Hydrocarbon Classification and EOR 101, 2012

Jim Myers, MPE Hydrocarbon Classification and EOR 101, July 14, 2009 Page 1 of 75

Hydrocarbon Classification and EOR 101Table of Contents

TABLE OF CONTENTS........................................................................................... 1ABSTRACT .......................................................................................................... 3TABLE OF APPENDICES ........................................................................................ 3INTRODUCTION.................................................................................................... 4HUBBERT’S “PEAK” AND BELL CURVE ................................................................ 4GEOPOLITICS OF INTERNATIONAL HO & BITUMEN DEPOSITS............................... 5ENVIRONMENTAL BITUMEN & HO ISSUES ........................................................... 7OILFIELD JARGON AND PROFESSIONS................................................................... 8GEOSCIENCES, ACCOUNTING, LAND, LEGAL........................................................ 8DRILLING AND PETROPHYSICAL ENGINEERS ........................................................ 9PRODUCTION AND RESERVOIR ENGINEERS ........................................................... 9CRUDE OIL CLASSIFICATION ..............................................................................11INTERMEDIATE HYDROCARBONS ........................................................................11SINGLE-PHASE FLOW IN POROUS MEDIA.............................................................13DRY GAS RESERVOIRS .......................................................................................13LNG AND ENERGY POLICY ................................................................................14WET GAS RESERVOIRS .......................................................................................162-PHASE RELATIVE PERMEABILITY AND FRACTIONAL FLOW ...............................16RELATIVE PERMEABILITY AND MOBILITY RATIO ................................................17RETROGRADE GAS RESERVOIRS .........................................................................18VOLATILE OILS ..................................................................................................18CRUDE “BLACK” OILS........................................................................................20CONVENTIONAL (LIGHT & INTERMEDIATE) CRUDE OIL ......................................20API GRAVITY AND HEAVY CRUDE OILS (HO) ....................................................21HO & BITUMEN, ACCORDING TO USGS:............................................................22SHALES, ACCUMULATIONS, AND “OIL SHALES”..................................................23RESERVOIR CONDITIONS AND FLUID DENSITIES ..................................................24RESERVOIR CONDITIONS AND OIL VISCOSITIES ...................................................24RESERVOIR CONDITIONS, POROSITIES & WETTABILITIES ....................................25PRIMARY OIL RECOVERY DRIVE MECHANISMS...................................................25ORIGINAL OIL IN PLACE AND RECOVERY EFFICIENCY .........................................26CONSEQUENCES OF OIL RESERVOIR DEPLETION..................................................28WATERFLOOD AND EOR (IOR) UNITS ...............................................................28SCREENING PRODUCING OIL FIELDS FOR WF & EOR..........................................29WATER DRIVE, DISPOSAL AND SUPPLY...............................................................29WATERFLOODING & HOT WATER INJECTION ......................................................30WHY WATERFLOODS UNDER-PERFORM ..............................................................31


CHEMICAL FLOODING (CF) INTRODUCTION ........................................................32ALKALINE FLOODING AND ASP..........................................................................32SURFACTANTS, MICELLES, TYPE I MICRO-EMULSIONS .......................................32MICRO-EMULSION TYPES II & III .......................................................................33SURFACTANTS IN E&P .......................................................................................34POLYMERS, GELS, AND GELATION......................................................................34OILFIELD POLYMERS AND GELS..........................................................................35MICROBIAL EOR................................................................................................36CF EOR SUMMARY ...........................................................................................37MISCIBLE EOR (CO2) PROCESSES:.....................................................................37CO2 FLOOD LOGISTICS & OPERATIONS...............................................................38SCREENING OIL-CO2 MISCIBILITY ......................................................................39EOR FOR HO FIELDS: TRHO............................................................................40CYCLIC STEAM INJECTION (CSI).........................................................................41STEAMFLOODING (SF)........................................................................................41IN-SITU COMBUSTION (I-SC, OR FIRE FLOOD) .....................................................42TOE TO HEEL AIR INJECTION (THAI™)..............................................................42DILUTION OF HO FOR PIPELINES.........................................................................43SURFACTANTS, HO, & BITUMEN........................................................................44“DEAD” OIL AND RECOVERY EFFICIENCY...........................................................44STRIPPER WELLS IN THE US ...............................................................................45AN EMERGING EOR CHEMICAL FLOODING PROCESS ..........................................45EOR AND CO2 SEQUESTRATION ........................................................................46FLUE GAS & GREENHOUSE GASES......................................................................47US FLUE GAS LOCATIONS ..................................................................................47US LOCATIONS FOR GEOLOGICAL CO2 SEQUESTRATION.....................................49FLUE GAS COMPOSITION ....................................................................................50FLUE GAS PROCESSING ......................................................................................50PROCESSING FLUE GAS NOX...............................................................................51PROCESSING FLUE GAS SO2 ...............................................................................51PROCESSING FLUE GAS MERCURY, HG ...............................................................52GREENHOUSE GAS SEQUESTRATION ...................................................................52CO-OPTIMIZATION FAILURE ................................................................................53HORIZONTAL DRILLING IN PROVEN OILFIELDS....................................................54MICRO HOLE DRILLING ......................................................................................56SUMMARY: LIGHT OIL LEGACY, HEAVY OIL DESTINY.......................................57US ENERGY POLICY ISSUES................................................................................59REFERENCES ......................................................................................................60


AbstractThe Global Industry of Exploration & Production (E&P), refining, transportation,distribution, and sales of hydrocarbons (oil & gas) give and take tremendous influencefrom and upon International geopolitical economics and logistics. Based uponenvironmental, ecological, personal and national economics, 2009 may mark thebeginning of the end of the “Hydrocarbon Age” of Man. May this Age conclude with aslittle torment as the Stone Age, ages of Bronze, Iron, Coal, etc...Should this End be near, exit strategies for individuals, companies, provinces, and nationswill be required. New information and technologies are available to assist with thiseventual shift from reliance upon hydrocarbons to fuel our vehicles, heat and cool ourbuildings, and generally support commerce and culture on all scales.Inventory and study of these data and technologies is vital to promote progress, controlhuman convenience, prevent human tragedy, preserve flora and fauna, foster sustainableecology and environment, and preserve political stability. Traditional and alternativeenergy resources must be balanced in delicate compromise and interplay.This document focuses upon some aspects of the science, engineering and technologiesof E&P, at a college freshman level. The overall role of E&P in upcoming events willnot be to solve the many problems now in view. Opportunities to forestall identifiedproblems, mitigate their intensity, and reduce their consequences seem apparent,however. Transition to the New Energy Economy will benefit from efforts to sustain andimplement good ideas, maximum identification of practical oil & gas resources, and questfor sustainable modifications to current systems. Enhanced oil recovery (EOR),especially as applied to heavy oil (HO) and bitumens, is perhaps the most powerful toolE&P can wield in the near future.Improved national energy policies and environmental policies for many nations may beattainable through careful study and collaboration between nations. Our citizens andcompanies would certainly benefit from application of foresight, practicality, and timingto enact genuine US National Energy Policy and US National Environmental Policy.

Table of AppendicesAPPENDIX 1. DARCY’S LAW..................................................................................................62APPENDIX 2. PITCH (ASPHALT) LAKES ..................................................................................63APPENDIX 3. FAIRWAY JAMES LIME FIELD, EAST TEXAS .......................................................63APPENDIX 4. EXXON MOBIL ADDS 1.5B BARRELS TO PROVED RESERVES ................................64APPENDIX 5. OIL FROM CANADA’S TAR SANDS CAN BE MADE ‘CLEAN,’ OBAMA SAYS.........64APPENDIX 6. ANWR RESIDENTS FAVOR DEVELOPMENT.........................................................66APPENDIX 7. REVIEWS OF HUBBERT'S PEAK: THE IMPENDING WORLD OIL SHORTAGE ..........66APPENDIX 8. REVIEWS OF MATTHEW R. SIMMONS’ TWILIGHT IN THE DESERT:........................71APPENDIX 9. RADIAL JET ENHANCEMENT..............................................................................74APPENDIX 10: ........................................................................................................................75“SURFACTANT-BASED PHOTORHEOLOGICAL FLUIDS: EFFECT OF THE SURFACTANT STRUCTURE”.............................................................................................................................................75


IntroductionA definition: petroleum, pe·tro·le·um (pə-trō'lē-əm)A thick, flammable, yellow-to-black mixture of gaseous, liquid, and solid hydrocarbonsthat occurs naturally beneath the earth's surface, can be separated into fractions includingnatural gas, gasoline, naphtha, kerosene, fuel and lubricating oils, paraffin wax, andasphalt and is used as raw material for a wide variety of derivative products.[Middle English, from Medieval Latin petrōleum: Latin petra, rock; see petrous + Latinōleum, oil; see oil.]

Hubbert’s “Peak” and Bell CurveM. King Hubbert was a Shell geologist who in 1956 predicted that US oil productionwould peak in the early 1970s and then begin to decline. Hubbert was dismissed bymany experts inside and outside the oil industry. Pro-Hubbert and anti-Hubbert factionsarose and persisted until 1970, when US oil production peaked and started its longdecline.The Hubbert method is based on the observation that oil production in any region followsa bell-shaped curve. Production increases rapidly at first, as the cheapest and mostreadily accessible oil is recovered. As the difficulty of extracting the oil increases, itbecomes more expensive and less competitive with other fuels. Production slows, levelsoff, and begins to fall. This can be observed in any sedimentary basin producing oil.Hubbert demonstrated that total US oil production in 1956 was tracing the upside of sucha curve. To know when the curve would most likely peak, however, he had to know howmuch oil remained in the ground. Underground reserves provide a glimpse of the future:when the rate of new discoveries does not keep up with the growth of oil production, theamount of oil remaining underground begins to fall. That's a tip-off that a decline inproduction lies ahead.Kenneth S. Deffeyes is the son of a petroleum engineer; he was born in Oklahoma, "grewup in the oil patch," became a geologist and worked for Shell Oil before becoming aprofessor at Princeton University.In Hubbert's Peak, Kenneth S. Deffeyes, writes with good humor about the oil business,but he delivers a sobering message: the 100-year petroleum era is nearly over. Global oilproduction will peak sometime between 2004 and 2008, and the world's production ofcrude oil "will fall, never to rise again." If Deffeyes is right--and if nothing is done toreduce the increasing global thirst for oil--energy prices will soar and economies will beplunged into recession as they desperately search for alternatives.It's tempting to dismiss Deffeyes as just another of the doomsayers who have beenpredicting, almost since oil was discovered, that we are running out of it. But Deffeyesmakes a persuasive case that this time it's for real. This is an oilman and geologist'sassessment of the future, grounded in cold mathematics. And it's frightening.Deffeyes used a slightly more sophisticated version of the Hubbert method to make the


global calculations. The numbers pointed to 2003 as the year of peak production, butbecause estimates of global reserves are inexact, Deffeyes settled on a range from 2004 to2008. Three things could upset Deffeyes's prediction. One would be the discovery ofhuge new oil deposits. A second would be the development of drilling technology thatcould squeeze more oil from known reserves. And a third would be a steep rise in oilprices, which would make it profitable to recover even the most stubbornly buried oil.Above summary is adapted from Scientific American review (See Appendix 7.) ofDeffeyes’ book. While exact dates are unknown, analysis of International sedimentarybasins indicates that a peak in International oil producing capacity is in the very nearfuture, if not already past. Simmons’ Twilight in the Desert (See Appendix 8.), alsodisturbing, dwells on Saudi reserves and deliverability.The American Petroleum Institute estimated in 1999 that the world's oil supply would bedepleted between 2062 and 2094, assuming total world oil reserves at between 1.4 and 2trillion barrels and consumption at 80 million barrels per day.Geopolitics of International HO & Bitumen DepositsAn abundance of information on heavy and extra-heavy oils and what USGS calls“bitumens” was published at http://pubs.usgs.gov/fs/fs070-03/fs070-03.html. Table 1 isexcerpted from this publication:

Table 1. 2003 USGS Summary: International distribution of estimated technicallyrecoverable heavy & extra-heavy oil and natural bitumen in billions of barrels (BBO). The totalestimated petroleum in these known accumulations is about equal to remaining conventional(light) oil reserves, and is concentrated in the Western Hemisphere.

recovery

factor*recoverableHeavy Oil, BBO

recovery

factor*

recoverableNaturalBitumen, BBO

North America 0.19 35.3 0.32 530.9South America 0.13 265.7 0.09 0.1W. Hemisphere 0.13 301.0 0.32 531.0

Africa 0.18 7.2 0.10 43.0Europe 0.15 4.9 0.14 0.2Middle East (ME) 0.12 78.2 0.10 0.0Asia 0.14 29.6 0.16 42.8Russia 0.13 13.4 0.13 33.7E. Hemisphere 0.13 133.3 0.13 119.7

GLOBAL TOTAL 434.3 650.7*Recovery factors were based on published estimates of technically recoverable and in-placeoil or bitumen by accumulation. Where unavailable, recovery factors of 10 percent and 5percent of heavy oil or bitumen in place were assumed for sandstone and carbonateaccumulations, respectively.



Especially for assignment to various classes of oil refineries, crude oils are classifiedaccording to their API Gravities, sulfur content, and other measured characteristics. Thusthe implications of downstream Refining and Marketing components of the Oil and GasIndustry have influenced the Exploration and Production components’ (E&P) view ofcrude oil classification.Before quickly reviewing the definition of API Gravity and the Internationalclassifications of various classes of hydrocarbon reservoirs, a quick introduction to theInternational setting of the known Heavy Oil (HO) and Bitumen deposits and theirpotential geopolitical significance is provided.An abundance of information on heavy and extra-heavy oils and what USGS calls“bitumens” was published at http://pubs.usgs.gov/fs/fs070-03/fs070-03.html. Table 1 isexcerpted from this publication:In addition, 212.4 billion barrels of natural bitumen in place is located inRussia but is either in small deposits or in remote areas in eastern Siberia.The USGS article excerpted here is a clear patriotic and scientific call for official andpublic awareness. HO and bitumens, as strategic domestic resources concentrated in theWestern Hemisphere, could be key elements in a National Energy Policy.Environmental Bitumen & HO IssuesIn 2003, the USGS lumped light and intermediate crude oils together as “conventional”or “light,” and pointed out:“Because conventional light oil can typically be produced at a high rate and a low cost, ithas been used before other types of oil. Thus, conventional oil accounts for a decliningshare of the Earth's remaining oil endowment.In addition to assessing conventional oil resources, scientists of the US GeologicalSurvey's Energy Resources Program collect data on the abundant energy resourcesavailable as heavy oil (including extra-heavy oil) and natural bitumen...Historically, heavy oil was found incidentally during the search for light oil and wasproduced by conventional methods when economically feasible. However, to sustaincommercial well production rates, heavy and extra-heavy oil production almost alwaysrequires measures to reduce oil viscosity and to introduce energy into the reservoir...Natural bitumen (often called tar sands or oil sands) and heavy oil differ from light oilsby their high viscosity (resistance to flow) at reservoir temperatures, high density (lowAPI Gravity), and significant contents of nitrogen, oxygen, and sulfur compounds andheavy-metal contaminants. They resemble the residuum from the refining of light oil…The Western Hemisphere has 69 percent of the world's technically recoverable heavyoil and 82 percent of the technically recoverable natural bitumen. In contrast, theEastern Hemisphere has about 85 percent of the world's light oil reserves.” Many environmental issues are associated with recovery of heavy oil and bitumens.Traditional thermal recovery processes include consumption of water, fuels, and solvents.Tar sand recovery may also involve surface mining and, similarly, use water, fuels andsolvents, and is often unsightly on profoundly grander scales. Tar sand recovery involvesstrips and open pits of Canadian land.


Please note that Canada has huge quantities of oil, gas, minerals, timber, etc. These areon monumental expanses of abundant land remote from population centers,environmental political success, and tourist attractions. Canadian government haslegitimate, sound, and fortunate jurisdiction over exploitation and their fiscal attitudemight be named. Call it “needy,” “greedy,” pragmatic, or statesmanlike, it is veryprofitable to the government and perhaps a vital benefit to citizens of the Great WhiteNorth.The ownership of Canadian mineral royalties by the Crown will always outweighenvironmentalism. Canada is perfect for study of exploitation technical issues withoutundue environmental and political restraint. US E&P professionals face greatly enhancedethical, moral, and legal issues overprinting those technical issues.Oilfield Jargon and ProfessionsThe oil and gas (O&G) industry contains several sectors: “upstream” exploration andproduction (E&P) sector, midstream gas processing and transmission (pipeline) sector,and “downstream” refining and distribution sectors.In E&P, shallower rock formations and equipment are called “uphole” from thosedeeper; deeper ones are called “downhole” from shallower ones. Equipment on theground surface may also be called “uphole,” and those below the surface are usuallycalled “downhole.”All the operations of drilling and producing oil and gas wells are recorded in the wellhistory, a vital administrative tool. Additional detailed records reside in variousdocuments (permits, notices) legally required by regulatory agencies.Lease Net Revenues of each Lease are shared by Joint Venture (JV) holders of WorkingInterests (WI’s) in the Lease, after subtraction of taxes, overriding royalty interests(ORRI’s), and other operating expenses from the Lease’s Gross Revenue.Geosciences, Accounting, Land, LegalAccounting and bookkeeping performs normal and exotic accounting for accountspayable and receivable, taxes, and especially Division Orders (DO’s) by which owners ofworking interests (WI’s).Legal contracts and procedures are performed by attorneys, their clerks and assistants,including lease operating agreements (LOA’s).Geoscience and Exploration: exploration geologists and geophysicists, also calledexplorationists, pick targets with hopeful potential to discover new oil and gas reservoirsunderground. Geophysical data, including seismic, gravity, magnetic, and x-rayfluorescence surveys are used along with data from existing wells (“well control”) inthese processes. Geoscience and land services may be performed by operating companyemployees or by outside consultants, which may be freelance partnerships betweengeoscientist and landmen.Land: “landmen” meet owners of downhole mineral rights and uphole surface property,and negotiate leases which control payment of ORRI’s and surface rentals and liabilities.Before a lease can be drilled, an LOA must be signed by WI holders to assign a state-


licensed operating company to “operate” the lease.Later in the lease development process, exploitation and development geologists andgeophysicists pick additional well locations to capitalize on existing properties and/ornew discoveries.Locations are picked for downhole geology and uphole considerations and prepared,numerous other rentals and services are paid, and drilling expenses and liabilities areborne by Operating Companies registered with State regulators and other WI holders.After all WI holder’s finalize and approval the LOA, each lease expense for geosciencelabor, data, or processing, drilling, workover, recompletion, and stimulation is submittedby operating company to WI holders in an authority for expenditure (AFE), requiringeach WI to consent or non-consent. Actual drilling and production operations areperformed in the field using procedures detailed in a prognosis for the operations.Drilling and Petrophysical EngineersDrilling Department: Drilling managers, drilling engineers, and wellsite foremen(“company men”) track the progress of each wells while it is being drilled. Drilling rigsare commonly owned by drilling contractors. First penetration of ground surface is called“spudding,” occurring on “spud date.” Drillpipe is generally lowered in 30’ “joints,”turned to the right by a kelly bushing in a rotary table which is like a giant motorizedwrench, as drilling fluid is pumped through the entire “string” of drillpipe to lubricate thedrillbit and return rock cuttings to wellsite surface. Drillpipe is occasionally withdrawnin 60-90’ “stands”; this operation is called “tripping drillpipe.”Geoscientists and/or petroleum engineers evaluate each well is evaluated after reaches itsTotal Depth (TD). An openhole wireline unit is dispatched to wellsite to run electricporosity and resistivity logs. Petrophysical engineers (petrophysicists) specialize incasing point evaluation of wells, using well logs, mud logs, cores, well tests, and otherdata acquired during drilling process. During the casing point decision the opportunityfor an attempt to produce hydrocarbons, a “completion” is sought.A casing election made according the LOA with consent or non-consent of WI holders.If incremental economics are deemed to allow the expense to set production casing, acasing crew arrives to assemble the long string of steel production pipe reaching to TD.Cement trucks then arrive to mix oilfield cement, pump it down the drillpipe to returnbehind the casing, providing a hopefully strong seal between formation rock layers andproduction pipe. This “cement job” may be the drilling personnel’s last wellsite duty.Petrophysicists also assist other petroleum engineers and geoscientists to furtherscrutinize well data for additional opportunities, especially recompletions uphole of thedeepest completion, which is almost always performed first.Production and Reservoir EngineersProduction engineers: Many petroleum production engineers hand both downholecompletion and uphole facilities work, but these activities are discussed separately here.After running a wireline cement bond log to confirm a successful cement job, completionengineers design the downhole system the packers, plugs, and tubing, submersible


pumps, gas lift valves, and/or rods. They call out a wireline perforating unit, which blastscontrolled perforations in the production casing by electrically detonating shaped chargesdownhole. Perforated interval will probably be acidized, and a swabbing unit may thencheck the wellbore for liquid entry.Facilities engineers specialize in the uphole meters, compressors, separators,dehydrators, treaters, pumps, pipes, valves, tanks or tank batteries, often served withstairs and walkways for safety.Reservoir engineers assist in justifying the choice of a drilling location and, withpetrophysicists, to evaluate a well’s success at TD. They then monitor the data in eachfield to watch for problems and opportunities. They project the oil, gas, and wateranticipated from fields for many years into the future. Economic forecasts of oil and gasprices are used with these production forecasts to estimate the economic performance ofthese assets. Reservoir engineers have primary responsibilities for the 10-k Reportsrequired by the SEC for public corporations. Ultimately these activities combine to set apresent value (PV) on each asset, employing discounted net cash flow (DCNF) method.Reservoir engineers use computer programs called reservoir simulators to match theproduction histories of fields and for numerical experimentation to plan waterfloods(WF), enhanced oil recovery (EOR) projects, and reservoir gas cycling to enhancerecovery in retrograde gas and volatile oil reservoirs.They use other programs to analyze the pressure-volume-temperature (PVT) behavior ofcomplex reservoir fluid systems. Along with production engineers, they use “nodalanalysis” software to analyze and predict the pressure drops that occur in every intervalfrom the perforations at a completion through downhole and uphole equipment all theway to the stock tanks or gathering lines.In the 1970’s, the Environmental Protection Agency (EPA) and Occupational Safety andHealth Administration (OSHA) were created just in time for the Oil Boom following theOPEC oil embargo of 1973. Since then the O&G industry has evolved the merging ofthese priorities with security to create the acronym “HSSE” for health, safety, security,and environmental emphasis.


