low saturation ratios such as developed when sulfate-removal is utilized as a barite scale control technology.
Quantifying Greenhouse Gas Emission Reductions from Enhanced Oil Recovery Operations
Authors: Loreti C. P. , Grygar W. W.
Published: December 2007

Enhanced oil recovery (EOR) has been identified as a promising way of sequestering carbon dioxide (CO2). When CO2 that would otherwise be vented to the atmosphere is used in the process, the CO2 remaining in the ground represents a reduction in greenhouse gas (GHG) emissions.

The accurate quantification of the amount of CO2 sequestered is important as companies look to market the emission reductions associated with EOR operations. Purchasers of emission reductions need assurance that the reductions they are purchasing are real. Often, however, losses of CO2 and methane (CH4) during the operation of EOR projects are not fully considered in accounting for the emission reductions. While minor fugitive losses of CO2 may be accounted for, much larger losses that may occur as a result of the way equipment is configured or how facilities are operated are often ignored.

This paper presents a methodology for quantifying the net greenhouse GHG emission reductions resulting from enhanced oil recovery operations based on the observation of a range of operating facilities. It demonstrates the need to consider the operational aspects of the production facilities in quantifying the amount of GHG emission reductions. It concludes that losses of CO2 and CH4 in EOR operations may be large enough that unless they are fully considered, the magnitude of any claimed emission reductions may be subject to question.
Increased Access to Federal Lands through Data Sharing
Authors: Belieu S. D. , Jehn P. J. , Bohrer M. F.
Published: December 2007

Much of the environmental and technical data useful to the oil and gas industry and regulatory agencies is now contained in disparate state and federal databases. Delays in coordinating permit approvals between federal and state agencies translate into increased operational costs and stresses for the oil and gas industry. Making federal lease stipulation and area restriction data available on state agency Web sites will streamline a potential lessors review of available leases, encourage more active bidding on unleased federal lands, and give third-party operators independent access to data who otherwise may not have access to lease restrictions and other environmental data.

As a requirement of the Energy Policy Conservation Act (EPCA), the Bureau of Land Management (BLM) is in the process of inventorying oil and natural gas resources beneath onshore federal lands and the extent and nature of any stipulation, restrictions, or impediments to the development of these resources.

The EPCA Phase 1 Inventory resulted in a collection of GIS coverage files organized according to numerous lease stipulation reference codes. Meanwhile, state agencies also collect millions of data elements concerning oil and gas operations. Much of the oil and gas data nationwide is catalogued in the Ground Water Protection Council's (GWPC's) successfully completed Risk Based Data Management System (RBDMS).

The GWPC and the states of Colorado, New Mexico, Utah, and Montana are implementing a pilot project where BLM lease stipulation data and RBDMS data will be displayed in a GIS format on the Internet. This increased access to data will increase bid activity, help expedite permitting, and encourage exploration on federal lands.

Linking environmental, lease stipulation, and resource inventory assessment data and making a GIS interface for the data available to industry and other agencies via the internet represents an important step in the GWPC strategy for all oil and gas regulatory e-commerce. The next step beyond mere data sharing for facilitating the permitting process is to make it possible for industry to file those permit applications electronically. This process will involve the use of common XML schemas.

This paper describes the coordinated effort being undertaken by the member states of GWPC, BLM, POSC (Petrotechnical Open Standards Consortium), MMS (Mineral Management Service), and others to make this effort a reality.
Optimize Separator Operating Pressures to Reduce Flash Losses
Authors: Boyer B. E. , O'Connell S. C.
Published: December 2007

Flashing losses from crude oil and condensate storage are routinely vented to the atmosphere. By minimizing operating pressure of low-pressure separators, the amount of flashing losses can be reduced, resulting in increased profits at a minimal cost of implementation and an immediate payback. Companies can be report these methane reductions to the Environmental Protection Agency's Natural Gas STAR Program. Devon Energy realized savings of approximately $7000 per year after separator optimization at one of its oil and gas production facilities.
Accurate Wellbore Placement Using a Novel Extra Deep Resistivity Service
Authors: Helgesen T. B. , Meyer W. H. , Thorsen A. K. , Baule A. , Ronning K. J. , Iversen M.
Published: December 2007

The Grane field causes significant challenges with respect to reservoir drainage and wellbore placement. The true resistivity profiles from offset wells are reflecting an irregular oil water transition zone in the field, likely to be caused by subtle facies variations and/or local variations in the oil water contact(OWC). In addition, horizontal wells penetrated many shales.

Baker Hughes INTEQ has in collaboration with Hydro developed an extra deep resistivity service called DeepTrak™ to navigate at a distance of up to 12 meters from a resistivity contrast boundary. This service has been used in several wells.

The tools as well as the surface software components provided full service capability and were used successfully to geosteer along the OWC at the required distance. In addition, the DeepTrak service was capable of detecting shale injectites, thus giving valuable insight for reservoir characterization and geological model update.

By use of field data, it is demonstrated how the DeepTrak service can be used for accurate wellbore placement.
Offshore California Facility Decommissioning: Past, Present, Future
Authors: Mount P. B. , Voskanian M.
Published: December 2007

Decommissioning of offshore oil and gas production facilities in California has always been and will continue to be a controversial and hotly debated topic. This Decommissioning has been occurring since the early part of the 20th Century and most recently involved four offshore platforms, a pier, and an island in State waters. It also involved the abandonment of over 23 sub sea wells and associated debris off the Santa Barbara, California Coast. Much was learned from these many decommissioning projects, and organizations were formed to coordinate future decommissioning projects and discuss alternatives. This presentation will summarize the lessons learned from past decommissioning projects, future projects and options available for future projects. There will be a discussion on the positions of the public, environmental communities and government on the approval process, facility removal process and final disposition of the facility. Focus of the presentation will be on the process that could be used to develop viable decommissioning options.
A Project Lifecycle Approach to an Effective and Value Added Social, Environmental, and Health Impact Management Process
Authors: Finney R. , Witchalls B.
Published: December 2007

Integrated environmental and social assessment is increasingly becoming part of national regulatory approval processes, to estimate and manage the impacts of oilfield developments upon the natural and human environment. Even at pre-project stages, the Environmental and Social Impact Assessment (ESIA) can form part of the company decision-making process for country entry. The ESIA should not be viewed however simply as a regulatory ‘tick-in-the-box’ but form part of a larger Environmental and Social Management Process. Effective integration of the ESIA findings, into the engineering design process can deliver benefits in impact mitigation and environmental management across all stages of the development.

The international community is demanding increasingly rigorous environmental and social performance of planned developments by international operators and reputation can be strongly influenced by the consistency and quality of the assessment process and the extent to which ESIA commitments are delivered. It is recognised by the International Association of Oil & Gas Producers (OGP) that sharing of experience through ‘lessons-learned’ would provide a means to achieve consistency in delivery of high quality environmental and social impact management processes.

The OGP ESIA in Projects Taskforce has been formed to develop industry guidance, which is applicable to development projects in any geographical area, thus facilitating the attainment of a consistently high standard by all operators, which is aligned with international expectations. The aim is to add both technical value and to facilitate interactions with stakeholders and third parties. Given the diversity of project specifics, company internal processes, local environmental sensitivities etc. The approach must offer a high degree of flexibility in its application. A ‘Toolbox’ based on agreed ‘good practice’ is being assembled that maps key environmental and social management activities with E&P project activities, defining deliverables and checklists at each stage. This is seen to offer greater potential than a more rigid process.
The State Review Process, Improving Environmental Performance through Multiple Stakeholder Program Reviews
Authors: Erb J. E. , Stewart T. E.
Published: December 2007