Crude Oil ClassificationCrude oil is classified as light, medium, heavy, orextra-heavy, according to its measured API Gravity,based on this crude oil’s specific gravity (SAG), itsgravimetric density compared to that of water, at60°F.

API Gravity = (141.5 / SG@60°F) - 131.5, soSG = 141.5 / (API Gravity +131.5).

This temperature of 60°F is a component of StandardTemperature and Pressure (STP). The exacttemperature of STP has been numerically redefinedregularly since the STP concept was introduced.Currently the North America petroleum Industryuses predominantly STP of 60°F and 14.73 psi (todefine the natural gas sales unit MCF @STP, forexample). Natural gas companies in Europe andSouth America have adopted 15 °C (59 °F) and101.325 kPa (14.696 psi) as their STP.Light crude oil is defined as having an API Gravityhigher than 31.1°API.Gasoline’s API Gravity averages 50°, so its SG=141.5 / (50° + 131.5) = 0.778.Intermediate crude oil or Medium crude oil isdefined as having an API Gravity between 22.3°APIand 31.1°API. Note the EU defines medium crudegravity between 25.7° API and 31.1°API.Heavy crude oil is defined as having an API Gravitybetween or 10° and 22.3° API. The EU has aslightly different definition of ‘heavy'. Their cutoffbetween ‘heavy' and ‘intermediate' lies at 25.7° APIGravity. This causes there to be more “heavy” crudeoil in their view.Extra-heavy crude oil is generally defined ashaving an API Gravity below 10°.Graphic copyright Schlumberger "Oilfield Review.” FromCarl Curtis and others, 2002, Oilfield Review, v. 14, no.3, p. 50.Intermediate HydrocarbonsThe continuum of hydrocarbons is best understood within the unified concepts offractionation and equilibria related to deposits of natural gas, volatile oils, and crude oils.These will be discussed in sections below.


When a wellsite geologist uses a wellsite gas chromatograph (GC) to analyze thecombustible gases, these hydrocarbon gases are fractionated to methane (CH4), ethane(C2H6), propane (C3H8), and the butanes (C4H10’s). The 5 gases are reported as C1, C2,C3, C4, and C5. C4 and C5 are the butanes; pentane is often a liquid and thus not alwayslogged.

Figure 1. Gas Chromatograph display, showing a retrograde gas or wet gas response. Thebutanes are liquids at many winter temperatures. The pentanes would be liquids at allcommon uphole temperatures. All might gaseous in situ, depending upon downholetemperature and pressure. http://www.srigc.com/Please note that methane is CH4, ethane is C2H6, propane is C3H8, butanes are C4H10’s,pentanes are C5H12’s, and hexanes are C6H14’s. Methane occurring alone is often callednatural gas or dry gas; a more inclusive definition of dry gas is provided below. Thecollection of ethane through the hexanes, CH4- C6H14’s, is called intermediatehydrocarbons, or intermediates. The intermediates are discussed regularly inclassification of hydrocarbon gases and liquids.Butane, also called n-butane, is the unbranched alkane with four carbon atoms,CH3CH2CH2CH3. Butane is also used as a collective term for n-butane together with itsonly other isomer, isobutane (also called methylpropane)(CH3)3;; the isobutane moleculeis triangular. When the butanes are blended with propane and other hydrocarbons, it isreferred to commercially as liquefied petroleum gas (LPG).For decades the butane’s, C4H10’s, were commonly used as fuels, especially inagricultural engines. Propane, C3H8, and LPG have replaced the butanes in these routinerural applications, and propane now commonly used in motor vehicles, outdoor cooking,and home heating.This replacement avoids the problem of butane condensing to a vaporless liquid duringcold weather. Liquid hydrocarbons do not burn; only hydrocarbon vapors burn undercontrol by design. Likewise, pentanes, C5H12, and hexanes, C6H14, are liquids at STP.


All these heavier hydrocarbons require vaporization by some process such as carburationor fuel injection to fuel controlled combustion.Single-Phase Flow in Porous MediaDarcy's law is a simple proportional relationship between the instantaneous discharge ratethrough a porous medium, the viscosity of the fluid and the pressure drop over a givendistance. The rate at which a fluid flows through a permeable substance per unit area isequal to the permeability, which is a property only of the substance through which thefluid is flowing, times the pressure drop per unit length of flow, divided by the viscosityof the fluid.Darcy’s Law is presented below in its 1D form:

The total discharge, Q (units of volumeper time) is equal to the product of thepermeability of the medium, the cross-sectional area (A) to flow, and thepressure drop (Pb − Pa), all divided by thefluid’s dynamic viscosity µ, and the length.Figure 2. Schematic view of Darcy’s Law for single-phase fluid flow through a porousmedium.

Q = - κ A (Pb – Pa) / µ L.The total discharge, Q (units of volume per time, e.g., m³/s) is equal to the product of thepermeability (κ units of area, e.g. m²) of the medium, the cross-sectional area (A) to flow,and the pressure drop (Pb − Pa), all divided by the dynamic viscosity µ (in SI units e.g.kg/(m·s) or Pas), and the length L the pressure drop is taking place over. The negativesign is needed because fluids flow from high pressure to low pressure. So if the changein pressure is negative (in the x-direction) then the flow will be positive (in the x-direction).Dividing both sides of the above equation by the Area A results in a more generalnotation for the differential form of Darcy’s Law:

q = - κ p / µ.This simple law, detailed in Appendix 1., is completely adequate to formulate numericalsimulations of saturated groundwater movement. It also describes the movement of drygas and wet gas in downhole reservoirs lacking oil or water, and is completely adequatefor their numerical simulation. Darcy’s Law is perhaps the most unavoidable buzzwordin subsurface reservoir engineering.Dry Gas ReservoirsVirtually all petroleum reservoirs contain some accumulation of methane, CH4. Thismethane may be dissolved in crude or volatile oil. It may have accumulated as a gravity-stable gas “cap” above a bank of saturated oil. Most oil deposits also contain someintermediates. Methane in a cap above oil is usually rich in intermediates. Methane


found without oil may be almost pure (dry) or may be dissolved with intermediates.Methane, ethane, and propane, with their small molecules, are gases at STP and at allcommon surface atmospheric conditions. If a petroleum reservoir contains only water,methane, ethane, and/or propane, the deposit is called dry gas. The dry gas may alsocontain butane, C4H10’s, but these will condense at the surface during cold weather.

Dry gas is primarily methane, perhapsincluding some intermediates. This is thephase diagram of a typical dry gas. Boththe line of isothermal reduction andseparator condition point are outside thephase envelope.The looping lines within the phaseenvelope represent constant liquidvolume as fractions of total volume. Theyare called iso-vols or quality lines.The dry gas hydrocarbon mixture is 100%gas in the reservoir, the tubing, atsurface, and even at separatorconditions. The very light intermediates,C2H6, and/or C3H8, will require processingequivalent to refrigeration for separationfrom methane.Figure 3. Dry Gas (methane, ethane, and/or propane) McCain, 1990.

Local or remote offsite processing of the ethane, propane, and/or butane enrichments tomethane can be very profitable, however. These are generally called “plant products.”The “gas plants” which separate them from methane may be owned by the E&P venture,the pipeline transmission company, or a 3rd-party midstream specialist. Ethane andbutane may have markets as petrochemical feedstocks or heavy oil diluent. Butane andpropane and LPG are also commercial fuels, of course.These most convenient gases can also remain dissolved in natural gas and contribute tothe heat value of the gas. Their contribution should be honored when negotiating gas unitsales value. Specification and timing of the heat value measurement will help optimizepipeline sales contracts.The International oil markets which swirl with superstition and uncertainty are notcompletely reproduced in the Continental markets for natural gas. Thus some additionalstability occurs in the natural gas markets. For the first 100 years of E&P, markets fornatural gas were very limited; many gas discoveries were plugged as disappointments,and much gas associated with oil wells was wasted by flaring. Great abundance, lowprices, gathering, transmission, and distribution pipeline systems combined with oilrationing and labor shortage to accelerate heating with gas during WW2.LNG and Energy PolicyBefore this dry (natural) gas can be moved overseas it must be liquefied cryogenically.Liquefied natural gas (LNG) technology is mature but only applied to specific isolated


deposits and markets. Methane is refrigerated to –163°C, -258°F, reducing the methane’svolume below STP by approximately the factor 600.LNG is about half as dense as water, so it is suited to transport by sea to locations withoutadequate domestic natural gas supplies. LNG is a “transparent, odorless, non-toxic, non-corrosive,” very cold, very flammable liquid, stored and transported in insulated pressurecontainers. About 200 LNG transport vessels are in service, and at least 13 nationsexport to 17 nations importing LNG. LNG prices are sometimes more than twice thosefor natural gas.In absence of very long pipelines and/or LNG shipments, natural gas supplies are hugegeopolitical issues, especially in Eurasia. Europe and Asia rely upon former SovietRepublics for natural gas supplies. Hopefully the gas markets on other Continents willperform less brutally than has Eurasia’s market.About 84% of the US natural gas supply, about 19.3 TCF annually, comes from theapproximately 500,000 US natural gas wells and associated gas from a similar number ofUS oil wells. About 83% of US gas imports, 3.3TCF annual, come from Canada.Slightly more US gas is exported to Mexico than is imported from Mexico. The 2%balance of US natural gas needs, 771BCF annual, is met by importing LNG fromTrinidad/Tobago (58%), Algeria, Egypt, Nigeria, Equatorial Guinea, and Qatar.The 8 US LNG import terminals are located on the Gulf of Mexico coast (4), inMassachusetts (2), in Maryland and Georgia. Mexico has terminals at Altamira and BajaCalifornia. The US exports LNG to Japan, Mexico, and Russia. The oldest marineterminal has been in service at Kenai, Alaska since 1969, exporting mostly to Japan andother Pacific Rim customers.At least 12 LNG import terminal proposals are now before the FERC, including Atlantic,Pacific, and Gulf Coasts, including the Pacific Northwest region. Compared to 2005demand, International LNG import demand will double in the next few years. WithTotal’s commitment to develop a terminal in Yemen, that nation is posed to become theWorld’s newest exporter of LNG.The US natural gas Industry has underwritten moderate product cost increases by itsaggressive replacement of reserves since 2000. The bulk of these new reserves have beenprovided by offshore oil and gas fields and unconventional gas reservoirs (“tight gas”from low-permeability reservoirs like shales, coal bed methane (CBM), and gas hydrates.Natural gas and LNG deserve detailed attention in the US Energy Policy as a domesticstrategic resource.


Wet Gas ReservoirsWet gas reservoirs produce condensate stocktank liquids, with GOR’s above 5,000 (even50,000) scf/STB. The gravity of the stock tankliquid is in the 40-50°API range and does notchange during reservoir life; GOR is alsoconstant during reservoir life. This liquid isusually clear as water.

No hydrocarbon liquid exists in the wet gasreservoir downhole.

The pressure path line in a wet gas phasediagram does not enter the liquid phaseenvelope. Separator conditions lie within thephase envelope, however, causing liquid to beformed at the surface.

Figure 4. Phase diagram for a wet gas reservoir. McCain, 1990.The hydrocarbon accumulations in most petroleum reservoirs are saturated with waterdue to their contact and equilibrium with water. Luckily the solubility of water inhydrocarbons is low.As a classification, the term “wet gas reservoir” is named, not for water, but for their richcocktails of downhole hydrocarbons in gaseous form. Those downhole gases thatcondense in separators at surface facilities are called condensates.These volatile, (brown, orange, or green) translucent and perhaps almost transparentstock tank liquids may contain hexanes and above, pentanes, butanes and limitedevaporating propane. In the early oil and gas business these were sometimes called “dripgas” because they might be burned as gasoline in a vehicle. Gasoline’s API Gravityaverages 50°, so its SG= 141.5 / (50° + 131.5) = 0.778.2-Phase Relative Permeability and Fractional FlowThe Buckley–Leverett equation or the Buckley–Leverettdisplacement can be interpreted as a way of incorporating themicroscopic effects due capillary pressure in two-phase flowinto Darcy's law. In a 1D sample (control volume), let S(x,t) bethe water saturation; f is the fractional flow rate, Q is the totalflow, Ф (φ, phi) is porosity and A is area of the cross-sectionin the sample volume.Forward in this primer, subsequent types of oil and gas accumulations will requireconcepts of 2-phase reservoir flow. Interfacial tension (IFT) forces are responsible forwettability (hydrophilic (water-wet), lipophilic or hydrophobic (oil-wet), or amphiphilic(mixed or “dalmation” wettability)) between oil and rock, and capillarity and gravitysegregation between oil, gas, and water and water.In fluid dynamics, the Buckley–Leverett equation is a transport equation used to modeltwo-phase flow in porous media[1] . The Buckley–Leverett equation or the Buckley–


Leverett displacement can be interpreted as a way of incorporating the microscopiceffects due to capillary pressure in two-phase flow into Darcy's law.The Buckley–Leverett equation is derived for a 1D sample given

mass conservation capillary pressure pc(S) is a function of water saturation S only dpc / dS = 0 causing the pressure gradients of the two phases to be equal.

General solution:The solution of the Buckley–Leverett equation has the form S(x,t) = S(x − U(S)t) whichmeans that U(S) is the front velocity of the fluids at saturation S.Relative Permeability and Mobility RatioEspecially during the development of reservoir engineering for secondary recovery(waterflooding), the relative permeability concept received generations of empirical andtheoretical research. A reservoir mobility gas-liquid mobility ratio, Mg-l, of gas to liquid,can be defined as

M g-l = kg µl / kl µgwhere M= µl and µg. are the viscosities of the liquid and gas phases, kg and kl are the2-phase reservoir relative permeabilities to gas and liquid.

Figure 5. 2-phase oil-water relative permeability curves measured in laboratory(2004, L. Qingjie, L. Li, Manli).

A similar mobility ratio can be formulated for water to oil, Mw-o, gas to oil, Mg-o, etc. The


most interesting relative permeability considerations are in 3-phase reservoircircumstances, where Herb Stone’s 3-phase relative permeabilities equations are requiredto estimate 30-phase data from 2-phase data for use in numerical reservoir simulationprograms.Retrograde Gas ReservoirsAn initial producing GOR of 3,300 to 5,000 indicates a very rich retrograde gas. Withoutpressure maintenance, such a rich gas will condense sufficient retrograde liquid torepresent a saturation of 35%. Even such a large quantity of retrograde liquid normallycannot be produced, due to its unfavorable mobility ratio as compared to reservoir gas.Economics incentive pressure maintenance and/or gas cycling to keep this valuablesolvent/gas in its gaseous phase! GOR > 50,000 indicates negligible retrograde effect.Retrograde gas reservoirs produce lightly colored, brown, orange, greenish, or water-white stock tank condensates with the same range of API Gravity, 40-50° API, as theliquids from wet gas reservoirs.The surface gas is very rich in intermediates; it is usually processed to remove propane,butanes, pentanes, and/or heavier hydrocarbons. These are often called plant liquids orplant products.Retrograde gas reservoir phasediagrams have the critical point on the leftside. Critical temperature is less thanreservoir temperature; thecricondentherm is greater.Initially retrograde gas is totally gasdownhole (1); under production pressuremay drop to dew point (2). Then liquidcondenses downhole. This liquid iscalled retrograde liquid. Laboratoryphase diagrams indicate lower pressures(3) where retrograde liquid revaporizes.This effect is uncertain in producingreservoirs due to downhole fluidcomposition changes during production.Figure 6. Phase diagram for a retrograde gas reservoir. McCain, 1990.

GOR’s increase and stock tank liquid gravity increase after reservoir pressure dropsbelow the dew-point (2).Retrograde gas reservoirs are cycled with reinjection of miscible gases (especiallymethane) to facilitate surface liquid recovery. They may also undergo water injection tomaintain pressure and retard the retrograde process.Volatile OilsThe class of light petroleums that are 100% liquids under initial downhole reservoirconditions, those in the 40-50° API Gravity range, is called volatile oils. Volatile oilscontain fewer heavy molecules and more intermediates (ethane through hexanes) than


crude oils.Note that volatile oils, wet gas, and retrograde gas/condensate reservoirs all have verylow viscosity and high API Gravity and very low fractions of very large heavyhydrocarbon molecules. The distinction between downhole liquids and gases can bearbitrary and/or academic among such light hydrocarbons.Laboratory-determined compositions of volatile oils will have mole 12.5-20% heptanesand above. The dividing line between volatile oils and retrograde gases at 12.5% molepercent heptanes plus is fairly definite.When the mole concentration of heptanes-plus is below 12.5%, the reservoir fluid isalmost always gas and exhibits a dew point. When this concentration is above 12.5%, thereservoir fluid is almost always a liquid and exhibits a bubble point. Any exceptions tothis rule normally do not meet the rules of thumb regarding stock-tank oil gravity andcolor.Laboratory observation of a volatile oil will reveal an initial formation volume factorgreater than 2.0 RB/STB. The oil produced at point 2. of the Figure will shrink by morethan 0.5, often 0.75, on its journey to the stock tank (3 or more stages of surfaceseparation are recommended). Volatile oils have also been called “high-shrinkage crudeoils” and “near-critical oils.”

The volatile oil reservoir phase envelopecritical point is low and close to reservoirtemperature. The iso-vols are not evenlyspaced; they are shifted upwards towardthe bubble-point line.The vertical line shows the path taken bythe constant-temperature pressurereduction during production, releasing alarge proportion of gas for a small pressuredrop.A volatile oil may become as much as 50%reservoir gas at only a few hundred psibelow the bubble-point pressure. Also, aniso-vol with even lower gas proportioncrosses the separator condition point.Figure 7. Phase diagram for a volatile oil reservoir. McCain, 1990.

As reservoir pressure drops to point 2 in Figure 4, creation of a secondary gas saturationbegins. The secondary downhole gas associated with a volatile oil reservoir is very rich,usually a retrograde gas; also, often over 50% of stock tank liquid produced from avolatile oil reservoir entered the wellbore as a gas. Remember the favorable mobilityratio allowing gas to flow preferentially due to its low viscosity.The critical temperature of a volatile oil is always greater than the reservoir temperature;its initial production GOR is between 2,000 and 3,3000 scf/STB. Producing GOR andstock tank API Gravity increases with primary production.


Literature is slight on volatile oil deposits. The largest accumulation I personallyobserved is the Fairway James Lime Field, East Texas with 410 MMBOIP, of which 213MMBO had been recovered in 2007 after 4 decades of gas cycling and water injection tomaintain reservoir pressure. (Appendix 3.)Another noteworthy volatile oil accumulation is in Eugene Island, Block 99, Lease OCS-G 21637, 20 miles offshore of Louisiana in the Gulf of Mexico. The extremely poorcharacterization and operation of this field by Columbia Gas Development Corp. leftmany millions of barrels of volatile trapped at abandonment despite the extremely lowprice and high availability of natural gas to optimize recovery by gas cycling.The Properties of Petroleum Fluids By William D. McCain states: “Volatile oilscontain relatively fewer heavy molecules and more intermediates, ethane-hexanes[methane is CH4, ethane is C2H6, propane is C3H8, butane’s are C4H10’s, pentane’s areC5H12, hexanes are C6H14]. Their critical temperatures are much lower than for black oilsand are close to reservoir temperatures. Their gas-oil ratios (GOR’s) are in the range of2,000-3,3000 scf/STB.”Crude “Black” OilsNote that Dr. McCain wrote the Book, and refers to the non-volatile light oils as “black,”low-shrinkage crude oils, or ordinary oils. So, black oil is a synonym for crude oil, and isexpected to have a GOR < 2,000scf/STB, an API Gravity < 45, and to be dark due topresence of heavy hydrocarbons.Black, or crude oils contain a wide variety of chemical species, including those large,heavy, molecules resistant to evaporation. Black, or crude, oils contain more heavymolecules and less intermediates (ethane through hexanes) than volatile oils.As the reservoir pressure drops below bubble point, a secondary gas saturation is created.The lower viscosity of gas eventually allows it to be preferentially drained duringproduction. Oil volumes shrink slightly as their dissolved gases evaporate from thishydrocarbon mixture downhole.Conventional (Light & Intermediate) Crude OilIntermediate crude oil or Medium crude oil is defined as having an API Gravitybetween 22.3°API and 31.1°API. Note the EU defines medium crude gravity between25.7° API and 31.1°API.Especially the most economically favorable crude oils are classified by API Gravity andsulfur content and given names. For example, Brent Crude is actually a combination ofcrude oil from 15 different North Sea oil fields with API Gravity of 35.5°.The Permian Basin’s West Texas Intermediate (WTI) has an API Gravity of around39.6 (specific gravity of around 0.827), lighter than Brent Crude. It contains about 0.24%sulfur, rating it a sweet crude, less sulfurous and thus “sweeter” than Brent.WTI properties and production sites make it ideal for being refined in the United States,mostly in the Midwest and Gulf Coast regions where demand for gasoline andpetrochemical products is high. Thus its listed market price is often higher than Brentcrude. WTI is extensively stockpiled at locations like Cushing, Oklahoma.


From January 1, 1987 to June 15, 2005, OPEC calculated an arithmetic average of sevencrude oil streams (known as the OPEC Basket). This basket included Algeria's SaharanBlend, Indonesia Minas, Nigeria Bonny Light, Saudi Arabia Arab Light, Dubai Fateh,Venezuela Tia Juana and Mexico Isthmus (a non-OPEC oil) to estimate the OPEC basketprice.Effective June 16, 2005, OPEC's new reference basket consists of eleven crude streamsrepresenting the main export crudes of all member countries, weighted according toproduction and exports to the main markets. The crude oil streams in the basket are:Saharan Blend (Algeria), Minas (Indonesia), Iran Heavy (Islamic Republic of Iran), BasraLight (Iraq), Kuwait Export (Kuwait), Es Sider (Libya), Bonny Light (Nigeria), QatarMarine (Qatar), Arab Light (Saudi Arabia), Murban (UAE) and BCF 17 (Venezuela).According to OPEC, the API Gravity for the new basket is heavier (32.7º compared to34.6º). In addition, the sulfur content of the new basket is more sour (1.77% compared to1.44%).

The black (crude) oil phase envelopehas the critical point higher abovereservoir temperature. Iso-vols arespaced rather evenly within theenvelope. Line 123 indicates thereduction in pressure during primaryproduction.Along Line 12, the oil is undersaturated;if more reservoir gas were present, itwould dissolve at these higherpressures.Along Line 23, the gas is saturated, andpressure reduction releases gas from thecrude oil to form a volumetric poresystem saturation of a free gas phase.Figure 8. Phase diagram for a “black,” or “crude” oil reservoir. McCain, 1990.

API Gravity and Heavy Crude Oils (HO)Heavy crude oil is defined as having an API Gravity between or 10° and 22.3° API. TheEU has a slightly different definition of ‘heavy'. Their cutoff between ‘heavy' and‘intermediate' lies at 25.7° API Gravity. This causes there to be more “heavy” crude oilin their view.Extra-heavy crude oil is generally defined as having an API Gravity below 10°.The USGS definition of natural bitumens, which are yet denser than extra-heavycrude oils, is presented below.This indication of oil specific gravity at temperature 60°F places the heaviest of the HOclass, with API Gravity = 10°, at the specific gravity (SG) of 1.0 (identical to water at60°F).


The lightest HO, at a SG= 141.5 / (22.3° + 131.5) = 0.922, floats on water.Asphalt, in the extra-heavy class, on average has an API Gravity of 8° (sinks in water).Its high viscosity makes it seem more solid than liquid; hence its desirability forpavement composites.The heaviest crude oils and natural bitumens, composed of very large complex carbon-rich hydrocarbon molecules, have very high heat contents. They were originally refinedto produce fuel oil, but require specialized refining to yield the petrochemical products inhighest demand today.Some of the rarest and most profitable petroleum refineries today are those devotedspecifically to processing heavy and extra-heavy crude oils. A memorable example isValero’s Bill Greehey Refinery in Corpus Christi, TX; one of the most profitablerefineries in the USA is refining very heavy oils to produce gasoline and other top-price petrochemicals!The properties of heavy and extra-heavy crude oil and bitumens are very stronglyinfluenced by temperature. Their form as perhaps solids, perhaps liquids, is muchdifferent depending upon temperature. The crude oil may be on the surface at 0.0° C, orat 100.0° C also on location, or at 100.0° C in a thermal recovery process at a depth of2,000’.These Celsius temperatures convert to 32° and 212° Fahrenheit. The very high kinematicviscosities of these heaviest crude oils and bitumens are especially strongly affected bytheir temperatures in their various environments.

Cumulative percentage of annualproduction (blue) and cumulativepercentage of technically recoverableresources (brown) of heavy oil as afunction of oil density (API Gravity) in2000.Less than 10 percent of the heavy oilproduced annually is extra-heavy oil(API Gravity of 10° or less), whereas 33percent of the technically recoverableheavy oil has an API Gravity of 10° orless.Figure 9. Cumulatives production and recoverable vs. API Gravity, USGS.

HO & Bitumen, According to USGS:Many “liquid” hydrocarbons in this class are found in tar sands, such as the AthabascaTar Sands in Canada. These tar sands are shallow, and due to their northern latitude theseshallow deposits are rather cool. When the Tar Sands are sampled in core barrels, onlythe tar consolidates the core, and the core falls into a blob when warmed!For some of their discussions, USGS lumps the Light and Heavy crude oil classestogether as …:


“(USGS) Light oil, also called conventional oil, has an API Gravity of at least 22° anda viscosity less than 100 centipoise (cP).Heavy oil is an asphaltic, dense (low API Gravity), and viscous oil that is chemicallycharacterized by its content of asphaltenes (very large molecules incorporating most ofthe sulfur and perhaps 90 percent of the metals in the oil). Although variously defined,the upper limit for heavy oil has been set at 22° API Gravity and a viscosity of 100 cP.Extra-heavy oil is that portion of heavy oil having an API Gravity of less than 10°.Natural bitumen, also called tar sands or oil sands, shares the attributes of heavy oil butis yet more dense and viscous.Natural bitumen is oil having a viscosity greater than 10,000 Centpoise (cP).” Waterhas a kinematic viscosity of 1.0 cP at 60°F.Natural bitumen (often called tar sands or oil sands), extra-heavy and heavy crude oilsdiffer from lighter oils by their high viscosity (resistance to flow) at reservoirtemperatures, high density (low API Gravity), and significant contents of nitrogen,oxygen, and sulfur compounds and heavy-metal contaminants. They resemble therefinery residuum from the refining of light oil.”Shales, Accumulations, and “Oil Shales”As a rock type, a shale is a fine-grained sedimentary rock whose predominant originalconstituents were clay minerals or muds. It is “fissile,” its thin laminae breaking with anirregular curving fracture, often splintery. Non-fissile rocks of similar composition aremudstones. Related rocks but with less clay and more very fine-grained silica aresiltstones. Shale beds are of immense importance in E&P as sources, seals, andreservoirs. Their study is also part of the “shaly sands problem” in petrophysics.Every hydrocarbon accumulation relies on its resident reservoir porosity system, aseal and trap to confine the oil and/or gas, and migration of the hydrocarbons from thesource formation in which the hydrocarbons were geochemically created. Those areclassically defined as the basic elements required creating a hydrocarbon accumulation.Shale is the most common sedimentary rock; it is deposited in beds of all thicknesses,from tiny laminae to vertical sequences of thicknesses of thousands of feet extendingover huge areas. By virtue of their very limited hydraulic permeabilities and hugevolumes, shale beds are the most common “seals” above oil and gas reservoir rocks,serving along with structural and stratigraphic “traps” to confine accumulations ofhydrocarbons. Halite (table salt) formations are also excellent seals by virtue of their lowpermeability and flowing behaviors of plastic deformation.Since organic-rich shale beds are the predominant “sources” of hydrocarbons, few ofthese beds are lacking in hydrocarbon content. Unlike the focused limited definition ofshale as a rock type, a thick shale bed’s depositional cycles commonly included silty andsandy episodes, resulting in laminae of sufficient primary porosity containing natural gasto allow these massive beds to serve as gas reservoirs after horizontal drilling andhydraulic fracture treatments. Thinner shale beds and those with inferior organic contentdo not offer similar potential for gas production.


An 'oil shale' is neither oil, nor shale. Oil shale contains kerogens (immatureprecursors to oil and gas), and theoretically can be burnt without processing as a fuel. Ina documented episode, a personally built mountain cabin was constructed with a fireplacebuilt from “oil shale.” The first fire in that fireplace was a real house warming, and thecabin was destroyed.First Exxon in the 1970’s, then more recently Shell Oil, have invested $ billionsattempting to create synthetic oil and gas from “oil shale” in the Rocky Mountain states.Huge technological and environmental challenges remain, and these will be some of thefinal energy resources exploited in North America.Reservoir Conditions and Fluid DensitiesThe oil and gas Industry’s exploration and production (E&P) activities, a legacy ofobservational context based on gravimetric density permeates the views of thegeoscientist and engineer. In this legacy, gas floats on oil, and oil floats on water.Innumerable geologic crossections, areal maps, and well log breakdowns are thusaligned. The maps show primary and secondary gas “caps” perched upon rings of lightand intermediate oils. The oil rings very often float on aquifers or smaller deposits offormation water.The Yates Field Unit of Pecos Co., Texas, is an example: After generations of injectionof possibly every available fluid, including nitrogen, CO2, heated and unheated water,this is still a $billion property. The oil accumulation is now described as a “seven-footoil column,” above a water column, below a gas “cap.”Subsurface accumulations of heavy and especially extra-heavy crude oils challenge thisgravimetric stereotype. The lightest of the extra-heavy crudes have neutral buoyancy infresh waters. Formation brines have specific gravities up to about 1.1, but low-salinityconnate waters may be gravity-stable above heavy oils. This density contrast defies theIndustry stereotype of the oil-water contact, replacing it with a water-oil contact.Reservoir Conditions and Oil ViscositiesThe API Gravity a crude oil and its basis in specific gravity (SG), based on the density ofwater, reflect the molecular weights of their constituent liquid hydrocarbons. Generallyliquid hydrocarbon viscosities increase as do their densities, but this correlation exhibitsconsiderable statistical scatter, especially when the various international occurrences ofthese very heavy hydrocarbons are examined.Note that while API Gravities of reservoir oils and their gravimetric implications arethemselves of interest in thermal recovery of heavy oil (TRHO), HO’s very highkinematic viscosities have even more impact on their performance under all recoveryprocesses.The primary recovery characteristics of California’s largest fields benefited greatly fromtheir extreme overpressure, however. This extreme pressure regime temporarilyovercame the disadvantage of the very high viscosities of the HO’s, and was probablygreatly influenced by the region’s pronounced tectonic stresses.This discussion assumes subject HO’s have viscosities more than 50 times that of water


under reservoir conditions. This is consistent with real HO’s under recovery usingTRHO options.Reservoir Conditions, Porosities & WettabilitiesPerhaps the most accessible parameters in reservoir characterization are averageporosities. Perhaps the least accessible parameters in reservoir characterization arewettabilities.A reservoir pore may be primary (created during sedimentary deposition) or secondary(created during lithification or diagenesis long after sediments are deposited). Theprimary porosity systems may be intergranular, especially in sandstones, siltstones, andeven in shales (thus the current wave of “shale gas” projects which has added significantUS natural gas reserves through combined use of horizontal drilling and hydraulicfracturing technologies). Porosity systems may be intercrystalline, karstic, fractured, orall of the above, especially in carbonate reservoir rocks. Wireline compensated neutronlithodensity combination porosity logs give average reservoir porosity measurementswith accuracy ranging from excellent to barely adequate. Generally these nuclearporosity logs provide adequate accuracy for average reservoir porosity evaluation.The surfaces of a reservoir pore may be hydrophobic (repelling water) or hydrophilic(attracting water). Oil will cling electrostaticly to hydrophobic surfaces. Water will clingsimilarly to hydrophilic surfaces. These concepts are easily demonstrated in simplisticexperiments.Many reservoir porosity systems exhibit mixed, checkerboard, or “Dalmatian“nonuniform wettabilities. Since many techniques to evaluate reservoir systems’wettability states and distributions unfortunately involve alteration of these states,wettability evaluations are very difficult.Primary Oil Recovery Drive MechanismsPrimary recovery in oil reservoirs depends on a primary reservoir drive mechanism.Hydrostatic and/or lithostatic forces have charged the compressible oil accumulation withpotential energy.Gravity drainage occurs when heavy oil "drips" down through the reservoir porositysystem into production wells. This is significant in reservoirs with depleted pressures.If the oil is saturated with gas, a primary gas cap may exist gravity-stable above banks ofoil and water. If the water bank is small, water drive will not be significant. In gas capdrive, the very high compressibility of natural gas may allow the gas cap’s expansion tosignificantly support pressure and maintain reservoir energy during production. Withgreat care, oil production may be controlled and limited to prevent premature fingering ofa gas bank into production wells. Since gas has very low viscosity and very highmobility ratio, this is a difficult engineering task.Volatile and crude oils without water drive often depend upon dissolved gas drive(DGD). This mechanism, also known as depletion drive, is especially important in theearly period of high production rate sometimes called flush production. Above bubblepoint, the oil enters the wellbore without gas liberation or significant reduction of


reservoir potential energy.

Figure 10. Schematic cross sections of 3 basic reservoir drive mechanisms: depletion ordissolved gas drive, gas cap drive, and water drive.As the DGD oil reservoir’s pressure drops during production, it eventually reachesbubble point, and gas is liberated from the oil. Especially near the wellbore, regions offree gas occur. Viscosities and mobility ratios predict preferential flow of gas, and theproducing GOR increases. Oil composition is thus changed, and reservoir oil graduallyshrinks slightly and loses much of its natural gas and intermediates content. Withoutpressure maintenance operations the reservoir’s oil loses its potential energy, becomesheavier and more viscous.This undesirable and destructive loss of DGD oil reservoir energy can be prevented byinstituting a pressure maintenance plan before reservoir pressure drops significantlybelow bubble point. Encouragement or requirement of such conservation measures isadmirably institutionalized in Canada and China, for example. The US E&P Industry isnow super-mature way beyond much benefit from such regulation in any emergingenergy policy, however.An oil reservoir with an oil-water contact directly connected to an extensive aquifer maybenefit from the aquifer’s advance toward production wells, water drive. Givenadequate management to moderate production and minimum heterogeneity regardingreservoir/aquifer permeability, a large aquifer may support reservoir pressure for ageneration before the free water impinges upon production wells. These water drivesmay be considered strong and active (large aquifer moving quickly as oil is produced),moderate, or weak.Original Oil in Place and Recovery EfficiencyA reservoir engineer’s evaluation of an oil deposit begins with calculation of original oilin place (OOIP). This calculation is simple: multiply the volume of the oil accumulationby its average porosity by its porosity-weighted oil saturation. After volumetric units likeacre-feet are converted to barrels of oil (BO), an estimate of the original oil in place inBO results. The Lower 48 States of the US abounds with counties which have producedover 1 billion BO; some of these records were set before WW2, and very many havefollowed. The ratio of cumulative oil recovery to OOIP, in BO, is called recovery


efficiency.In carefully engineered conditions, under the most fortunate drive mechanisms and otherreservoir details, more than half of OOIP (50%) may be produced during primaryrecovery. This is most likely under conditions of strong water drive, very high reservoirporosity, and permeability, with moderate drawdown of bottomhole tubing pressure(BHTP). The bank of water moves toward the oil column as the oil column movestoward the wellbore, maintaining downhole reservoir pressure.Along with oil fields on land where the oil column is in direct contact with a very largeaquifer, these conditions are especially likely in marine settings like the Gulf of Mexico(GoM). Occasionally a column of reservoir brine may even outcrop on the marine floor,placing it in direct contact with the marine hydrostatic gradient.Due to the unfavorable mobility ration of gas to oil, oil accumulations with gas cap driveseldom approach such high recovery efficiency as 50%. Accumulations depending uponDGD never approach such a high value of recovery efficiency, and the economics ofprimary production eventually becomes marginal, leaving most of OOIP remains in thereservoir. Recovery efficiency under primary recovery for DGD reservoirs ranges from3% to 30%, at an average of around 12%.

Figure 11. Chemical analysis of a Texas intermediate crude oil thought to be Paleozoic inorigin, from a reservoir on production for almost 100 years. Note that methane andintermediates are almost absent, with heptane (n7) the lightest component displayed withsignificant amplitude. This stripping of light HC’s is a common characteristic due to excessivedrop of reservoir pressure in a DGD oil reservoir. Because of its increased viscosity andlowered API Gravity, such oil is called “dead” oil.


Consequences of Oil Reservoir DepletionIn the Lower 48 States of the US, during primary recovery, most active oil fields produceby the dissolved gas drive (DGD) primary recovery mechanism, also called depletiondrive. As was just mentioned, drawing an oil reservoir’s far below bubble point quicklypromotes a premature severe change in downhole reservoir conditions. Several changesin the reservoir’s character are then inevitable: Gas is progressively liberated from reservoir oil, forming banks of gas. Due to unfavorable

mobility ratio of oil to gas, these banks of free gas flow preferentially to the wellbore. This gas is typically rich in intermediates, having been in contact with oil. Thus methane

and intermediates are progressively stripped from the oil, making the oil heavier. Eventuallythe GOR ratio will vanish to near zero; such remaining oil is called “dead oil.”Consequences of this oil composition change are inevitable:

The progressively heavier oil becomes denser, “shrinking” within the reservoir pores. Additional pore space is thus evacuated. Oil may shrink into the less accessible volumes of

the porosity system. This reduced oil saturation increases relative permeability to gas,enhancing the already-unfavorable oil-gas mobility ratio.

The progressively heavier oil becomes more viscous, “thickening” in viscosity, furtherenhancing the unfavorable oil-gas mobility ratio.

High gas flow rates near the wellbore enhance the stripping of reservoir oil from thecompletion area, further enhancing the unfavorable oil-gas mobility ratio near the wellbore.

Recovery efficiency under this unfavorable scenario is often in the 10% range, and isseldom as high as 20%.