State Review of Oil and Natural Gas Environmental Regulations, Inc. (STRONGER) was formed in 1999 as a non-profit, multi-stakeholder organization to reinvigorate and carry forward the State Review Process, begun cooperatively by the U.S. Environmental Protection Agency (EPA) and the Interstate Oil and Gas Compact Commission (IOGCC) in 1988. The State Review Process is unique in federal environmental regulation. Rather than develop a traditional prescriptive, command-and-control federal regulatory program, the EPA enabled the states, the regulated community and other stakeholders to develop, through consensus, a set of state oil and gas regulatory program guidelines, and a process for evaluating state oil and gas regulatory programs against the guidelines.
Upstream Onshore Oil and Gas Fatalities: A Review of OSHA’s Database and Strategic Direction for Reducing Fatal Incidents
Authors: Curlee C. K. , Brouillard S. J. , Marshall M. L. , Knode T. L. , Smith S. L.
Published: December 2007

According to the OSHA database for the period from 1997 through 2003, one fatality occurred every 10 days in the U.S. upstream (E&P) oil and gas industry. To determine trends and provide insights into the safety failures, as well as potential interventions to eliminate the high frequency of fatal incidents, the seven years of OSHA data were reviewed. This data encompasses over 250 fatalities from the four principal SIC categories that comprise the onshore upstream oil & gas exploration and production industry. Data were sorted initially by region, well drilling or field servicing, rig type, and event. Further analysis was conducted by a diverse team of industry professionals, including representatives from operating companies, well drilling and servicing companies, and industry trade associations. Particular focus was directed at accident type, equipment type and well site location in an attempt to identify causal factors from the limited incident descriptions contained in the OSHA database.

The resulting analysis showed nearly half of all fatalities (47%) resulted from "struck by" incidents; fires and explosions accounted for 16% while falls from heights accounted for another 14% of the fatalities. Fatality incident rates from year to year were strongly correlated to overall upstream industry activity level as represented by the U.S. rig count.

This fatality data review provides oil and gas industry operating managers, safety professionals, trade associations and others a road map for targeted improvement programs and priorities for reducing onshore oil field-related fatalities.
Discussion of Foam Corrosion Inhibition in Air Foam Drilling
Authors: Meng Y. , Wan L. , Chen X. , Chen G. , Yang L. , Wang J.
Published: December 2007

Simulating corrosion condition of air foam drilling, corrosion inhibition performance and foaming properties of stable foam are evaluated. Corrosion product layer images and composites are investigated by scanning electron microscope, energy dispersion spectrometer and x-ray diffraction analysis. The results show that corrosion pitting with sodium chloride crystalline grain forms on the surface of steel corroded by formation water. Foam can retard corrosion, particles in foam uniformity, thinness and tightness. After adding foam and inhibitor no obvious corrosion phenomenon happens but existing tiny trace originating from washing and erosion. Foam corrosion inhibition mechanism is first put forward through laboratory data and theoretical analysis, which mostly consists in foam agent absorption on steel surface; viscosifier complexing characteristic; oxygen isolation; foam enwrapping sands, reducing erosion. Adding inhibitor and oxygen scavenger, foam corrosion inhibition ability is improved further. Indoor experiment and field application show foam drilling substituting for dry air drilling and adjusting pH value and adding inhibitor reduce sharply corrosion of drilling tools. Special formula in Western Gasfield of China X-14 well is 2.0%F4 +0.3%HPAM + 0.2%XC + 0.5%CT2 + 0.05%Na2SO3. Practice proved that this method effectively restrained drilling tools corrosion and improved economic benefits.

This paper is the first in a series of studies designed to bring forward foam corrosion inhibition in air foam drilling. The goal is to better understand the mechanism of foam corrosion inhibition, to be able to select the proper inhibitor and extend air foam drilling techniques in suit region.
The Need to Have an Energy Literate Public and Consumer Base. How the Energy Industry has (or has not) Dealt with its Image.
Authors: Tobin J. C.
Published: December 2007

abstract

This past summer, Eve Sprunt, SPE President Elect, faced the on going issue of the industry's image while on a business trip to Southeast Asia. People view the petroleum industry as a sunset industry. They have heard predicitions that oil production will peak in the next decade or so and fear that someone entering the industry today will have their career cut short by the lack of resources.