The largest of the producing oil fields, and those with the largest amounts of original oilin place (OOIP), will institute unitization to implement a waterflood for pressuremaintenance. In small accumulations the result of poorly managed reservoir pressureyields a “stripper well,” which produces a few BO/day or less.Waterflood and EOR (IOR) UnitsBeginning in the 1980’s, WF and EOR processes have been lumped together anddiscussed as improved oil recovery (IOR) processes to encompass all activities beyondprimary production. Generally the formation of a waterflood (WF) or EOR unit isfacilitated by the extremely reduced performance of the existing leases in the field underits previous recovery technique. Often the process of elimination makes the decision ofleaseholders to participate obvious.In Texas, the Railroad Commission’s energy policy famously incentives leaseholders tounitize. Regardless, the considerations mentioned here and above are necessary to justifyand accomplish this transition from primary recovery to a more engineered combinationof characterization, development, and recovery methods. Canadian regulators monitoreach oil field, and as each fields bottomhole reservoir pressure approaches bubble point,the operator of the field is ordered to shut-in the field until a pressure maintenance plan isapproved and being implemented for the field.China’s energy policy is even more aggressive. During field development, beforeextensive reservoir depletion, programs of water injection to maintain pressure and


displace oil to producing wells begin.Before launching the complicated study and economic expense of EOR, oil fields may bewaterflooded, with all the issues mentioned above. The unfavorable viscosity ratiobetween water and most crude oils enhances the bypassing of oil banks and prematurebreakthrough of water banks during WF. This secondary recovery process also providesinvaluable information regarding reservoir characterization, however.After economic performance of a waterflood unit becomes inadequate, the operator maypropose additional measures to increase the unit’s profit and producing life. Thesemeasures are collectively known as enhanced oil recovery (EOR) or tertiary recovery.Screening Producing Oil fields for WF & EORThe bases for planning and organizing a WF or EOR operation can perhaps be dividedinto these components: reservoir rock (depth, permeability, porosity, wettability) characterization oil properties (especially viscosity) reservoir drive mechanism water quality and availability analog field examination pilot projects, and Unitization.When screening oil fields regarding WF, heterogeneity, continuity, and non-oil-bearingreservoir volumes (“thieves” or “thief zones”) are dominant reservoir characterizationissues. The geologic thieves may be connected aquifers below the hydrocarbon columnand/or wet areas on its flanks.Due to the limitations of cement jobs, major WFs often inadvertently provide pressuremaintenance in uphole and even downhole reservoirs. These unplanned flows canenhance oil well performance, even on relatively distant adjacent leases. Theseoperations problems may also be regarded as thief zones. They are huge windfalls fornearby ventures receiving this free pressure maintenance.The accepted methods to screen a field or lease for secondary recovery (WF) arereservoir characterization and subsequent study of analog fields. Both these steps arebest taken in concert between engineering and geosciences. The next step beforeunitization for WF is the choice of an area of the field for a pilot WF involving areasonable number of injectors and producers. This and all other decisions preliminary tounitization are best made with input from any leaseholders willing to be involved.Water Drive, Disposal and Supply“Dad” Joiner’s discovery well the East Texas Field, Bradford No. 3, reached a depth of3,592 feet in the Woodbine sand on September 5, 1930, and flowed 300 barrels of oil perday, and was completed on October 5, 1930. This landmark discovery was followed bymultitudinous additional successful wells. 30,340 wells have been drilled within its140,000 acres. Located in central Gregg, western Rusk, southern Upshur, southeastern


Smith, and northeastern Cherokee counties in the east central part of the state, is calledthe largest and most prolific oil reservoir in the contiguous United States.The magnitude of the field’s reserves and productivity set off many unique precedent-setting events in understanding mechanisms of oil recovery (the primary recoverymechanism of water drive, for example), pipeline construction, and productionregulation. The price of a barrel of oil dropped from about $1.00 to $0.10 and belowduring the 1930’s.Roosevelt’s New Deal administration, the US Congress and Supreme Court’s crablikeattack of the “hot oil” problem combined with Texas executive, judicial, and legislativesteps to provide authority to regulate and limit oil and gas production to the TexasRailroad Commission. These were direct results of overproduction from the East Texasfield. By January 1, 1993, cumulative East Texas field oil production from was reportedas 5,145,562,000 barrels, perhaps not including huge volumes of “hot oil” stolen in the1930’s.Originally skeptical operators were convinced by 1938 that ultimate recovery of thefield's production depended upon the conservation of its water-drive mechanism. Theyinitiated a pressure maintenance program by re-injecting produced salt water into theaquifer, reducing the rate of pressure decline.Thus produced formation water had advanced from the status of inconvenience ornuisance to become an invaluable resource to sustain and limit decline of production.This was a crucial event in reservoir engineering management.Conservation of produced water can provide massive economic and logistical long-termadvantages in operation of oil fields. Early commencement of re-injection of producedwater from oil wells, and injection of water from water supply wells is now a hallmark offoresight in reservoir engineering, especially in Canada and China.Waterflooding & Hot Water InjectionA waterflood (WF) pilot or unit attempts to mimic the natural strong water drive, whichis one of the most efficient drive mechanisms observed in primary recovery operations.Waterflooding is also called secondary recovery. Banks of this injected water candisplace banks of oil toward producing wells wholesale. Reservoir rock heterogeneityand wettability cause some oil banks to be bypassed, however, as water banks breakthrough prematurely at production wells. This premature water breakthrough is greatlyenhanced when reservoir oil is many times more viscous than reservoir water. Thisviscosity contrast is called an unfavorable mobility ratio.Hot water injection, the most basic and probably the earliest thermal recovery techniqueuses water heaters at surface injection facilities to provide hot water for injection.Remember the term “hot” is relative, especially under cold surface conditions. Thewarming of water for injection can be a vital measure in its overall assistance to fieldoperations.Especially when some heavy oil or fractions are involved, accumulations of paraffin orother solids can be major themes in maintenance. Field facilities professionals routinely


employ “heater-treaters” to remediate problems with viscous or solid heavy crudes,lubricants, cements, or solids or break emulsions.The viscous/solid problem materials may include whatever crude or oils, solvents,cements, plastics, natural materials combine to contaminate a rental part or operatorproduction component. So, the ability to bring this practicality of heating water at awater injection site is a very important option. Combined with general detergents andindustrial chemicals to control injectant properties, heating water is just a routineindustrial activity.WF’s can also be augmented by using additives to increase the viscosity of injectionwater, thus reducing mobility ratio problem and premature water breakthrough, andconstituting an element of chemical flooding (CF).Why Waterfloods Under-performThe Petroleum Technology Transfer Council (PTTC) workshop on Permian Basin (PB)waterfloods presented these “top 10” list reasons why waterfloods under-perform: Misunderstanding reservoir heterogeneity: The carbonate reservoirs of the PB are

notoriously heterogeneous. Petrophysical and geological review of existing and new welllogs, including correlation of injection and production data are vital to refine descriptions ofthese porosity systems.

Injecting above formation fracture pressure enhances heterogeneity and prematurewater breakthrough. It can be avoided by automatic control of water injection systems andautomatic monitoring of wellhead pressures using satellite communication. IHS andcompeting vendors have this technology for hire; in-house networks may be contracted forprojects with well-counts above 100.

Incorrect perforations are always suspected in the old wells of PB waterfloods. High oil viscosity can result from the stripping of reservoir gas and energy during primary

production with depletion drive mechanism. The emerging EPARS technology help tomitigate this with crude oil analysis and well treatments to improve reservoir oil composition.

Insufficient lift capacity does not allow sufficient oil production. Early water breakthrough, an element of waterflood conformance, will be the subject of

constant study and vigilance. When water breaks through and eliminates oil production, awell is usually shut in and eventually converted to water supply or injection.

Out-of-zone injection, related to incorrect perforations, must be suspected. Underestimating fill-up volume when shut-in tubing pressures are about 15psi, all

reservoir natural gas will re-dissolve in oil, and waterflood will become effective. Insufficient water supply is related to several other topics above. Scale, bacteria, or other water quality issues that reduce injectivity benefit by analysis

of samples of water, scale, and corroded metal and service company consultations, toprovide adequate treatment for injection water and employment of optimum well treatments.

Wells are high-dollar investments that must remain healthy; they benefit fromcorrosion/chemical treating, material and metallurgy selection, rod handling, tubing androd inspection services, and careful surface facility design.Design and operation changes can remove moved unnecessary pressure drops in injectionsystems, thus significantly lowering horsepower requirements for injection pumps to


reduce power cost.According to PTTC, “When the chemical man, pump supplier, service rig, company man,etc., work together, well failure frequencies of fewer than 0.5 per well per year can beachieved, and some operators actually achieve rates of 0.25 per well per year or less.”Chemical Flooding (CF) IntroductionChemical flooding (CF), involving surfactants to reduce interfacial tension (IFT)between oils and water and polymer gels to increase water viscosity, is an augmentationof the waterflood process. CF has been the subject of major oil company and servicecompany research and development for many decades. Surfactants to reduce oil-waterIFT can act similarly to household detergents, dissolving oil fractions in the injectedaqueous phase. Engineered aqueous polymers increase water viscosity to reduceunfavorable oil-water mobility ratios. A variety of “recipes” has been researched, andmany have had field trials.Perhaps the most proven and successful CF method is the micellar or micro-emulsionflood, in which a slug of a stable solution of oil, water, alkalines or surfactant(s), and saltelectrolytes is injected to reduce interfacial and capillary forces. This slug then displacedby a slug of high-viscosity mobility control buffer polymer solution, and finally followedby slugs of water injection.Those micellar flood steps may be preceded by a “preflush” of low-salinity water.Synonyms for this process are micellar/polymer flooding and surfactant /polymerflooding.Alkaline Flooding and ASPPerhaps the most common acronym in CF is ASP for “alkaline surfactant polymer.”Alkaline (caustic) chemicals react with organic acids in certain crude oils in situ toproduce surfactants that dramatically lower IFT between oil and water, creatingemulsions to entrain and mobilize oil. These caustics also react with reservoir rocksurface to modify wettability. Caustic slug injection may be preceded by a “preflush” oflow-salinity water and/or followed by a viscous mobility-control slug injection.The alkaline flooding and ASP concepts deserve the increased attention they are currentlyreceiving. Some alkalines, like sodium hydroxide (NaOH, “lye”, or “caustic soda),famous for cleaning drains, dissolving organic matter, making soap, and its extremesolubility in water with liberation of heat, are so inexpensive as to lend themselves toeconomic performance in well-configured recovery processes.Alkaline industrial waste products are also readily available. Wood ash, for example, canbe processed to provide a low cost environmentally friendly alkali. Emerging laboratoryand field technologies to refine the designs of chemical floods should be especiallyeffective on alkaline flooding applications due to their potentially low chemical costs.Surfactants, Micelles, Type I Micro-emulsionsSurfactants are broadly defined as organic compounds that can enhance cleaningefficiency, emulsifying, wetting, dispersing, solvency, foaming, defoaming, and lubricityof water-based compositions. Surfactants are produced from petrochemical (synthetic)


feedstocks or oleochemical (biological) feedstocks. They can stabilize mixtures of oiland water by reducing the interfacial surface tension (IFT) at the interface between the oiland water molecules. Because water and oil do not dissolve in each other, a stablehomogeneous mixture (emulsion) requires a surfactant to keep it from separating intolayers. Soaps and detergents are surfactants. Sodium dodecyl sulfate (SDS) is anexample of a regularly studied anionic surfactant.The word "surfactant" is the shortened form of "surface-active agent.” Surfactantsaccumulate at interfaces due to their amphiphilic natures: The hydrophilic “head”segment (moiety) of a surfactant molecule (monomer) is polar, like water. Another “tail”hydrophobic moiety of the molecule is nonpolar, like oil. Surfactant moleculesaccumulate at the oil-water interface with their polar moiety in the aqueous phase andtheir non-polar moiety in the oil phase, minimizing Gibbs free energy.A surfactant solution has three components: surfactant monomers in the aqueoussolution, micellar aggregates, and monomers adsorbed as a film at the interface (surfaceof bubble, oil-water, etc.) The surfactant is in dynamic equilibrium among thesecomponents. Each micelle is a dynamic structure. When the aqueous surfactantconcentration exceeds critical micelle concentration (CMC), surfactant monomers self-aggregate into spherical or wormlike monomer aggregates called micelles.The micellar aggregate of “n” micelles has stability (relaxation time, nτr) in the range ofmilliseconds (ms) to seconds, breaking and reforming rapidly. A large relaxation timerepresents high micellar structure stability. Relaxation time correlates quantitativelystrongly with foaming ability, textile wetting time, bubble volume, emulsion droplet size,solubilization of benzene, etc.When discussing the molecular structures of surfactants, micelles, and oil and waterphases, an emulsion is called a microemulsion. An oil-in-water (Type I) microemulsioncan be formed with micelles’ polar micelle exteriors in contact with water phase, andnonpolar micelle interiors containing oil.Micro-emulsion Types II & IIIOil-based drilling fluids are composed primarily of diesel fuel, often configured as awater-in-oil (Type II) microemulsion. Oil-soluble surfactants form inverse micelles withtheir tails exterior and their heads interior, where water is trapped.In an oil reservoir, a surfactant will partition between oil and water phases according tothe monomer’s relative hydrophilicity; surfactant hydrophilic-lipophilic balance (HLB). Water-soluble surfactant mixtures with micelles have HLB’ of about 20. For transitional mixtures, 8 < HLB < 12. Oil-soluble mixtures with inverse micelles have HLB’s around 5.Chemical system conditions can be varied to force water-soluble surfactants to partitioninto the oil phase. For example, in an ionic surfactant system, increasing water salinitycan lower HLB and force surfactant monomers to partition into the oil phase. HLB’s fornonionic surfactant systems are decreased with temperature increases.At aqueous surfactant concentrations >10-20 times CMC, high micelle concentrations


can produce “middle phase” oil-in-water microemulsions with ultra-low oil-water IFC’sto mobilize oil trapped by IFC in a porous reservoir.To achieve a middle phase microemulsion (Type III) system, HLB is adjusted sosurfactant is ready to leave the water phase, but not to enter the oil phase, so themonomers accumulate at the surface. Since all the surfactant cannot fit in the interface, anew “middle” phase forms, containing oil, water, and virtually all the surfactant, inequilibrium with free oil and water phases. Theoretically, these middle phasemicroemulsions do not break with time, so their achievement under reservoirconditions is a very favorable goal.Surfactants in E&POther oilfield surfactant applications are: demulsifiers to separate oil and water by breaking emulsions, viscosity stabilizers lubricants, petroleum additives, engine-oil additives, fuel additives and dehazers organoclay intermediates, anti-swelling clay hydration inhibitors corrosion control, foam control, anti-fouling, anti-scaling KCl replacement, acidizer additive dispersants and deflocculation agents, wetting and suspending, biocides.These oilfield surfactants are involved in well stimulation, drilling, cementingcompletion, production, refining, and pipeline transport, as well as EOR.EOR and other downhole applications require surfactants that meet demanding down-hole environmental regulations and performance requirements. Emulsifiers to allow oiland water to mix perhaps require the majority volume of oilfield surfactants. Thedramatic rise in oil and gas prices, peaking in 2008, caused significant increases in EORactivity and demand for more effective EOR processes and materials.This has stimulated market demand for specialty, higher cost surfactants such as cationicsand amphoterics (anionic or cationic depending on conditions). These are more costlythan nonionics and anionics (negative charge on surface-active moiety) but perform moreeffectively.Interest in use of surfactants for EOR in HO and bitumen reservoirs is beginning tocompete with traditional emphasis of thermal recovery of heavy oil (TRHO).Polymers, Gels, and GelationPolymers, macromolecules, high polymers, and giant molecules are high-molecular-weight materials composed of repeating subunits. Natural organic polymers includepolysaccharides (or polycarbohydrates) such as starch and cellulose, nucleic acids, andproteins.A gel is a continuous solid network enveloped in a continuous liquid phase; the solidphase typically occupies less than 10-volume % of the gel. Gels can be classified interms of the network structure. The network may consist of agglomerated particles(formed, for example, by destabilization of a colloidal suspension; a “house of cards”consisting of plates (as in a clay) or fibers; polymers joined by small crystalline regions;


or polymers linked by covalent bonds.In a gel the liquid phase does not consist of isolated pockets, but is continuous.Consequently, salts can diffuse into the gel almost as fast as they disperse in a dish of freeliquid. Thus, the gel seems to resemble a saturated household sponge, but it isdistinguished by its colloidal size scale. The dimensions of the open spaces and of thesolid objects constituting the network are smaller (usually much smaller) than amicrometer.Thus the interface joining the solid and liquid phases has an area on the order of 1000 m2

per gram of solid. As a result, interfacial and short-range forces, such as van der Waals,electrostatic, and hydrogen bonding, control the properties of a gel. Factors thatinfluence these forces, such as introduction of salts or another solvent, application of anelectric field, or changes in pH or temperature, affect the interaction between the solidand liquid phases.The process of gelation, which transforms a liquid into an elastic gel, may begin with: a change in pH that removes repulsive forces between the particles in a colloidal

suspension, or decrease in temperature that favors crystallization of a solution of polymers, or the initiation of a chemical reaction that creates or links polymers.Conversely, the reason that water cannot be gently squeezed out of such a gel is that thenetwork of solids has a strong affinity for the liquid, and virtually all of the molecules ofthe liquid are close enough to the solid-liquid interface to be influenced by thoseattractive forces.The most striking feature of a gel is its elasticity. If the surface of a gel is displacedslightly, it springs back to its original position. If the displacement is too large, gels,except those with polymers linked by covalent bonds, may suffer some permanent plasticdeformation, because the network is weak.Oilfield Polymers and GelsCommercial oilfield polymers include solid beads to adsorb hydrocarbons as well as gels.The gels are available in both dry powder and very dense and viscous “liquids.” XanthanGum, for example, is a polysaccharide biopolymer well known to have excellentperformance in high salinity brine.“Standard” EOR polyacrylamides have molecular weights in the >12,000,000 range andare suited for bottomhole temperatures <90°C. Sulfonated copolymers of acrylamide andsodium salt of acrylamide propyl sulfonated acid, suited for EOR applications withbottomhole temperatures >90°C, have molecular weights in the <12,000,000 range.Oilfield gels are used to increase viscosity of an aqueous drilling fluid or EOR injectant.Less expensive starch gels are adequate for many routine drilling fluid requirements.When more expensive polymer gels are used, the 5-gallon buckets of polymer gel areheavy; the gel concentrate is dense, very viscous, and very thixotropic (sticky).Working directly with these polymer gels is physical challenging on wellsite; the gel doesnot want to leave the bucket, sticks to personnel and equipment, and needs specialized


mixing equipment to be uniformly dispersed in drilling fluid. Emulsion gels havecolorful wellsite names like “whale snot.”Microbial EORLabs are engineering microbes that react in situ with reservoir oils to biochemicallygenerate surfactants and CO2 downhole (see miscible EOR processes below). Themicrobes can be cultivated underground or in wellsite surface vats; some growexplosively. US DOE and Canadian CERA are funding MEOR research in hopes thatMEOR technologies become cost-effective and environmentally advantageous.MEOR is already used in Venezuela, China, Indonesia, and the U.S. to treat HOreservoirs. Researchers hope to develop improved microbial species to inoculatereservoirs and modify the difficult properties of HO and bitumen.Microbial technologies are also proposed to reduce use of harsh chemicals during oil welldrilling. Genetic engineer’s goals are more effective bacteria to subsist on abundantinexpensive nutrients.In an MEOR process downhole, conditions for microbial metabolism are supported viainjection of nutrients. This may involve injecting a fermentable carbohydrate into thereservoir. Some reservoirs also require inorganic nutrients as substrates for cellulargrowth or as alternative electron acceptors in place of oxygen or carbohydrates.

Figure 12. Illustration summarizing total US EOR production history indicates that productionfrom thermal recovery, including TRHO to recover heavy oil, is decreasing steadily. EORproduction from “gas injection”, including CO2 injection, may increase, but not sufficiently tooffset the decrease of thermal recovery production. Emerging priorities for CO2 sequestration,however, may spur additional CO2 injection projects, including those without potential for oil-CO2 miscibility to make miscible displacement possible. Chemical flooding (CF) production isnot significant.


MEOR processes are applicable to 40-50% of North American oil reservoirs. Reservoirconditions restricting MEOR applications are: high total salinity (above 12%) high reservoir temperatures (above 50 C), and very low permeability.While some microbes grow inside of these environmental parameter ranges, fewsuccessful MEOR projects have been in such reservoirs.Biotechnology may soon take greater advantage of extremophiles — microorganismsthat grow in high salt or heavy metal concentrations, or at extremes of temperature,pressure, or pH. These organisms could support process operation over a wider range ofconditions. However, extremophiles present challenges for the development of industrialbioprocesses, such as slow growth, low cell yield, and high shear sensitivity.Potential hazards of using microbes for drilling, environmental remediation, and/or EORinclude migration of microbes and/or metabolites into groundwater, use of brine andother media and pH adjustment chemicals, emissions of H2S, and solid waste issues.In addition to steps in “Screening Producing Oil fields for WF & EOR” section above, inan MEOR investigation, reservoir oil and water samples are analyzed to pick microbesand processes supportable in the oil reservoir and augmented cultures which survive andperform desired in situ metabolic function(s) are determined. Field demonstration projectis then designed to confirm success of selected MEOR mechanism(s). If demo issuccessful, laboratory, consultants, and operator can consider an MEOR pilot project.http://peswiki.com/index.php/Directory:Microbial_Enhanced_Oil_Recovery

CF EOR SummaryHistorically, CF has perhaps been a stepchild in the family of EOR processes. In 1983,Slider quoted HK van Poollen & Associates, "Although much laboratory work has beendone, no field project has as yet been reported as economic."CF has benefited, however, from the intense chemical research of O&G product refiningand distribution sectors. These sectors’ development of detergents and polymer gels fortheir huge array of industrial customers has produced profit centers, which subsidizedtheir development of CF agents.CF importance and interest surges whenever very high oil prices become sustained. Arange of laboratory and field technologies is emerging to refine the designs of chemicalfloods.Miscible EOR (CO2) Processes:The most successful EOR processes for recovery of light and intermediate crudes arevarious forms of miscible displacement using CO2. An injectant is chosen to mixdownhole with residual crude oil. The miscible component of injectant is called a“solvent”; it is usually some combination of CO2 with anything inconvenient for the EORsurface gas processing plant to remove. These additional gases may include methaneCH4, and contaminants: hydrogen sulfide (H2S), sulfur dioxide (SO2), and even Nitrogen(N2).


CO2 flooding processes can be classified as immiscible and miscible, even though CO2and crude oils are not miscible upon first contact at the reservoir. Recovery mechanismsin immiscible processes involve reduction in oil viscosity, oil swelling, and dissolved-gasdrive. In the miscible process, CO2 is effective for improving oil recovery for a numberof reasons. While not 1st-contact miscible, CO2 is very soluble in crude oils at reservoirpressures; therefore, it swells the oil and reduces oil viscosity.

Figure . Condensing/vaporizing mechanisms for a multiple-contact miscibility processbetween compressed CO2 and reservoir crude oil.http://txspace.tamu.edu/bitstream/handle/1969.1/4138/etd-tamu-2005B-PETE-Garcia.pdf?sequence=1

Miscibility between CO2 and crude oil is achieved through a multiple-contact miscibilityprocess. Multiple-contact miscibility starts with dense-phase CO2 and hydrocarbonliquid. The CO2 first condenses into the oil, making it lighter and often driving methaneout ahead of the oil bank. The lighter components of the oil then vaporize into the CO2-rich phase, making it denser, more like the oil, and thus more easily soluble in the oil.Mass transfer continues between the CO2 and the oil until the two mixtures, vaporizingoil and condensing CO2, become indistinguishable in terms of fluid properties. Becauseof this mechanism, good recovery may occur at pressures high enough to achievemiscibility. Figure illustrates the condensing/vaporizing mechanisms for a multiple-contact miscibility process Marylena Garcia Quijada reviews of the perfect example ofsuccessful CO2 flooding in her 2005 Master’s Thesis.In general, high downhole pressures are required to compress CO2 to a density at which itbecomes a good solvent for the lighter hydrocarbons in the crude oil. This pressure isknown as minimum miscibility pressure. (MMP) and it is the minimum pressure atwhich miscibility between CO2 and crude oil can occur.CO2 Flood Logistics & OperationsObtaining a CO2 supply was the first hurdle jumped in the logistics to create CO2 floods.The development of Bravo Dome in NE New Mexico, with its pipelines to large PermianBasin WF’s, was perhaps the milestone event heralding commencement of full-scalemiscible displacement projects. Additional fields in the 4-Corners area and Mississippihave served to swell the ranks and production volumes of CO2 injection projects.


Regarding miscible EOR processes and field conformance, major conformance issues Ihave seen repetitively include these issues:Premature solvent (CO2) breakthrough in volumes so large as to overload the surface CO2 processing plant, indicate excessive bypassing of reservoir oil by injected CO2.

Figure . Map illustrating the US States studied by DOE for EOR with CO2. Basin-orientedassessments estimate 89 billion additional barrels recoverable. Schematic cross-sectionshows the water-alternating-gas (WAG) process.Note that bypass of oil by injected CO2 is serious; only those volumes of CO2 whichactually contact reservoir oil can mix with the downhole oil to accomplish lower oil viscosity (thinning) increase oil volume (swelling).Of course, these are the reasons for the “injecting water” part of water alternating withgas (WAG) studied and employed so widely in simulations, Pilots, and Units include: Maintenance of oil reservoir downhole pressure Reduction of downhole miscible gas mobility, thus remediating premature CO2

breakthrough, and Displacement of downhole oil banks by banks of injected water.Another conformance issue I see frequently is the alteration of reservoir rock at injectionwells due to chemical leaching and processes associated with high injection rates,enlarging pores and increasing injectivity.The most constant and frequent issue I have observed in fields using CO2 WAG iscorrosion, both uphole and downhole (especially in production wells and facilities).Brine or brackish water, of course, causes corrosion in a waterflood. The copious waterdownhole in a waterflood converted to a CO2 flood becomes carbonated, and theresulting carbonic acid is even more corrosive than formation or injection water.Add a little H2S downhole and/or in CO2 stream, and completions & facilities may seemto disintegrate before your eyes!Screening Oil-CO2 MiscibilityIn addition to operating problems detailed above, establishment of miscible displacementin a WF involves very detailed screening for oil oil-CO2 miscibility under reservoirconditions.


In a successful miscible displacement, CO2 is not a gas in the reservoir. To becomemiscible, CO2 must exist in the reservoir at sufficiently high pressure and temperature toexist in a dense liquid-like phase. Unless an EOR project achieves oil-CO2 miscibility inthe reservoir, CO2 in contact with oil will only achieve some swelling and viscosityreduction and perhaps crude vaporization.Inferior performance is expected when CO2 is injected without miscibility. Emergingpriorities for greenhouse gas sequestration might greatly increase the volume of thesenon-miscible projects, however, and additional oil recovery would be likely.Downhole miscibility of CO2 requires a minimum bottomhole reservoir pressure of about1500psi. The oil-CO2 minimum miscibility pressure (MMP) correlates inversely withAPI oil gravity, increasing as oil becomes heavier. Miscibility fails to occur at anypressure at about API gravity < 22.The MMP requirement also fails for reservoirs shallower than about 2,500’, for oils ofAPI gravity > 40. Heavier oils at 22 < API gravity < 32 require reservoir depths of about4,000’ to 2,800, respectively.Precise experimental oil-CO2 MMP measurements are performed in specializedlaboratories, and have required generations of research for their development.Computational estimates of oil-CO2 MMP’s also continue to be topics of intenseresearch.Experience with many CO2 floods in the Permian Basin of West Texas has yielded twoRules of Thumb for recovery efficiency under CO2 flooding. Incremental recovery frommiscible CO2 flooding can be estimated as: 10% of original oil in place, OOIP, or 25% of primary and secondary recovery combined. NOTE: when combined, these estimates predict that 50% of the OOIP is left abandoned in

the reservoir after tertiary recovery! Remember, however, that recovery efficiency issensitive to the price of oil and other economic parameters.

EOR for HO Fields: TRHOMany of the known HO deposits exist in sandstone reservoirs; CA’s most prolific oilfields are examples. Thus, the use of water or steam for downhole injection may activatedownhole clay minerals, causing these clays to swell. This swelling is a notoriousmechanism to reduce formation permeability by the blocking pore throats by swellingand/or migrating clay crystals. Water must be procured and treated for injection, andmotors must be operated to inject the water.Industry introductions of thermal recovery of heavy oil (TRHO), steamfloods (SF) andcyclic steam injection (CSI), were based on waterflood experience and/or use of heat tohandle oil on surface production facilities. Steam was generated at the ground surfaceand substituted for water as an injectant as in a waterflood. When a bank of super-heatedsteam progresses in an oil reservoir, oil viscosity is reduced as temperature increases. Reservoir pressure is increased through


additional water volume partial distillation of the oil.

Whether SF or CSI was introduced first is not clear. The discovery of the SCI process isattributed by at least one source to a steamflooding accident in Venezuela noticed byShell in 1959. I suspect this was the independent discovery of a secret proprietary andconfidential unpatented stimulation treatment already being performed behind lockedlease gates in CA and perhaps elsewhere.By 1966 the Kern River Field’s production rate had exceeded its 1904 rate of 47,100BBL/day. This California achievement almost matched the total daily oil production rateof the entire State of Texas!Cyclic Steam Injection (CSI)The most basic step in TRHO is cyclic steam injection (CSI). This is a single-wellstimulation method in which high-pressure steam is generated at the ground surface forinjection into 1 or more wells. After a period of injection into each well, the same well istemporarily converted to a period of production.Between steam injection and production periods there is an idle period, allowingadditional fluid flow and heat transfer, leading to the term “Steam Soak.” This cycle isrepeated while recovery is economic; it is also called “huff ‘n’ puff.”Advances in the details improving the CSI option of TRHO were introduced anddeveloped in prolific HO deposits like the Kern County area of California (CA),Venezuela and Indonesia. Many of the legendary CA producing fields were identifiedaround 1900, so today they are some of the most super-mature assets in the USA, leavingremaining recoverable reserves as low as 20% of Original Oil in Place (OOIP).Regardless, at least 1 billion barrels of oil are likely to remain in these fields.As a single-well stimulation process, CSI requires relatively little increase inpetrophysical, geological, and reservoir study over those conducted for primary recovery.CSI is normally applied to wells proved as previous producers under primary recovery.Since it effects a region of limited extent around a single wellbore, its effectivenesseventually declines over its period of application.Wellbore heat absorption limits CSI formation depth to less than 3,000ft (1,000m). Therequirement of surface steam generation depends upon the procurement and treatment ofwater for injection, the use of natural gas to generate steam from said water, and themanagement of related environmental issues.Steamflooding (SF)CSI has continued as a mainstay of TRHO, holding steady in CA during the period ofrelatively low oil prices in the Industry slump ending in 2005, for example. During thisperiod WF recovery declined in CA. The employment of more advanced techniques suchas Steamflooding (SF) and In-Situ Combustion (I-SC, also called Fireflooding) has beenin flux over the same period.The Steamflood rationale combines some waterflooding principles and some CSIprinciples. Downhole injected steam warms the oil to reduce its viscosity. This effect is


reduced by absorption of steam heat by the reservoir rock, water, wellbore, and adjacentformations. Employment of SF has gradually increased since 1995; these SF projectsoften enhance or replace CSI processes.As for CSI, wellbore heat absorption limits formation depth for SF to less than 3,000ft(1,000m). Steam condenses downhole to yield liquid water. As with CSI and WF, thesewet processes have dangerous possibilities of clay activation. Their requirement ofsurface steam generation depends upon the procurement and treatment of water forinjection, the use of natural gas and treated water to generate steam, and the managementof related environmental issues.Regarding reservoir characterization, SF benefits from all the attention to petrophysics,geosciences, and reservoir study, pilot and unitization required for optimized WF.Conformance of the WF is invaluable characterization data.The financial expenses and the physical issues are so enhanced for SF, however, thatcharacterization must be truly sophisticated during the screening, pilot, and unitizationphases. Loss of effective injection to various thieves and injectant bypassing oil nolonger involves only treated water and its injection horsepower, but also heating cost andthe increased complexity of SF facilities.In-Situ Combustion (I-SC, or fire flood)The incentives to reduce uphole heat loss, clay activation, and various environmentalissues have accumulated to motivate research and production personnel to seekalternatives to the wet methods mentioned above.So, the In-Situ Combustion (I-SC) process, also called fire flood or fireflood, hasbenefited from considerable analysis, experiment, and discussion. In-situ combustion is aflameless dry process. As a bare minimum, oxygen (O2) must be injected. O2 (pure,atmospheric with Nitrogen, staged or otherwise combined) then reacts with a downholefuel flamelessly to heat the reservoir rock and HO.Reliance upon reservoir HO alone as a downhole fuel is a convenient notion, butprobably impractical. Methane, a solvent, and/or other staged and/or optimized additivesare probably required to engineer this combustible injectant. Note that CH4 and O2combine to form CO2 and H20 in combustion, along with at least traces of CO (carbonmonoxide) and perhaps O3 (ozone), so such a process is not completely dry! CO2 is, ofcourse, desirable since it will dissolve in water and oil at low pressures. Larger fuelmolecules would yield more complex combustion product compounds.Theoretically, I-SC avoids wellbore heat loss, most of the water involved with CSI andSF, and some surface environmental issues. I-SC introduces, however, many complexphysical issues like ignition method, choice of fuel(s), choice of O2 or mixture, sources ofthese, the flameless processes visualized downhole, and the details of their effects onrock and HO.Toe to Heel Air Injection (THAI™)Toe to heel air injection (THAI) is a new method of extracting oil from heavy oildeposits, which may have significant advantages over existing methods, including


previous I-SC implementations. The method was developed by Malcolm Greaves of theUniversity of Bath and has been patented by Petrobank.THAI™ is an evolutionary new combustion process that combines a vertical air injectionwell with a horizontal production well. During the process a combustion front is createdwhere part of the oil in the reservoir is burned, generating heat, which reduces theviscosity of the oil, allowing it to flow by gravity to the horizontal production well.The combustion front sweeps the oil from the toe to the heel of the horizontal producingwell, recovering an estimated 80 percent of the original oil-in-place, while partiallyupgrading the crude oil in-situ. Combustion continues as long as air is injected, estimatedat about five years. Combustion gasses bring the mobilized oil and water to the surface,so no pumps are needed.Water and natural gas are used during the first three months to create steam injected invertical injection well. After this initial period, for the estimated 5-year project life,neither water nor natural gas is used. The second quarter test report indicates oil cut isover 50%. No new water is added after the first three months; produced water combinescondensed previous steam, reservoir water, and combustion product.Petrobank estimates that THAI will recover 70% to 80% of oil originally in place(OOIP). If 10% of the oil originally in place were burned in the process, this would leave10% to 20% of the oil originally in place in the ground.According to the Petrobank website, besides yielding 70% to 80% recovery efficiency,THAI can be used in many areas where steam methods cannot: Thinner reservoirs, less than 10 meters thick Where top or bottom water is present Where top gas is absent Areas with "shale lenses" that act as barriers to steam, In general, lower pressure, lower quality, and deeper reservoirs than current steam-based

processes.By comparison, recovery using current steam processes is estimated to be 20% to 50% inthe high-grade, homogeneous areas where steam methods can be used.Dilution of HO for PipelinesExtra-heavy oil requires addition of diluents (gas condensate, natural gas liquids, or lightcrude) to enable pipeline transport. Extra-heavy oil must also be chemically upgraded toreduce density and remove contaminants for refinery feedstock. In recent VenezuelanOrinoco heavy oil belt projects, 1 barrel of diluents is required for every 3 or 4 barrels ofextra-heavy oil produced.Horizontal wells and optimally positioned lateral branches equipped with improvedelectrical submersible or progressing cavity pumps can deliver up to 2,000 BO/day in theVenezuela’s Orinoco heavy oil belt. Horizontal well costs dropped in recent years, andthis extra-heavy crude oil is commercial.Fuel use for reservoir injection and facilitating transport to upgrading facilities is stillsignificant. In 2001, concession operators still planned to increase Orinoco production to


600,000 barrels of extra-heavy oil per day by 2005, however, and to sustain that rate for35 years.(Petroleum Review, 2001, v. 55, no. 653, p. 30).Surfactants, HO, & BitumenIn Venezuela, from 1980 to 1984, PDVSA, jointly with British Petroleum, developed anew method to reduce the high cost of transporting bitumen by pipeline. This effortresulted in new and simple technology to process Cerro Negro bitumen, known asOrimulsion. In this proprietary process the bitumen is mixed with water and a surfactantchemical in order to produce a stable emulsion, which can be transported by pipeline andby ship in a similar way as fuel oil.Orimulsion is an emulsion of approximately 70% natural Cerro Negro bitumen 8.5° APIsuspended in 30% fresh water by means of mechanical energy and the addition of lessthan 1% alcohol-based surfactants (emulsifiers) that allow the bitumen droplets to remainsuspended in a stable mode. This product can be easily handled at room temperature andwith standard equipment. Furthermore, the presence of water improves the combustioncharacteristics of the natural bitumen. PDVSA’s BITOR division enjoyed massiveinternational success due to Orimulsion’s combination of: sufficiently low viscosity to allow routine transportation of Orimulsion extremely successful combustion characteristics, allowing direct use as fuel.PDVSA decided in August 2003 that it was dissolving BITOR into PDVSA's easternoperating division and not expanding production of Orimulsion because it could makemore profits from Venezuelan extra-heavy oil and bitumen selling blends or syncrudeinstead of Orimulsion.PDVSA intended to fulfill long-term contracts, which BITOR had with utilities inCanada, Denmark, Italy, and Japan, but to discontinue any contracts in negotiation andclose UK, UE, and North American operations. This leaves a huge vacuum for relatedtechnologies to replace Orimulsion.www.soberania.org/Articulos/articulo_1375.htm

Recent research (Piero Baglioni et al) indicates that relatively slight modifications tosurfactant molecular structure can promote reduction in both viscosity and density in anemulsion. Such research applied to oilfield surfactants could yield valuable applicationsfor surfactant use in EOR for HO and bitumens. See Appendix 10.“Dead” Oil and Recovery EfficiencyOver 1,800,000 crude oil wells have been drilled and brought into production in theUnited States in the past 125 years. Over 90% of the wellheads in the Global well countare in the Lower 48 states.Most of the large oil fields of the US lower 48 states are very old. Many of the smalleroil fields are also quite old. Those not already on waterflood may soon be unitized forthis. Recall, however, that many sandstones contain sensitive reservoir clays whichmigrate and/or swell when contacted with water. Before implementation of waterflood,prolonged and pronounced reduction of reservoir pressure under DGD has rendered the


crude oil “dead”, lacking methane and intermediate hydrocarbons, and thus more viscousand dense than its original character.Yet, of the 430,000,000,000 barrels of crude oil proven to be in place within the variousoil-bearing formations throughout the United States and Canada, no more than 25% ofthat crude oil, on the average, has actually been recovered, leaving about 325,000,000,00billion barrels of crude oil still in place within the various rock formations.Stripper Wells in the USIn the United States of America, one out of every six barrels of crude oil produced comesfrom a marginal oil well, and over 78 percent of the total number of US oil wells are nowclassified as such. There are over 400,000 of these wells in the United States, andtogether they produce nearly 900 thousand barrels of oil per day, 15 percent of USproduction. These are known as stripper wells.Many of the huge population of stripper wells lie in these fields; some are tinyaccumulations known as “single-well fields.” Until a field reaches a critical size withquite a few wells, unitization for waterflood is not feasible, though many tiny fields,which include water disposal wells, have constituted tiny waterflood pilots.Between 1994 and 2003, approximately 142,000 marginal wells were plugged andabandoned. The resultant loss in oil revenue is significant: more than $3.0 billion in lostoil revenue at the 2003 average world oil price. Until improved economics occurs,especially based on oil pricing, these wells cannot be replaced by drilling replacementwells. During this interminable period local, regional and National payrolls, rental fees,property taxes, and balance of trade are lost. Some may even be temporarily abandoned(TA) or permanently abandoned (plugged and abandoned) (PA, or P&A), “brownfield,”wells.Unitization for waterflood and EOR helps to reverse this trend, but is often not feasibledue to geologic or environmental limitations. Industry badly needs new EORalternatives. Petroleum geochemists have investigated long and hard to provide analysisand operations to bridge the gap between a stripper well and enhancement of itseconomics and longevity.http://stripperwells.comAn Emerging EOR Chemical Flooding ProcessOne such bridge is a proprietary technology presented by EPRS Energy. Dr. R C Ropp,VP of Technical Affairs, Fellow and Certified Chemist of The Royal Society ofChemistry (London) has patented this process. EPRS performs the patented chemicalanalysis to characterize each specific accumulation of crude oil.A concentrated stimulation treatment chemical is then designed specifically for theaccumulation at hand, and EPRS sends a team to that specific location to implement thattreatment. About a barrel of this aqueous chemical concentrate is injected per well,followed by a “chaser” slug of 15-20 barrels of water to displace and dilute theengineered concentrate.A reaction between heavy components of the crude oil’s hydrocarbon molecular weight