Our image, among many other things, makes this industry an easy target for arbitrary and volatile taxation and regulation, etc. This is old news as the problem has been around for the petroleum segment of the industry since Titusville, and for the energy industry in general since mankind first discovered fire.

Dealing with depleting resources has always been a part of our business. It is dealing with the problem of depleting human resources that is a more recent phenomenon.
Shallow Gas Shut-Off Using Rigid Polymer Gel in Lake Maracaibo, Venezuela
Authors: Hurtado J. F. , Milne A. , Olivares E.
Published: December 2007

This paper describes the application of a rigid polymer gel to shut off potential gas-bearing zones in an openhole section located below a surface casing shoe in Lake Maracaibo, Venezuela. The objective was to minimize the risk of shallow gas influx during continued conventional drilling operations.
Balanced Scorecard Linked to Shareholder Value: Making the Numbers Count
Authors: Schuyler J.
Published: December 2007

The "balanced scorecard" (BSC), popularized by Kaplan and Norton, has become widely recognized both as a performance measuring vehicle and as a strategy communications tool. Typically, 20 to 25 measures (performance drivers and/or indicators) are chosen for the BSC—to align people, processes and investments with the company's strategy. New "dashboard" type software enables an attractive BSC presentation. Because of data accessibility, BSC measurements are almost universally historical or current data.

More importantly than lag measures, what decision-makers need are forecasts. And credible forecasts are generated from a Monte Carlo simulation of the company, industry, and economic environment. The BSC process merges "management by objectives" with the "system dynamics" modeling approach. System dynamics offers the best process for enterprise modeling, yet this link is generally missing from BSC implementations. The stochastic company model is also the means for optimizing the asset and project portfolios and for tuning investment decision policy.

Most corporate executives acknowledge that the sole or overarching objective is maximizing long-term shareholder value. This paper describes an approach for incorporating shareholder value and related key forecasts into the BSC. Share value is approximated by forecasting the company's free cash flow with the company model.

Resolving the discount to get from expected monetary value to market capitalization presents some interesting issues. Share value is tracked and forecast, so people in the company can answer, "Are we creating or destroying shareholder value?"
Investigation of Flow-Back Properties of Various Drilling and Completion Fluids Through Production Screens
Authors: Taugbøl K. , Svanes G. , Svanes K. , Omland T. H. , Alterås E. , Mathisen A. M.
Published: December 2007

A unique test configuration has been utilized to investigate the flow-back properties of oil-based fluids through sand screens for openhole completions after 1-2 months suspension time. This test which simulates downhole conditions can be used to select fluid in which the screens will be suspended.

The results from the testing show that oil-based fluid with a density greater than 1.5 sg can plug the sand screen if suspended for a long period. The results show the effect of both time and temperature on the plugging tendencies. Increased temperature and time increases the risks of plugging. The use of low-solids oil-based fluid has proven to reduce the probability of plugging and will be recommended at higher fluid densities.

This paper will outline the test set-up as well as present the findings from running more than 50 different tests on different fluids. These fluids include conventional oil-based and low-solids oil-based drilling fluids at varying densities tested at temperatures from 95 to 175°C.
Investigation of Reactive Transport Phenomena for Modification of Two-Phase Flow Using NMR
Authors: Castelijns H. J. , Pel L. , Huinink H. P. , Zitha P. L. J.
Published: December 2007