range and the contents of the engineered concentrate forms natural gas downhole. Theresult of this effect can be compared to TRHO’s “distillation,” Miscible Recovery’smixing, or even the catalytic cracking reactions performed in petrochemical refineries.Reservoir crude oil is thus depleted of these unfavorable heavy fractions and restoredwith light hydrocarbons. Some of the restored methane and intermediates dissolve in theenhanced reservoir crude, and some remains as a free gas phase downhole.The reservoir crude oil is thereby rendered less dense and less viscous. API Gravity isincreased. Reservoir and wellhead pressures increase. Post-treatment wellhead pressuresas high as 1600psi have been achieved.EPRS has experimented with about 65 different crude oils from all over the US and hasgenerated significant gas volumes from each. The EPRS chemical flooding technologyexhibits considerable potential to accomplish these effects in accumulations of heavy andextra-heavy crude oils. This may extend even to tar sands, bitumens, and even thekerogens in “oil shales.” EPARS is one E&P’s newest alternatives in the field of EOR.EOR and CO2 SequestrationNew opportunities for environmental remediation, increased oil production, and jobcreation are emerging due to recently identified global and US priorities to reduceemission of greenhouse gases into the atmosphere. Naturally, CO2 withheld from suchrelease must be impounded (sequestered) somewhere.The mature and successful EOR technique of miscible displacement relies primarily onprograms to inject CO2 into oil reservoirs as a “solvent” to mix and dissolve withreservoir oil, including additional injection of various grades of water for reservoir fluidmobility control. There is a growing inventory of existing CO2 sequestration EOR (CO2-S-EOR) projects, and an expanding volume of related literature on screening for and co-optimization of new CO2-S-EOR opportunities.Energy and environmental agencies have strong interest in co-optimization of EOR bygas injection and greenhouse gas sequestration (EOR-GGS) by disposal of CO2, CO,oxides of nitrogen, H2S, SO2, etc., as exist in flue gases and especially in output of oil andgas processing plants. There are enough EOR-GGS examples around the world (Algeria,Australia, Canada, Norway, etc.) in operation or post-proposal stages to help EPRS avoidprevious wrong turns in planning. Two prominent Canadian projects are the widelypublicized Weyburn Pilot Project in Saskatchewan and the much more interesting Zamaoil field in Alberta.The Zama Field project injects both CO2 and H2S from its nearby processing plant intothe top of a Devonian pinnacle reef. Oil is produced from a completion near the reefbottom, making this project somewhat gravity-stable. A shallower well serves to monitorleakage of these “acid gases.”These projects also use the term “carbon sequestration.” E&P companies are prepared toseek industrial sources of CO2 and other greenhouse gases (especially output from gasprocessing plants which scavenge these gases from crude oil and/or natural gas, andperhaps flue gases from power stations), and to formulate plans to sequester these


undesirable emissions underground.Flue Gas & Greenhouse GasesNew opportunities for environmental remediation, increased oil production, and jobcreation are emerging due to recently identified global and US priorities to reduceemission of greenhouse gases into the atmosphere. Naturally, CO2 withheld from suchrelease must be impounded (sequestered) somewhere.The mature and successful EOR technique of miscible displacement relies primarily onprograms to inject CO2 into oil reservoirs as a “solvent” to mix and dissolve withreservoir oil, including additional injection of various grades of water for reservoir fluidmobility control. There is a growing inventory of existing CO2 sequestration (CO2-S)EOR (CO2-S-EOR) projects, and an expanding volume of related literature on screeningfor and co-optimization of new CO2-S-EOR opportunities.

US Flue Gas LocationsEnergy and environmental agencies have strong interest in co-optimization of EOR bygas injection and greenhouse gas sequestration (EOR-GGS) by disposal of CO2, CO,oxides of nitrogen, H2S, SO2, etc., as exist in flue gases and especially in output of oil andgas processing plants. There are enough EOR-GGS examples around the world (Algeria,Australia, Canada, Norway, etc.) in operation or post-proposal stages to help EPRS avoidprevious wrong turns in planning. Two prominent Canadian projects are the widelypublicized Weyburn Pilot Project in Saskatchewan and the much more interesting Zamaoil field in Alberta.


The Zama Field project injects both CO2 and H2S from its nearby processing plant intothe top of a Devonian pinnacle reef. Oil is produced from a completion near the reefbottom, making this project somewhat gravity-stable. A shallower well serves to monitorleakage of these “acid gases.”These projects also use the term “carbon sequestration.” E&P companies are prepared toseek industrial sources of CO2 and other greenhouse gases (especially output from gasprocessing plants which scavenge these gases from crude oil and/or natural gas, andperhaps flue gases from power stations), and to formulate plans to sequester theseundesirable emissions underground.So, actual feasibility of co-optimizing EOR, especially the gas-injection processes ofimmiscible and miscible displacements, is a crucial issue to be questioned in everyrealistic sense. Characterization of flue gas compositions, especially flue gases from the gas-fired and coal-

fired power plants which dominate the US power utility industry. Can flue gases bedirectly injected into oil reservoirs for these EOR processes?

If processing is required to prepare flue gases for EOR injection, what are the nature, scale,and expense of these processes? Will existing flue gas processing methods be adequate,or must additional techniques be researched?


US Locations for Geological CO2 Sequestration


Flue Gas CompositionCO2 is NOT the only greenhouse gas: nitrogen oxides, NOX, are considered MUCHmore hazardous, for example. Unprocessed flue gases are seldom good candidates forEOR by gas injection due to their very high (78-80%) atmospheric nitrogen (N2)content.Fuel Choices & OSHA:

Chemical SpeciesOSHA TWA*ceiling, ppm

NaturalGas

Fuel Oil Coal

Nitrogen, N2 78-80% 78-80% 78-80%Carbon dioxide, CO2 5000 10 – 12% 12-14%

Oxygen, O2 2-3% 2-6% 7%

Carbon monoxide (CO) 50 70-110ppm 70-160ppmNitrogen oxides (NOx) NO-25, NO2-5* 50-70ppm 50-110ppm 1%

Ammonia, NH3 50 Used in removal of NOx.

Sulphur dioxide (SO2) H2S-20*, SO2-5 180-250ppm >2,000ppm

Hydrocarbons (CXHY) <60ppmMercury, Hg >200lb/year/plant

Fly Ash none minimal 12%

Table. Summary of flue gas composition ranges for power plants fueled by gas, oil andcoal. Given these inconvenient contaminants it is no surprise that EOR by flue gas injectionhas been discontinued, sometimes converted to nitrogen injection, in most projects whichattempted that EOR implementation. OSHA’s TWA limits are allowed for 8-hour personnelshifts. OSHA’s Ceiling limits should not be exceeded at any time for personnel.Flue Gas ProcessingAn example of flue gas processing sequence is: While flue gas is still hot, incineration under controlled temperature and pressure in a

chamber, which may include a catalyst system, perhaps injecting a reagent, can producerequired chemical reactions. Incineration reaction results depend on composition,temperature, pressure, catalysis, and residence time for which these conditions apply.

Co-generation heat exchangers can scavenge heat from this hot gas and provide cooling. Sorbents like activated carbon, lime, or sodium salts, can be injected to adsorb mercury or

SO2 gases. Electrostatic precipitators (ESP’s), wet or dry, can capture particulates like sorbents, fly ash,

or soot, in a wide range of temperatures. These devices have been adapted to “ionic”household air cleaners.

Wet scrubbers can accept high-temperature moist flue gas to remove particulates and/orgaseous contaminants.

Dry scrubbers (cooling followed by carbon, lime or sodium reagent injection, and fabric“baghouse” filter) can remove particulates.

Carbon monoxide, CO, is a colorless, odorless gas which is tasteless and non-irritant. It issomewhat less dense than air and, although it is a product of imperfect combustion, it is


inflammable. Carbon monoxide, like oxygen, has an affinity for iron-containingmolecules, and it is about 210 times more effective in binding to iron-containinghaemoglobin than oxygen. Blast furnace gas contains 25% carbon monoxide. Coal gas,which was used as a fuel in Europe up until North Sea (natural) gas became plentiful,contains 16% CO.Processing Flue Gas NOx

Nitrogen oxides (NOx) occur in all fossil fuel combustion, through oxidation ofatmospheric nitrogen (N2) and also from organic nitrogen fuel content, and flue gas NOxconcentrations are enhanced by high combustion chamber temperatures. Nitric oxide(NO) oxidizes with time and forms nitrogen dioxide (NO2), a brown, toxic, water-solublegas that can seriously damage the lungs, contributes to acid rain and helps to form ozone.With or without Selective Catalytic Reduction (SCR), ammonia (NH3) ions react withboth species:

4NH3 + 6NO 5N2 + 6H2O,8NH3 + 6NO2 7N2 + 12H2O.

Use of ammonia in NOx reduction technologies or for flue gas conditioning can have asubstantial balance-of-plant impact on coal-fired plants. Ammonia adsorbs on fly ashwithin the flue gas processing system as both free ammonia and ammonium sulfatecompounds, however.This ammonia can then desorb during subsequent transport, disposal, or use of the flyash. This desorption of ammonia presents several technical and environmental concernsas fly ash disposal occurs in surface water and landfills. SCR can optimize the NH3-NOxreduction with a minimum of downstream problems developed by ammonia slip.Processing Flue Gas SO2

Almost all hydrogen sulfide, H2S (OSHA “ceiling” = 20ppm), oxidizes within a day toSO2. SO2 is smelly, toxic, and contributes to acid rain. SOX can be removed from fluegas by dry alkaline adsorption before particulate removal.Addition of sodium bicarbonate into the flue gas causes it to react in the followingmanner:

2NaHCO3 Na2CO3 + H2O + CO2.This allows for the sodium carbonate to react with the oxygen and sulfur dioxide in theflue gas to form sodium sulfate and carbon dioxide as follows:

Na2CO3 + SO2 + 0.5CO2 Na2SO4 + CO2.With the creation of solid sodium sulfate, the desulfurization of the gas is complete,awaiting capture of solid sodium sulfate particles.In wet limestone scrubbing after particulate removal, limestone slurry in water comesinto contact with the flue gas

SO2 + CaCO3 + H2O CaSO3 + H2O + CO2.This calcium sulfite (CaSO3) is then oxidized to form calcium sulfate, CaSO4, gypsum.


Contaminants in “sheet rock” made from recycled gypsum are suspect householdenvironmental hazards.Processing Flue Gas Mercury, HgSince the average mid-sized coal-fired plant releases at least 200-300 pounds of mercuryper year, and mercury pollution has immense environmental impact, mercury emissioncontrol is receiving large “doses” of money and professional attention, and benefits fromspecialized industry knowledge. Oxidized mercury, Hg2+, and Hg bound to particles iseasily removed with ESP’s or wet flue gas desulfurization (FGD); removal of freeelemental mercury is more challenging.Technologies that impact mercury speciation include most existing air pollution controlmethods: Selective Catalytic Reduction (SCR) mercury oxidation is gaining emphasisfor mercury removal, since it is often already used to remove NOx; sorbent injection, dryscrubbers, dry and wet ESP's, and wet scrubbers are oldest and most commonlyemployed methods.The accepted existing activated carbon mercury sorbent process is that it takes many,many times more pounds of carbon per pound of mercury removed. Since the averagemid-sized plant releases at least 200-300 pounds of mercury per year, it equates toanywhere from four hundred thousand to almost four and one half millions pounds ofinjected carbon needed per year. Once polluted with mercury and captured, this carbon isuseless, cannot be recycled, and must sit in a landfill.ADA’s patented Mercu-RE process has been introduced to provide a sorbent which canbe detached after capture to yield elemental mercury for resale.The Cloric acid laboratory process produces HgOCl:

Hg + HClO3 HgOCl + H2O,and can also be used to oxidize NOX pollutants, and those can then pass through thesystem as nitrogen gas, without the problem of ammonia slip contaminating fly ash.http://www.wshinton.com/Greenhouse Gas SequestrationUS Federal agencies DOE, DOI (especially USGS), and EPA are showing strong interestin co-optimization of EOR by gas injection and greenhouse gas sequestration (GGS) fordisposal of COX, NOX, H2S, SO2, CXHY, etc. There are enough EOR-GGS examplesaround the world (Algeria, Australia, Canada, Norway, etc.) in operation or post-proposalstages to help researchers, planners, and developers avoid previous wrong turns inplanning.Regarding power stations, separation of greenhouse gases from N2 in flue gases seems adominant problem, since N2 injection is only favorable for gravity-stable EORdisplacement of light oils (API Gravity > 30°) at depths beyond the common range of oilreservoir depths. So, most US oil fields would be eliminated “out” of screeningprocesses for injection of raw flue gas.A possible example that might screen “in,” regarding depth, reservoir pressure, and


temperature, is the Hawk Point Field of Campbell County, WY, a complex Permian-Pennsylvanian Minnelusa interbedding of with eolian sands. Naturally, such a complexreservoir has large variations in vertical permeability, flow barriers, and is generally veryheterogeneous. Its reservoir has thickness 50’, porosity 12%, and permeability 60mDreported.Hawk Point reservoir depth is 11,500’, with 260°F Temperature and 4,472psi initialpressure. Providing its crude oil contents are light enough (API Gravity > 30°) andtemperature is not too high (increases oil viscosity), Hawk Point a good candidate tofurther screen for a pilot project to investigate EOR using injection of nitrogen or fluegas. On primary production in 1986 and waterflood in 1989, in 2001 Hawk Point Fieldwas already a candidate for abandonment due to economic limit.USGS: CO2 sequestration “Based on current projections, the United States faces theneed to increase its electrical power generating capacity by 40% over the next 20 yearsand its total energy consumption by 24% by the year 2030. Fossil fuel usage, a majorsource of carbon dioxide emissions to the atmosphere, will continue to provide thedominant portion of total energy in both industrialized and developing countries.Overall reduction of carbon dioxide emissions will likely involve some combination oftechniques, but for the immediate future, sequestration of carbon dioxide in geologicalreservoirs seems especially promising, as existing knowledge derived from the oil andgas production industries has already helped to solve some of the technologicalobstacles. The USGS has been studying geologic options for storing CO2 in depletedoil and gas reservoirs, deep coal seams, and brine formations.”http://energy.er.usgs.gov/health_environment/co2_sequestration/

Co-optimization FailureThe deepest oil reservoirs are generally shallower than 20,000 feet. The Semitropic Fieldin California produced oil from an interval between 17,610-18,060 feet. Heat levels atthose depths eventually "cook" the oil, converting it to natural gas.Mexico’s Cantarell Field is considered the world’s biggest N2-injection project,producing 500,000 BO/D incremental in recent reports. Bechtel/IPSI’s 2001 designreport explores all the problems with flue gas injection and several other processes,culminating in the choice of N2 injection to provide pressure maintenance, immiscibledisplacement, and increased production in the huge Cantarell project. That report all buteliminates the practical potential for flue gases as EOR solvents.The extensive contamination of flue gases, reported in Table above, makes theirprocessing to eliminate N2 a chemical engineering design nirvana, but a construction andmaintenance infinite nightmare. All those greenhouse contaminants in flue gas, includingCOX, are associated with corrosion and/or toxicity. In the gas injection EOR processesthey would not be processed once; they would be processed indefinitely in cycles for thelife of the project.www.ipsi.com/Tech_papers/cantarell2.pdf

So, without extensive treatment of flue gases, EOR and GGS will not co-optimize exceptin exceptional and infrequent applications. GGS should then be directed toward storage


in less valuable reservoirs, like depleted natural gas reservoirs, gas-depleted low-gradecoal beds and coal beds too thin or deep for mining, etc.Some pilot projects for EOR-GGS co-optimization would be helpful for research anddemonstration purposes, however. Just west of Hobbs, NM, are Xcel’s Maddox andCunningham gas-fired power stations, for example. Their minor flue gas outputs couldbe combined for processing, and there are small oil fields nearby perfect for EOR pilotprojects.Saline aquifers should be considered with great care, because they may eventually beneeded with desalinization technologies to produce fresh water. Contaminating themwith flue gas contaminants would render that water useless.Horizontal Drilling in Proven Oilfields

Figure 13. Geologic cross-section illustrates advantages for reservoir exploitation (increasedinitial potential, IP, and ultimate recovery, OR) and surface land conservation advantages ofdirectional drilling. http://www.americandirectionaldrill.com.

In the last 10 years the Natural Gas Industry has invested the time and money to perfectmost aspects of directional drilling and measurement while drilling (MWD) to replaceconsiderable fractions of US natural gas consumption. This has moderated pricesandexploded the performance of tight gas wells. Along with the “slick water” fracturetreatments this has created most of the “unconventional” shale gas plays like the BarnettShale.


Figure 14. American Directional Drilling’s VR-500 eliminates many traditional drillingcomponents, such as draw works, cables, manual tongs, and catheads, which reduces injuriesand downtime. Standard Operating Procedures limits the need for crewmembers to be on thedrilling floor, which contributes to improved jobsite safety. Push/Pull Thrust and Rotary Torquefor increased working power and reserve capacity. The Best-In-Industry Top Head Driveequipped with Slip Spindle is rugged and durable yet easy on Pipe Threads.

The VR-500 provides optimum bit load from initial surface contact throughout the entire drillingoperation. Operators also have the ability to immediately start a horizontal curve after surfacepenetration resulting in greater access to shallow formations, possibly as shallow as 1,200’.www.americandirectionaldrill.com.

Horizontal drilling technology has equal aptitude for rejuvenating many oil fields,especially those with low permeability and almost all their OOIP still in place to berecovered. Many of these are shaly sands reservoirs, where waterflooding is hazardous


due to sensitive reservoir clays.Horizontal drilling in such settings has multiple appeals: Initial production Potential (IP): Vertical completion, sandstone, vertical thickness 40’, for

example, 50,000 BO cumulative, can be completed across a 4,000’ horizontal interval. Ultimate Recovery (OR): Horizontal completion contacts much more formation volume,

especially banks of oil bypassed by previous development, and may be expected to produceat least 10 times the vertical completions’ cumulatives.

As is already demonstrated for thermal recovery of heavy crudes, low-permeability sandswith viscous intermediate crudes are horizontal drilling targets.

New drilling rig designs allow horizontal “kick-off” from vertical wells at much shallower depths,allowing targeting shallower oil reservoirs.Micro Hole Drilling

Figure 13. Small trailer mountedcoiled tubing “Micro Hole” system.DOE and LANL funded design,which uses coiled tubing, mudmotor, bent bit sub, reduction gearsub, and ultra-compact steering tool.

Horizontal depth can be far lessthan 1,000’.

Figure 15. Schematic displays itshole diameter range vs.conventional hole sizes. www.offshore-

technology.com/features/feature758/


Micro-hole drilling has the potential to greatly reduce the cost of drilling shallow andmoderate-depth holes for exploration, field development, long-term subsurfacemonitoring and, to a limited degree, actual oil and gas production. It also offers greatlyenhanced reservoir imaging, making access to data cheaper and more precise, as well asbeing invaluable during exploration activities.These new low-cost production capabilities are needed to invigorate the domestic oil andgas industry so that more of the petroleum resources in the USA's mature basins can berecovered. Dedicated boreholes with permanent reservoir monitoring systems willprovide high-resolution, real-time information while monitoring and optimizingimproved oil recovery (IOR) processes. This low-cost, long-term, improved imagingmethod of monitoring fluids in the reservoir will enhance oil recovery and allowdedicated boreholes for reservoir monitoring, eliminating production interruptions.Summary: Light Oil Legacy, Heavy Oil DestinyUSGS: HO & Bitumen “In spite of an immense resource base, heavy oil and naturalbitumen accounted for only about 3 billion barrels of the 25 billion barrels of crude oilproduced in 2000. Compared to light oil, these resources are generally more costly toproduce and transport. Also, extra-heavy oil and natural bitumen must usually be upgradedby reducing their carbon content or adding hydrogen before they can be used as feedstockfor a conventional refinery.The extra production, transportation, and upgrading costs explain why development andproduction of extra-heavy oil and bitumen are still limited. Their abundance, strategicgeographic distribution, quality, and costs will shape their role in the future oil supply.”http://pubs.usgs.gov/fs/fs070-03/fs070-03.html

Stacked pair of horizontal wells for steam-assisted

gravity drainage (SAGD), a natural bitumen

recovery process. Steam injected through the

upper well mobilizes bitumen, and gravity causes

the mobilized fluid to move toward the lower well,

where the bitumen is pumped to the surface.

Figure 16. In Canada, natural bitumen is extractedfrom Alberta oil sand deposits that are too deep tosurface mine by a process known as steam-assisted gravity drainage (SAGD). Productionwells could produce in excess of 2,000 barrels ofbitumen per day. (USGS) Graphic copyrightSchlumberger "Oilfield Review.” From Carl Curtisand others, 2002, Oilfield Review, v. 14, no. 3, p.50.

The legacy of E&P, both Internationally in the USA, is emphasis and expertise devoted to


the wholesale finding, developing, recovering, transporting, and refining of Light andIntermediate grades of crude oil. Virtually all the Earth’s remaining reserves of thesemost convenient feedstocks occur in the Eastern Hemisphere. These geopolitical settingsinclude many governments that are unstable and/or unfriendly to the USA and its allies.Emerging technologies and geopolitical pressures are pointing to future enhancement ofand reliance upon the recovery of heavy and extra-heavy oils. This same trend applies tolarge deposits of natural bitumens, especially regarding tar sands. It is time to study andplan for the large potential environmental consequences of commercial recovery of thesevast resources.In 2001, about 735,000 barrels per day were extracted by mining and by in-situproduction from Alberta oil sands, accounting for 36 percent of Canada's total oilproduction. Projected 2011 production is 2.2 million barrels per day (Alberta Energy andUtility Board, 2002, Alberta's Reserves 2001 and Supply/Demand Outlook 2002-2011,Statistical Series 2002-98, p. 2-8 to 2-9).On Page 53, McCain mentions that the petroleum engineer is rarely concerned with solidhydrocarbons. This is an example of E&P’s historic unfamiliarity with deposits of heavyand extra-heavy crude oils and bitumens.


US Energy Policy IssuesIn review, key issues in formulating a US Energy Policy for the 21st Century include: Excessive reliance upon light and medium crude oils to provide the refined domestic

products necessary for domestic commerce, science, health, and welfare continues today.This reliance is despite the heavy concentration of global heavy oil and bitumen resources inCalifornia, Canada and South America.

A precarious state of up to 250,000 stripper wells continues in the US. These wellsproduce only a few barrels of oil daily, at most. Economics of these are extremely sensitiveto oil price. They contribute significantly to US production, reducing balance of tradeproblems and reliance upon unreliable International sources. The stripper well aggregatealso contributes greatly to their local economies, providing ad valorem tax base, localpayrolls, specialty materials purchases, royalty contributions, and surface rentals.

New Enhanced Oil Recovery (EOR) alternatives are needed to improve recovery andprolong production of crude oils from old fields with critically low reservoir pressures and/oradvanced “deadening” of their original crude oil compositions. At least one of these isavailable for licensing and implementation today.

The “Peak Oil” concept has recently emerged, describing a theory that the International oilproduction rate is now nearing its peak. The theory is that oil production rate will soondecline and continue its decline indefinitely. If this production rate peak occurs, huge wavesof price increases and/or regional shortages are inevitable, with potentially dire economicand logistical effects. This term is adapted from Hubbert’s work (Appendix 7.).

Horizontal and micro-hole drilling: Horizontal drilling helped spur the US gas boom in2000. It is now proven, and new rig designs are ready for US oil fields, perhaps incombination with waterflooding and/or EOR. Micro-holes will also be very helpful.

Another anomaly of high oil prices will occur soon: Pricing in 2010 will average about$75/BO. Now is the time to explore and develop the remaining very large structures ofAlaska, while existing field activities support healthy infrastructure, lending “critical mass” tomoderate the huge costs of such geoscience and engineering projects under suchchallenging conditions. Residents of Kaktovik, the only people living on the Coastal Plain ofANWR, support oil and gas development in their 'back yard'. (Appendix 6.)

Natural gas is a domestically strategic resource. Its use to generate electric power andeven power motor vehicles could result in premature depletion in North America. Futuregenerations could have no recourse but to heat their homes with coal. Burning coal inpower plants and biofuels in vehicles are examples of available substitutes.

Emissions from coal fired power plants can be scrubbed. Use of coal to generateelectric power is perhaps the best way to conserve natural gas and assist transition toalternative energy sources like wind, solar, and nuclear technologies. To mitigate pollution,the emissions of plants fired by high-sulfur coals can be scrubbed of their carbon, soot,sulfur, etc., with manageable (25%) impacts on their economics.

Emerging technologies: Prolonging stripper production, improving EOR processes, wind,solar and bio-fuel technologies, recycling, and especially for scrubbing the emissions frompower plants fueled by high-sulfur coals, are technologies that will experience explodingdemand in the coming generations, decades, and even immediately.

US technological leadership: If the US is not a pre-eminent provider of at least the designof such technologies, our Nation will have to procure them overseas. Such a circumstancewould represent tragic loss of International prestige, National revenue, and a myriad ofopportunities both tangible and intangible.


ReferencesHubbert's Peak: The Impending World Oil Shortage, Kenneth S. Deffeyes, 285 pages,Princeton University Press (October 1, 2001).Twilight in the Desert: The Coming Saudi Oil Shock and the World Economy - MatthewR. Simmons, 448 pages, Wiley (June 10, 2005)Heavy Oil and Natural Bitumen -- Strategic Petroleum Resources, Richard F. Meyerand Emil D. Attanasi: USGS Fact Sheet 70-03, August 2003 - Online Version 1.0.http://pubs.usgs.gov/fs/fs070-03/fs070-03.htmlThe Properties of Petroleum Fluids, McCain, William D., Jr., 596 pages, PennwellBooks, 2 Sub edition (April 1990) ISBN-10: 0878143351 ISBN-13: 978-0878143351.“LNG Update”, Maslowski, Andy: Well Servicing Magazine, Nov./Dec. 2008, pages43-46.Petroleum Reservoir Rock and Fluid Properties by Abhijit Y. Dandekar.“Effect of Wettability Alteration on Relative Permeability Curves for Low PermeabilityOil-Wet Reservoir Rocks,” 2004, L. Qingjie, L. Li, Manli, Research Institute ofPetroleum Exploration and Development, PetroChina.http://www.scaweb.org/assets/papers/2004_papers/1-SCA2004-39.pdfS.E. Buckley and M.C. Leverett (1942). "Mechanism of fluid displacements in sands.”Transactions of the AIME (146): 107–116.http://stripperwells.com

Standard Handbook of Petroleum and Natural Gas Engineering, Second Edition(Complementary Science) by Ph.D., PE, William C. Lyons and BS, Gary J Plisga(Hardcover - Oct 15, 2004).KGS--Petroleum a primer for Kansas:http://www.kgs.ku.edu/Publications/Oil/index.htmlSRI Instruments - GC, HPLC, Data Systems, Hydrogen Generatorswww.srigc.com/www.americandirectionaldrill.comwww.xtremecoildrilling.comwww.offshore-technology.com/features/feature758/www.rmotc.doe.gov/Pdfs/RSFFeb06.pdfRadial Jet Enhancement (RJE) (www.encapgroup.com)http://en.wikipedia.org/wiki?title=Talk:Tar_sandshttp://peswiki.com/index.php/Directory:Microbial_Enhanced_Oil_Recovery

“Orimulsion is the best way to monetise the Orinoco's bitumen,” Carlos Rodriguez,Soberania.org - 17/07/05,http://www.soberania.org/Articulos/articulo_1375.htm.Worldwide practical petroleum reservoir engineering methods, H. C. "Slip" Slider, Ed 2,PennWell Books, 1983, 616. Regarding micellar polymer flooding, HK van Poollen &


Associates point out: "Although much laboratory work has been done, no field projecthas as yet been reported as economic."OPTIMIZATION OF A CO2 FLOOD DESIGN WASSON FIELD - WEST TEXASA Thesis by MARYLENA GARCIA QUIJADA, Texas A&M UniversityMASTER OF SCIENCE, August 2005, Petroleum Engineeringhttp://txspace.tamu.edu/bitstream/handle/1969.1/4138/etd-tamu-2005B-PETE-Garcia.pdf?sequence=1

Handbook of Detergents, Part D: Formulation (Surfactant Science) by Michael ShowellHandbook of Detergents, Part E: Applications (Surfactant Science) by Uri Zoller


Appendix 1. Darcy’s LawHenri D’Arcy (′där·sēz ′lö) was the French civil engineer who discovered these valuableconnections between the porous medium’s porosity and permeability, fluid viscosity,pressure gradient, and fluid flow.Darcy’s Law:Darcy's law is a simple proportional relationship between the instantaneous discharge ratethrough a porous medium, the viscosity of the fluid and the pressure drop over a givendistance.http://www.answers.com/topic/darcy-s-law(fluid mechanics) The law that the rate at which a fluid flows through a permeablesubstance per unit area is equal to the permeability, which is a property only of thesubstance through which the fluid is flowing, times the pressure drop per unit length offlow, divided by the viscosity of the fluid.http://www.answers.com/topic/darcy-s-lawDarcy's law states that where the Reynolds number is very low, the velocity of flow of afluid through a saturated porous medium is directly proportional to the hydraulicgradient. For example, the flow of groundwater from one site to another through a rock isproportional to the difference in water pressure at the two sites:

V = hPl

where h is the height difference between the highest point of the water-table and the pointat which flow is being calculated (the hydraulic head), V is the velocity of flow, P is thecoefficient of permeability for the rock or soil in question, and l is the length of flow.Darcy's law is valid for flow in any direction, but does not hold good for well-jointedlimestone, which has numerous channels and fissures.The total discharge, Q (units of volume per time, e.g., m³/s) is equal to the product of thepermeability (κ units of area, e.g. m²) of the medium, the cross-sectional area (A) to flow,and the pressure drop (Pb − Pa), all divided by the dynamic viscosity µ (in SI units e.g.kg/(m·s) or Pas), and the length L the pressure drop is taking place over. The negativesign is needed because fluids flow from high pressure to low pressure. So if the changein pressure is negative (in the x-direction) then the flow will be positive (in the x-direction). Dividing both sides of the equation by the area and using more generalnotation leads towhere q is the flux (discharge per unit area, with units of length per time, m/s) and is thepressure gradient vector. This value of flux, often referred to as the Darcy flux, is not thevelocity which the water traveling through the pores is experiencing[2].The pore velocity (v) is related to the Darcy flux (q) by the porosity (φ). The flux isdivided by porosity to account for the fact that only a fraction of the total formationvolume is available for flow. The pore velocity would be the velocity a conservativetracer would experience if carried by the fluid through the formation.http://en.wikipedia.org/wiki/Darcy's_law


Appendix 2. Pitch (Asphalt) Lakes(of Trinidad, Venezuela, and California)http://www.semp.us/publications/biot_reader.php?BiotID=485A pitch lake is a deposit of natural asphalt in a “great expanse of more or less mobilecharacter, covering many acres, and resembling in many ways a similar expanse ofwater”, said petroleum geologist Clifford Richardson in 1917. (1) The most classic of allpitch lakes is Trinidad Lake in the Caribbean West Indies’ Island of Trinidad, but otherpitch lakes exist throughout the world, including the Bermudez Lake in Venezuela, andthe Rancho La Brea “Tar” Pits in Los Angeles, California.The meanings of the related terms asphalt, petroleum, bitumen, pitch, tar andhydrocarbons, are continuously evolving. Their meanings emanate from certain timesand places, for example, the Roman era of “bitumen” and the modern era of “petroleum.”Even the term lake, as applied to natural asphalt deposits, may overstate the reality ofthese often soggy, belching, smelly, weeping sores of the Earth’s crust.Appendix 3. Fairway James Lime Field, East TexasStill Developing After 48 Years

Robert E. Webster, David Luttner, and Lawrence LiuHunt Oil Company, Dallas, TX

Fairway (James Lime) Field, in Henderson and Anderson counties, Texas, trappedvolatile 48° oil in the Aptian age James Lime member of the Pearsall Formation. Thereservoir is a large patch reef complex of varied carbonate facies that grew on apaleobathometric high in the interior platform of the Lower Cretaceous shelf. Forreservoir management purposes, the James is divided into an upper “A” zone with reef-derived skeletal grainstone and/or lagoonal facies with moldic and interparticle porosity,a “B” dense zone of non-porous reef core, and a lower “C” zone composed of uniformfine grainstone. Porosity and permeability average 12.5% and 33 mD in the “A” zoneand 12.9% and <1 mD in the “C” zone, respectively, at depths of 9,800 to 10,200 ft. Totalnet pay averages 56 ft.Following discovery in 1960, 157 wells were drilled on 160 acre spacing during theinitial development phase. In 1963, a high pressure gas gathering system and gas plantwere put into operation, and in 1965 a field-wide unit of 28,518 acres was approved,designed to conduct gas and water pressure maintenance operations. An injection projectwas then initiated to preserve reservoir energy and increase recovery through use of aWAG (water-alternating-gas) miscible recovery process. Additional infill drillingprojects were implemented in 1971, 1980, 1991, and 2006 to optimize recovery; to date237 wells have been drilled, including 3 recent horizontal wells targeting bypassed pay inthe upper “A” and lower “C” zones. A large secondary gas saturation developed over theyears as the gas-recycling program was implemented. Gas sales began in 2000, and gasinjection was terminated in January, 2005. OOIP in the James was calculated as 410MMBO, of which 213 MMBO has been produced. As of Aug. 1, 2007, production was1,220 BOPD, 23,400 BWPD, 70 MMCFD, and 3,360 BNGLPD. Field life is projected


beyond 2015.AAPG Article #90078©2008 AAPG Annual Convention, San Antonio, TexasAppendix 4. Exxon Mobil adds 1.5B barrels to proved reservesAssociated Press, 02.16.09, 03:17 PM ESTExxon Mobil Corp. said Monday it added 1.5 billion barrels of oil equivalent to itsproved reserves last year, once again extending a positive trend of replacing more barrelsthan it produced. The added reserves for the industry's biggest player totaled 103 percentof its 2008 output.The company said it added 2.2 billion oil-equivalent barrels to its resource base in 2008,with reserves additions from the Kearl Phase 1 oil sands project in Canada totaling 1.1billion oil-equivalent barrels. It said proved additions were also made in the US,Norway, Nigeria, Australia, and Angola.For 2008, the company's resource base - which includes proved and probable reserves -grew by 0.3 billion oil-equivalent barrels to 72.4 billion oil-equivalent barrels. Thatfigure includes production, revisions to existing discoveries, asset sales and increasedgovernment take, which reduced the base by 0.5 billion oil-equivalent barrels.Last month Exxon reported a US record for annual profit even as its fourth quarter resultsfell 33 percent to $7.8 billion.Appendix 5. Oil From Canada’s Tar Sands Can Be Made ‘Clean,’ ObamaSaysJim Efstathiou Jr. Jim Efstathiou Jr. – Wed Feb 18, 12:00 am ETFeb. 18 (Bloomberg) -- Oil extracted from tar sands in Canada can be made a cleanenergy source, and the US will work with its northern neighbor to develop thetechnology, President Barack Obama said.A joint effort by the US and Canada, its biggest trading partner, on ways to capture andstore carbon dioxide underground would “be good for everybody,” Obama said yesterdayin an interview with the Canadian Broadcasting Corp. Obama will make his first journeyas president outside the US tomorrow to meet with Canadian Prime Minister StephenHarper.Conservationists on both sides of the border have called on Obama to reject any bid toexempt tar-sands oil from proposed climate-protection rules. Government officials inCanada say restrictions on oil-sands exports would increase US dependence on oil fromunfriendly countries. The oil is separated from sand and clay with intense heat in aprocess that releases more greenhouse gases than pumping conventional crude.“The United States is the Saudi Arabia of coal, but we have our own homegrownproblems in terms of dealing with a cheap energy source that creates a big carbonfootprint,” said Obama, who has backed “clean-coal” technology in the US overskepticism about its prospects from environmentalists such as former Vice President AlGore.Reducing greenhouse-gas emissions from energy sources such as coal and oil sands will


promote economic growth in both countries, Obama said.‘Ceiling’ on Growth“If we don’t, then we’re going to have a ceiling at some point in terms of our ability toexpand our economies and maintain the standard of living that’s so important,particularly when you’ve got countries like China and India that are obviously interestedin catching up,” the president said.The US imported about 780,000 barrels a day of tar-sands oil in 2008, 60 percent of totalproduction, according to the Canadian Association of Petroleum Producers. Petro-Canada, the country’s third-largest oil company, and other producers expect to more thandouble industry output to 3.3 million barrels a day by 2020.Alberta’s oil sands may hold the equivalent of 173 billion barrels, enough to supply theUS for 24 years, according to some government estimates. Only Saudi Arabia, thebiggest producer in the Organization of Petroleum Exporting Countries, has morereserves.“Canada’s energy industry is willing to invest money, technology, know-how and time inthis effort, but we really can’t do it alone,” Petro-Canada Chief Executive Officer RonaldBrenneman told reporters last week in New York. “It will take the combined efforts ofthe industry, government, regulators and consumers.”Environment MinisterCanadian Environment Minister Jim Prentice has said Canada and the US should worktogether to develop systems to capture and sequester underground carbon-dioxideemissions. The total “life- cycle” of emissions released, all the way to filling a car’s tankwith gasoline, are 20 percent more than conventional oil, the Rand Corp. researchorganization of Santa Monica, California, said in a 2008 report.Carbon capture would help “transition from a high-carbon present to a low-carbon futurewhile avoiding a disruptive and dislocative period,” Prentice said on Jan. 20.Obama backs slashing emissions of heat-trapping gases to 1990 levels. The newpresident will have to square his environmental agenda with his call to trim dependenceon oil supplies from the Mideast and with the US’s longstanding policy to treat Canada asa commercial and strategic ally.“Would I rather rely on Canada for my energy security or would I rather rely on HugoChavez?” Gordon Giffin, US ambassador to Canada during President Bill Clinton’ssecond term, said in an interview, referring to Venezuela’s president. “What Canada issaying to the United States is we now believe that we ought to be developing a NorthAmerican approach to energy and to the environment. Our energy issues are notidentically connected, but they’re logically connected.”To contact the reporter on this story: Jim Efstathiou Jr. in New York [email protected].