Water control in oil and gas wells is crucially needed in many oil and gas producing wells. Recent studies have indicated that chemicals, that are soluble in oil without a chemical reaction but react and form gels upon contact with water, may block water-bearing zones with little risk of damaging the oil-bearing zones. The chemical is initially mixed with oil. The gelation process involves the partitioning of the chemical out of the oil phase into the water phase. A heterogeneous reaction occurs (hydrolysis and condensation) between gelant and water, leading ultimately to gelation. The aim of this study is to gain greater insight into the coupled mass transfer and gelation process both in bulk and in porous media. We use Nuclear Magnetic Resonance (NMR) imaging techniques to conduct both qualitative and quantitative analyses. The discrimination between the chemical components is mainly based on relaxation times T1 and T2. Bulk measurements are performed to study the mass transfer-reaction mechanisms in an idealized setting. Mass transfer rates and gelation times are estimated as functions of physical parameters (temperature, concentrations etc.). The chemical is then applied in idealized porous media (glass bead packs) containing two phases. Highresolution images are used to reveal the reaction-mass transfer phenomena on the (macro-) pore scale. The results prove to be very promising for further investigations with the NMR methods.
Going Beyond the Efficient Frontier Analysis Using an Integrated Portfolio Management Approach
Authors: Erdogan M. , Mudford B. , Davis C. T. , Stegemeier D.
Published: December 2007

Proposal

The main focus of most portfolio optimization tools in the E&P industry is to determine the efficient frontier by defining risk and return measures and then selecting one of the portfolios along the curve as the most appropriate portfolio for a given set of conditions for the company. While it is critical to determine the efficient frontier, this paper proposes that defining other boundaries to all feasible portfolios and establishing a solution space or envelope rather than a point on the efficient frontier curve is both beneficial and practical. This approach provides decision makers an opportunity to test multiple strategies and to analyze the impact of competing goals and constraints in a more representative environment.

The paper emphasizes that creation of this more complete, representative environment requires an integrated portfolio management approach combining economic evaluation, portfolio modeling and portfolio optimization. In this paper, a collection of exploration and development projects are evaluated using stochastic simulation techniques. After all project information is consolidated in one centralized location, a multi-dimensional portfolio data cube is built. Using portfolio optimization, different strategies are then tested by analyzing the solution envelopes, and movements within the body of the solution envelopes to explore all available opportunities. Different groups of opportunities are also tested against different scenarios using portfolio optimization to identify the best project mixes. The paper also concludes that an integrated portfolio management approach – one that goes beyond efficient frontier analysis - helps decision makers to identify realistic choices in uncertain situations more effectively.
Why Didn't All the Wells at Smorbukk Scale In?
Authors: Vassenden F. , Gustavsen O. , Nielsen F. M. , Rian M. , Haldoupis A. J.
Published: December 2007

Two of 19 wells were lost to carbonate scale in a high-temperature gas condensate field with commingled production. The problem was identified as tubing plugging. Plugging was caused by a 6-8 °C heating of water from the shallow interval when mixed with the hotter hydrocarbons from deeper formations. Even though there is a thermodynamic potential for scale precipitation within the reservoir, formation damage due to scale has not been positively identified so far, after up to 5 years production history. Thermal effects were important to understand this: Expansion cooling reduces the development of formation damage. These conclusions are explained quantitatively with thermodynamic and scale chemistry modeling of the field observations.
Price Uncertainty Quantification Models Advance Project Economic Evaluations
Authors: Olsen G. T. , Fariyibi F. L. , Lee W. J. , McVay D. A.
Published: December 2007

Conventional oil and gas price forecasts typically include pessimistic, most-likely, and optimistic cases in an attempt to quantify economic uncertainty. An analysis of forecasts presented by industry and governmental organizations illustrates that conventional forecasting methods typically underestimate significantly the full range of uncertainty in oil and gas price forecasts. Economic indicators calculated using such forecasts will not reliably quantify investment risk. In this investigation we compared and contrasted several recently developed methods for quantifying upstream petroleum investment risk due to uncertainty in future prices. We analyzed five forecasting techniques - conventional, bootstrap, Inverted Hockey Stick (IHS), historical, and Sequential Gaussian Simulation (SGS). These techniques were applied to three synthetic projects and 23 industry projects to examine the uncertainty associated with economic indicators such as net present value, investment efficiency, and internal rate of return. Across all 26 projects, the conventional forecasts predicted a narrower range of economic indicator values than the four alternative methods, indicating that conventional methods routinely underestimate uncertainty.