Appendix 6. ANWR residents favor developmentThe residents of Kaktovik, the only people living on the Coastal Plain of ANWR, supportoil and gas development in their 'back yard'. Alaska's indigenous people have benefitedgreatly from North Slope production. In addition to providing a tax base for the localgovernment, oil development has provided jobs, funding for water and sewer systems andschools. Native and village corporations with oil field-related subsidiaries are workingon the North Slope, and the local government has a voice in permitting andenvironmental regulation.Organizations representing the residents of the Coastal Plain and surrounding area suchas the City of Kaktovic, Kaktovik Inupiat Corporation, North Slope Borough, ArcticSlope Regional Corp., Doyon Regional Corporation and Alaskan Federation of Nativeshave all endorsed development based on their experience with Prudhoe Bay.http://www.anwr.org/people/people.htm

Appendix 7. Reviews of Hubbert's Peak: The Impending World Oil Shortage232 pages, September 29, 2008These several reviews can be found on Amazon.com.From Scientific AmericanYou have to wonder about the judgment of a man who writes, "As I drive by those smellyrefineries on the New Jersey Turnpike, I want to roll the windows down and inhaledeeply.” But for Kenneth S. Deffeyes, that's the smell of home. The son of a petroleumengineer, he was born in Oklahoma, "grew up in the oil patch," became a geologist andworked for Shell Oil before becoming a professor at Princeton University. And he stillknows how to wield a 36-inch-long pipe wrench.In Hubbert's Peak, Deffeyes writes with good humor about the oil business, but hedelivers a sobering message: the 100-year petroleum era is nearly over. Global oilproduction will peak sometime between 2004 and 2008, and the world's production ofcrude oil "will fall, never to rise again." If Deffeyes is right--and if nothing is done toreduce the increasing global thirst for oil--energy prices will soar and economies will beplunged into recession as they desperately search for alternatives.It's tempting to dismiss Deffeyes as just another of the doomsayers who have beenpredicting, almost since oil was discovered, that we are running out of it. But Deffeyesmakes a persuasive case that this time it's for real. This is an oilman and geologist'sassessment of the future, grounded in cold mathematics. And it's frightening. Deffeyes'sprediction is based on the work of M. King Hubbert, a Shell geologist who in 1956predicted that US oil production would peak in the early 1970s and then begin to decline.Hubbert was dismissed by many experts inside and outside the oil industry. Pro-Hubbertand anti-Hubbert factions arose and persisted until 1970, when US oil production peakedand started its long decline.The Hubbert method is based on the observation that oil production in any region followsa bell-shaped curve. Production increases rapidly at first, as the cheapest and most


readily accessible oil is recovered. As the difficulty of extracting the oil increases, itbecomes more expensive and less competitive with other fuels. Production slows, levelsoff, and begins to fall.Hubbert demonstrated that total US oil production in 1956 was tracing the upside of sucha curve. To know when the curve would most likely peak, however, he had to know howmuch oil remained in the ground. Underground reserves provide a glimpse of the future:when the rate of new discoveries does not keep up with the growth of oil production, theamount of oil remaining underground begins to fall. That's a tip-off that a decline inproduction lies ahead.Deffeyes used a slightly more sophisticated version of the Hubbert method to make theglobal calculations. The numbers pointed to 2003 as the year of peak production, butbecause estimates of global reserves are inexact, Deffeyes settled on a range from 2004 to2008. Three things could upset Deffeyes's prediction. One would be the discovery ofhuge new oil deposits. A second would be the development of drilling technology thatcould squeeze more oil from known reserves. And a third would be a steep rise in oilprices, which would make it profitable to recover even the most stubbornly buried oil.In a delightfully readable and informative primer on oil exploration and drilling, Deffeyesaddresses each point. First, the discovery of new oil reserves is unlikely--petroleumgeologists have been nearly everywhere, and no substantial finds have been made sincethe 1970s. Second, billions have already been poured into drilling technology, and it'snot going to get much better. And last, even very high oil prices won't spur enough newproduction to delay the inevitable peak."This much is certain," he writes. "No initiative put in place starting today can have asubstantial effect on the peak production year. No Caspian Sea exploration, no drilling inthe South China Sea, no SUV replacements, no renewable energy projects can be broughton at a sufficient rate to avoid a bidding war for the remaining oil."The only answer, Deffeyes says, is to move as quickly as possible to alternative fuels--including natural gas and nuclear power, as well as solar, wind and geothermal energy."Running out of energy in the long run is not the problem," Deffeyes explains. "The bindcomes during the next 10 years: getting over our dependence on crude oil."The petroleum era is coming to a close. "Fossil fuels are a one-time gift that lifted us upfrom subsistence agriculture and eventually should lead us to a future based on renewableresources," Deffeyes writes. Those are strong words for a man raised in the oil patch.For the rest of us, the end of the world's dependence on oil means we need to make sometough political and economic choices. For Deffeyes, it means he can't go home again.Paul Raeburn covers science and energy for Business Week and is the author of Mars:Uncovering the Secrets of the Red Planet (National Geographic, 1998). --This text refersto the Hardcover edition.Review"Deffeyes has reached a conclusion with far-reaching consequences for the entireindustrialized world.... The 100-year reign of King Oil will be over." -Fred Guterl,


Newsweek "Deffeyes makes a persuasive case.... This is an oilman and geologist'sassessment of the future, grounded in cold mathematics. And it's frightening."Paul Raeburn, Scientific American "Deffeyes writes with the taut reasoning of a scientistand the passion of someone raised in the industry. His background is ideal for thissubject, and the book is a gem...Read Hubbert's Peak-it's better to know what lies ahead than to be surprised too late torespond." -Brian J. Skinner, American ScientistThe wolf is at the door, November 2, 2001, By Dohn K. Riley (Tahoe City, CA UnitedStates)Deffeyes hits the nail on the head when he clearly details what petroleum industryinsiders already know - it's not "if" global oil production will peak, it's "when.” Afteryears of warning about the imminent demise of cheap oil supplies, experts are nowsplitting hairs about whether or not inexpensive oil production will peak in this decade orthe next. The author's easy-going, occasionally humorous prose makes the bad newseasier to take, but either way, a serious global oil crisis is looming on the horizon.Deffeyes energizes his readers by sweeping us easily through the denser strata of thecomplexities and developmental progress that built "Big Oil," but he also warns ofrelying on technology to save us in the future. Unlike many technological optimists, thislife-long veteran of the industry concludes that new innovations like gas hydrates, deep-water drilling, and coal bed methane are unlikely to replace once-abundant petroleum inease of use, production, and versatility. The Era of Carbon Man is ending.A no-nonsense oilman blessed with a sense of humor, Deffeyes deftly boils his messagedown to the quick. Easily produced petroleum is reaching its nadir, and although they areclean and renewable, energy systems like geothermal, wind and solar power won't solveour energy needs overnight. "Hubbert's Peak" represents an important aspect of theenergy crisis, but it is only one factor in this multi-faceted problem that includesbiosphere degradation, global warming, per-capita energy decline, and a science/industrycommunity intolerant of new approaches to energy technology research anddevelopment. An exciting new book by the Alternative Energy Institute, Inc., "Turningthe Corner: Energy Solutions for the 21st Century," addresses all of the componentsassociated with the energy dilemma and is also available on Amazon.com.Anyone who is concerned about what world citizens, politicians, and industry in theUnited States and international community must do to ensure a smooth transition fromdependence on dangerous and polluting forms of energy to a more vital and healthierworld, needs to read these books. Future generations rely on the decisions we maketoday.The Story of Oil, The End of Oil, September 18, 2001, by Ron Patterson (Huntsville, AlUSA)Kenneth Deffeyes, Princeton professor and former oil field geologist, tells the story ofoil, right up to the beginning of the demise of oil. He takes the methods developed by M.King Hubbert, the man who accurately predicted the peak in US oil production, and


applies them to world oil production. The book makes absolutely riveting reading. Thefirst few chapters deal entirely with the source and production of oil. I kept wondering,as I was reading these chapters, what has this to do with Hubbert's Peak and the comingdecline in oil production? Then it began to dawn on me, one has to know everythingabout oil to accurately predict the future production of oil. Deffeyes is that man and hecovers every possible base. Many say "Just drill deeper" or "There is oil in the deepocean", but Deffeyes shows why drilling deeper can yield natural gas but not one drop ofoil and why oil from deep ocean sediments is impossible. Deffeyes leaves no stoneunturned and covers every possible source of oil.Deffeyes expects the peak in world oil production at around 2005 but says it could comeas early as 2003 or as late 2006. There is a fair amount of jitter in the year-to-yearproduction so picking the exact peak is difficult. But he reminds us that the center of theUS Best-fit curve was 1975 and the actual peak came in 1970. He says however, there isnothing plausible that could postpone the peak until 2009.Of course Kenneth Deffeyes is not the only oil field geologist that is predicting animpending peak in world oil production, Colin Campbell, Jean Laherrere and severalothers have been doing that for several years. The data supporting the impending peakand decline is sometimes difficult to interpret but Deffeyes lays the data out in undeniableterms and in such a manner that the average layman can understand it.The only problem I had with the book was I felt Deffeyes was overly optimistic as to theeffects of the coming decline in world oil production. He sees only a decade or so ofdifficulties until we get over our dependence on crude oil. Many others however, whohave looked more closely at the possibility of alternate sources of energy to replace cheapportable oil, find no possible replacement. And....most of these see nothing short of aworldwide holocaust a few years after the peak. They say the world's six billion peopleare supported by a network of food production and transport that will be impossible tomaintain when oil production begins to drop and the price of the remaining oil begins torise dramatically.But by all means, BUY THIS BOOK. Not only will it convince you of the inevitabilityof the impending peak and decline in oil production, but also it will give you theammunition and data to convince those around you, to convince them and give them timeto make preparations for....for something I find too hard to even imagine.Only one more oil crisis, but it'll be a doozy, February 27, 2002, By Royce E. Buehler"figvine" (Cambridge, MA USA)While millions of environmentally concerned Americans are ready to vilify on reflexwhat Molly Ivins flippantly dubs "the oil bidness," Kenneth Deffeyes thinks of thepetroleum fields as a place of high spirits and high romance. But, having spent half hislife working for Shell, and half of it training later generations of fossil fuel hunters, he ishere to break the bad news to us gently. And the news is, the party's over. The days ofderring-do among the derricks are just about done.Thirty years ago, US oil production peaked, and has been declining ever since. Shortly,


world oil production will hit the same peak, and begin to decline. That doesn't meanthere will be no oil left; thirty years after hitting its own peak, the US is still the secondlargest oil producer in the world. But it does mean that demand will outstrip supply, andthat means the economic dislocations of the late 70s - the spiking prices, the long gaslines, the deep recession - will become permanent. Eventually, other sources of energy,both renewables and plentiful fossil fuels like natural gas, will fill in the breach. But itwill be a long and painful process, requiring a ton of capital investments in research andin infrastructure that a suddenly poorer first world will be ill able to afford."Shortly,” Deffeyes argues, means in one to six years, and probably in the early part ofthat range. One can quibble with some of his arguments for that timing. With luck, heacknowledges, there may be one significant set of oil fields yet to be discovered, in theSouth China Sea (unexplored so far because the competing jurisdictions of the severalnearby island nations have made contracts hard to nail down.) And I don't think he'sgiven sufficient weight to the fact that all the oil recovery in the Middle East (ME) is still"primary,” using old-fashioned pumping technology. But if all the quibbles are granted,it only affords the world economy another five or ten years of grace.So, if Deffeyes is wrong, the time to start making those massive investments and changesis today. If he is right, the time to start making them is ten years ago, and all we canaccomplish by swift action is to make the period of intense pain a decade or two shorter.Though Professor Deffeyes isn't political enough or impolite enough to say so, Clinton(for all his green talk) failed to provide any leadership to reduce our dependence onpetroleum. And his successor, of course, is providing energetic leadership, but all of it isgeared to marching us all double-time into still more rapid consumption of what little oilis left. History will remember neither President Slick, nor President Oil Slick, any morekindly than it now remembers Herbert Hoover for fiddling while the fuse that would setoff the Great Depression burned.The book is an easy read, short and set in a conversational style that permits the reader toglide through the more technical portions if so inclined. The technical details and themathematical arguments could be tighter, and the folksiness, which would be delightfulin a lecture room, is occasionally a bit much on the written page. For those reasons, itwould be easy to give the book only four stars. But those faults are inseparable from thebook's virtues. They're compromises Deffeyes chose to make in order to be accessible toa wide audience, and his book deserves to reach one.If environmentalists take Deffeyes' message seriously, they'll realize that we will soon beso starved for oil that ANWR is certain to be plundered, and that nuclear plants arecertain to sprout across the landscape like, well, like mushrooms. If Deffeyes is on ornear target, nothing can prevent those developments. Greens today should be usingANWR and an expanded nuclear industry as bargaining chips, to be traded for strictCAFE standards, investment in renewable technologies, non-industry oversight ofnuclear safety, and (since the near term alternative will be coal) investment in natural gaspipeline infrastructure.


Appendix 8. Reviews of Matthew R. Simmons’ Twilight in the Desert:The Coming Saudi Oil Shock and the World Economy464 pages, Wiley; illustratedInvestment banker Simmons offers a detailed description of the relationship betweenSaudi Arabia and the US and our long-standing dependence upon Saudi oil. With a field-by-field assessment of its key oilfields, he highlights many discrepancies between SaudiArabia's actual production potential and its seemingly extravagant resource claims.Parts 1 and 2 of the book offer background and context for understanding the technicaldiscussion of Saudi oil fields and the world's energy supplies. Parts 3 and 4 containanalysis of Saudi Arabia's oil and gas industry based on the technical papers published bythe Society of Petroleum Engineers.Simmons suggests that when Saudi Arabia and other ME producers can no longer meetthe world's enormous demand, world leaders and energy specialists must be prepared forthe consequences of increased scarcity and higher costs of oil that support our modernsociety. Without authentication of the Saudi's production sustainability claims, the authorrecommends review of this critical situation by an international forum. A thought-provoking book. Mary WhaleyCopyright © American Library Association. bad news from the SPE, via a Texas investment banker, June 16, 2005 (excerpts)By R. Hutchinson "autonomeus" (a world ruled by fossil fuels and fossil minds)Matthew R. Simmons analyzes the technical papers of the Society of PetroleumEngineers (SPE) on Saudi oil, shining a light behind the veil of secrecy that has shroudedit since OPEC stopped reporting oil production data in 1982.In short, what the SPE reports reveal is that the official Saudi claims for reserves andproduction capacity are vastly overstated. Further, tragically, it seems that the fields havebeen mismanaged, making it unlikely that all the oil will ever be recovered.Are there vast untapped reserves in Saudi Arabia? According to the SPE data, the answeris no. No giant fields have been discovered since 1968, despite intensive exploration.Here is a list of crisp facts about world oil, according to Simmons (p. 331): Only a handful of super-giant oilfields have ever been discovered in Saudi Arabia and the

ME -- they represent a very significant portion of all ME oil, and they are all very mature. All mature giant oilfields peak and decline (production profiles showing the peaks are shown

for 8 fields in Texas, Alaska, the North Sea, and Russia). Implication: sophisticated newtechnology will not prevent or forestall this from happening.

There do not seem to be many giant oilfields left to be discovered in Saudi Arabia or the ME. Non-OPEC oil, excluding the FSU (former Soviet Union) seems to be peaking, or has

already peaked.Another dire warning that we must develop energy alternatives, March 28, 2006By Dennis Littrell (SoCal)Kenneth S. Deffeyes warned us that peak oil is upon us and that what is left in the groundis just about the same as what we have already used. He pointed to Thanksgiving Day,


2005 as the day oil hit its peak. Now another world renowned expert on oil, Matthew R.Simmons in this densely considered book, is advising us that the estimates of oil left inthe ground by the largest producer of oil, Saudi Arabia, are probably inflated, and at anyrate cannot be independently confirmed.Furthermore, it is supposed that estimates by almost all oil producing countries areinflated since such inflation improves their ability to influence the market while allowingthem (OPEC members at least) to produce more.A question that might be asked is how do we know that there are not great fields of oilsomewhere waiting to be discovered? Certainly if there are, the twilight of the oil-basedworld economy is pushed further into the future leaving us with much less to worry aboutnow. Simmons answers this question for Saudi Arabia at least. He makes it clear that thepossibility of any great discoveries on the Arabian peninsula "must now be deemedremote" since the land has been so thoroughly explored. (See Chapter 10 "Coming UpEmpty in New Exploration.")Deffeyes answered this question in another way. Using logic from his mentor M. KingHubbert who predicted with startling accuracy when US production would peak (early1970s) Deffeyes argues that what's left can be inferred from current production curves.Because oil exploration and production has been so extensive worldwide, if the oil werethere, it would have been discovered and drilled for. This is not to say that there are notsome (small) fields left undiscovered. There are some, no doubt, but like puddles addedto a great lake, they won't affect the overall picture.This same sort of logic can be applied to Saudi Arabia, and Simmons does indeed usesuch logic. However, he goes beyond that because he believes that oil predictionsimulation models (see Chapter 12, "Saudi Oil Reserves Claims in Doubt") can fail.Typically, he writes, an oilfield will yield about 75 percent of its oil during the first halfof its producing life. (p. 278) Almost all of the great Saudi fields are decades old.The strange thing about this book is that while it is touted as another book predicting theend of oil, it actually argues that the situation is not entirely clear. It is possible that thereis still a lot of undiscovered oil left in Saudi Arabia in places such as "the land along theIraq border, an unexplored area almost as large as California" and a couple of otherplaces. (p. 243) World wide such unexplored places are many. Nonetheless even if a lotof oil is discovered say in the middle of the Pacific Ocean or deep in the Antarctic, thecost of producing that oil will be greater than the cost of producing oil from say the greatGhawar field in Saudi Arabia where the oil gushes out of the ground almost effortlessly.Actually, according to Simmons "effortlessly" is no longer the correct adjective to use.As oil fields grow old some help is needed to get the oil to rise to the top and flow.Water is typically pumped into the field to get the oil to elevate. Simmons reports on theextensive use of saline water in Saudi Arabia--more evidence that there is not as much oilleft as the Saudis would like us to believe.Also a distinction must be made between pure "reserves" (actual oil in the ground) and"recoverable reserves" (oil that is cost-effective to produce). And a further distinction


must be made between grades of oil. It may be cost-effective to pump the sweetest,purest grade of oil out of a field whereas lesser grades would not be worth the expense.A weakness of the book is that, despite the words "and the World Economy" in thesubtitle, which suggest an exploration of consequences and what to expect, there is nextto nothing about the effect less oil (than expected) will have on the world economy.Clearly, of course, and in the broadest sense, our standard of living will go down as ourenergy costs rise. The subtitle is probably just a book biz editor's attempt to gain a largerreadership.Twilight in the Desert is long and extraordinarily detailed and gives the typical readermore information than perhaps would be desired. This reader came away convinced thatSimmons's main argument, that Saudi oil reserves have been exaggerated, is probablycorrect, but curiously his extremely balanced and careful delineation left me feeling thatthere is still plenty of doubt about both Saudi reserves and those world wide. Stay tuned.Regardless, one thing is clear, soon or late, within twenty years or fifty, we will have toretool our economies to run on something other than fossil fuels. The sooner we getstarted on that, the better. If we wait too long the sudden economic shock is likely to becatastrophic.(END of REVIEWS)


Appendix 9. Radial Jet EnhancementRadial Jet Enhancement is a patented technology to daily production of existingmarginally producing oil and gas wells. The technology is oriented toward existing oiland gas wells in North America at depths of 4,500 feet and shallower.

Radial Jet Enhancement utilizespatented design andmanufacturing technology of theDeflecting Shoe Boot andpressure water jetting. Thisfigure below more preciselyillustrates the process.

The technology has the ability todrill up to 8 laterals in only twodays, as opposed to a typicalperiod of four weeks per well.

The figure below demonstrateshow Radial Jet Enhancement candrastically expand the productionarea within a given field. Anaverage well will pull petroleumfrom an area of up to 120 feetfrom the well bore.

www.encapgroup.com

Radial Jet Enhancement lateral wellbores extend up to 300 feet from the well bore, thusincreasing the area of production several fold.Traditional well bore configuration, pulling from 120 feet, equates to a total volume ofpay zone of 271,296 cubic feet. Each lateral of 300 feet will pull from over 360,000cubic feet. That’s 1,440,000 cubic feet on four laterals.http://www.texas-energy.org/


Appendix 10:“Surfactant-Based Photorheological Fluids: Effect of the SurfactantStructure”The effect of the surfactant structure on the mechanical and structural properties ofsurfactant based photorheological fluids are presented in this paper.Cetyltrimethylammonium bromide (CTABr) mixed with trans-o-methoxycinnamic acidin a basic environment can form photosensitive systems. The driving force is the abilityof surfactant molecules to form wormlike micelles in the presence of the anionicphotosensitive additive. Taking into account that slight changes in the surfactantmonomer’s structure can induce drastic modifications of the micellar aggregate features,the role the of the nature of the counterion (in the CTAX type surfactants) or theheadgroup size (CTRABr type surfactants) and its influence on the mechanical propertiesof surfactant based photorheological fluids using trans-o-methoxycinnamic acid (trans-OMCA) as additive were investigated. Rheological studies reported in this paper showthat the viscosity of these systems drastically varies only by changing the nature of thesurfactant counterion. Moreover, by increasing the bulk simply by replacing the threemethyl groups with three ethyl groups in the surfactant headgroup moiety, the viscositydrastically decreases. Highly photosensitive PR fluids can be further obtained usingcetyltrimethylammonium trans-o-methoxycinnamate (CTAOMC) as surfactant at neutralpH. In addition to the complete rheological characterization carried out by means of theapplication of both a steady shear and a dynamic shear stress, a 1H NMR and NOESYstudy was also performed.Piero Baglioni‡, Elena Braccalenti †, Emiliano Carretti‡, Raimondo Germani †, LauraGoracci †, Gianfranco Savelli* † and Matteo Tiecco ††CEMIN, Center of Excellence on Innovative Nanostructured Materials, Department ofChemistry, University of Perugia, Via Elce di Sotto 8, I-06123 Perugia, Italy‡Departmentof Chemistry and CSGI, University of Florence, Via della Lastruccia 3, Sesto Fiorentino,I-50019 Firenze, ItalyLangmuir, 2009, 25 (10), PP 5467–5475DOI: 10.1021/la900465hPublication Date (Web): April 17, 2009Copyright © 2009 American Chemical Societyhttp://pubs.acs.org/doi/abs/10.1021/la900465h

Documents

Hydrocarbon Classification and EOR 101, 2012