All four alternative forecasting techniques can provide operators with more reliable quantification of the uncertainty inherent in their investment decisions than provided by conventional methods currently in widespread use. The four alternative methods have unique strengths and weaknesses that may affect their applicability in particular situations. The SGS methods is the most rigorous and accurate method; however, it is also the most difficult to apply. The IHS method serves as a reasonable approximation, and can be easily incorporated into existing procedures and software.
Fracture Face Damage – It Matters
Authors: Gdanski R. , Weaver J. , Slabaugh B. , Walters H. , Parker M.
Published: December 2007

The poorer-than-expected performance of some fracturing treatments has been an issue for decades. Considerable effort has been devoted to improved modeling of fracturing treatments so that improved expectations can be provided. Fracturing fluids have been modified to enhance cleanup. Proppant conductivity studies have lead to a better understanding of fracture performance. Yet, there are still many treatments, particularly in low-permeability gas wells, that defy efforts to clean up quickly and to produce at the expected rates. This paper revisits the question of whether fracture face damage is an issue in the subsequent performance of a gas well. It will be demonstrated that the landmark paper by Holditch1 has been misquoted for 25 years. A numerical simulator has recently been written that has reproduced the earlier work, but also expands on it by demonstrating the physical mechanisms by which fracture face damage can reduce gas production and accelerate water production. The simulator includes relative permeability curves for both gas and water, and capillary pressure functions. The role of Laplace pressure, or capillary pressure, will be highlighted in the explanation of how fracture face damage can cause significant loss in well productivity. In addition, the role of relative permeability to gas will be highlighted as to how it ultimately leads to decreased gas production and increased water production when the fracture face is damaged.
A Quantitative Model of Asset Inventory Cycles and Portfolio Management for Performance Forecasting
Authors: Stewart J. T. , Chorn L. G. , Loop K.
Published: December 2007

A petroleum company's asset portfolio and capital allocation practices are leading indicators of future performance. Understanding the company's opportunity portfolio's maturity in conjunction with embedded core competencies, gives management a quantitative tool to allocate capital between exploration, development, sales and acquisition. This article uses fifteen companies’ publicly reported, historical performance data to test the predictive ability of a multidimensional model of investment portfolio management (SPE82006). The suite of companies includes acquirers and acquirees, as well as those who grew organically over the last two decades. The article reports on a refined model framework and demonstrates its predictive abilities.
Integrated Risk, Resource and Value Assessment of Unconventional Petroleum Assets
Authors: Stabell C.
Published: December 2007

Unconventional (continuous) petroleum resources present unique assessment challenges. Unconventional petroleum assets are large single accumulations that cannot be counted and analyzed as discrete entities that are delineated by downdip water contacts. This paper presents an integrated stochastic risk, resource and value assessment framework for decisions related to exploration and exploitation of unconventional petroleum assets. The framework builds on the FORSPAN model (Schmoker, 1999) where the continuous accumulation is viewed as a play consisting of a set of discrete cells that have not been explored (exploited) and that have the potential for economic production. Each cell is the drainage area of a fixed number of wells. Recoverable volumes can vary between cells, with some cells being non-commercial. We extend the FORSPAN framework in several ways. First, the model includes an estimated size (in an uncertain number of cells) of potential "sweet spots". Second, the model also includes a measure of exploration efficiency that represents the probability of finding sweet spots. Exploration results in a discovery sequence of sweet spots where the sequence is partially ordered by an exploration efficiency estimate. Third, we do a full cycle economics assessment for each sweet spot. The overall full cycle economics assessment with expected aggregate production profile and after tax cash flows are used to compute the estimated net present value of the unconventional petroleum asset. The paper concludes with a discussion of model limitations and potential improvements.
New Life to an Old Field
Authors: Swanson J. S. , Swanson D. C. , Jarvis M. , Hall R.
Published: December 2007

Overview and Challenge

The East Tunstill Field is a tight, under-saturated sandstone reservoir with a 9% recovery factor on primary depletion. Marginal current production and a previous relatively unsuccessful waterflood did not present the potential value of the field. In order to present this value, within a limited budget, new procedures and methods were necessary. A project workflow was designed to handle the field characteristics of a high number of wells and many years of production, resulting in a large amount of data that could be used to achieve a better analysis.

The operator, Penn Virginia ("PVA"), believed an improved reservoir description applied with simulation methods could yield a better understanding of previous drainage, fluid movement, and the volume and location of the remaining oil. Additionally, the operator decided to utilize a new volumetric balancing technology that allowed a fast (15 minutes) analysis of various waterflood injection/producer patterns to derive the most economic and efficient flood pattern and thereby highlighting its potential.
Identifying the Economic Savings Beyond the Reservoir
Authors: Hogg C.
Published: December 2007

Utilizing past multilateral installations and studies, this paper analyzes and discusses potential up front cost savings gained from a multilateral approach. Downhole savings as a result of minimized drilling requirements, reduced casing requirements, and other equipment and operations are discussed. Additional cost savings resulting from decreased surface and support requirements will are also covered in detail. Additionally, intangible cost savings in the form of reduced rig mobilization costs, lessened HSE costs and lessened rig time cost savings are included in the discussion.
Identifying Technical and Economic EOR Potential Under Conditions of Limited Information and Time Constraints
Authors: Manrique E. , Wright J.
Published: December 2007

The application of Enhanced Oil Recovery (EOR) processes increases the economic value of existing fields through increased oil recovery and field life extension. This is especially important in depleted and mature fields, as oil production rates decline and water production increases. Additionally, environmental concerns also benefit EOR projects such as CO2 injection providing new opportunities for depleted and mature fields combined with a disposal of CO2 capturing emissions from industrial sources.

Generally, oil companies (from majors to independents) operate a large field portfolio or a large number of reservoirs with lack of information. In some other cases, many reservoirs lack enough financial performance to justify information or data gathering. The latter represents a common barrier to identify appropriate investment opportunities in a particular or a portfolio of reservoirs.

This paper describes an approach to perform an economic evaluation of EOR projects based on advance screening criteria and full field evaluations under conditions of limited information and time constraints. The proposed methodology estimates EOR technical viability and production potential in a particular field based on international field experience and fast evaluation tools such as analytical simulators and economic software programs. The proposed methodology not only provides a systematic approach for evaluating and ranking technical and economic EOR performance within a risk management framework but also shows an excellent potential to support decision-making processes in oil property acquisition and for the exploitation of unconventional reservoirs (CBM and Tight Gas), among others.
Active Filter-Cake Technology – Eliminating the Need for Post-Completion Cleanup
Authors: Ravitz R. , McCarter M. , Taglieri A. , Colazas G. , Montes E. , Rizkalla S.
Published: December 2007

A new generation Reservoir Drill-in Fluid (RDF) has been developed to mitigate the potential of damage to the producing formation and eliminate the need for post-completion cleanup. This RDF system was developed to perform synergistically where openhole gravel-packing or expandable screen completion styles are utilized.

This new RDF system generates an active filter cake which is impermeable to aqueous fluids, thus reducing fluid loss into the producing formation. Concurrently, the now residual filter cake is permeable to formation hydrocarbons. This system utilizes organophilic components which generate preferential oil channels in the residual filter cake, thereby, eliminating the need for stimulation/cleanup from either internal or external chemical breakers. The preferential channels also help reduce the influx of aqueous formation and/or injection fluids.

This paper details the development of the RDF system and the engineering of it on two openhole gravel-pack completions in the East Wilmington Field off the coast of Long Beach, California. It discusses the development of the system and the field trials. A maintenance schedule used by the fluid engineers for anticipated potential problems is also discussed. The field performance is discussed and lessons learned are contrasted with conceptual design. Comparative data from earlier horizontal wells are included and contrasted with respect to the RDF system design, drilling parameters and well start-up. Finally, the initial well-test data are presented.