Hydrocarbon Classification and EOR 101, 2012

Hydrocarbon Hydrocarbon Classification and EOR 101 Table of Contents

TABLE OF CONTENTS ......................... ...................................... ......................... ......................... .......................... ......................... ............... ... 1 ABSTRACT ......................... ...................................... ......................... ......................... .......................... .......................... .......................... ................. .... 3 TABLE OF APPENDICES ........................ ..................................... ......................... ......................... .......................... .......................... ............. 3 INTRODUCTION......................... ...................................... .......................... ......................... ......................... .......................... ........................ ........... 4 HUBBERT’S “PEAK” AND BELL CURVE ......................... ...................................... .......................... ......................... .............. 4 GEOPOLITICS OF INTERNATIONAL HO & BITUMEN DEPOSITS ........................ ............................... ....... 5 ENVIRONMENTAL BITUMEN & HO ISSUES ......................... ...................................... ......................... ..................... ......... 7 OILFIELD JARGON AND PROFESSIONS ........................ ..................................... .......................... ......................... ................. ..... 8 GEOSCIENCES, ACCOUNTING, LAND, LEGAL........................ ..................................... ......................... ................... ....... 8 DRILLING AND PETROPHYSICAL ENGINEERS ........................ ..................................... ......................... ................... ....... 9 PRODUCTION AND RESERVOIR ENGINEERS ......................... ...................................... ......................... ..................... ......... 9 CRUDE OIL CLASSIFICATION ....................... ..................................... .......................... ........................ .......................... .................11 ...11 INTERMEDIATE HYDROCARBONS ........................ ..................................... ......................... ......................... .......................11 ..........11 SINGLE-PHASE FLOW IN POROUS MEDIA....................... ..................................... .......................... ........................1 ............13 3 DRY GAS RESERVOIRS ........................ ..................................... ......................... ......................... .......................... .........................1 ............13 3 LNG AND ENERGY POLICY ......................... ...................................... .......................... ......................... .......................... .................14 ...14 WET GAS RESERVOIRS ........................ ..................................... ......................... ......................... .......................... .........................1 ............16 6 2-PHASE RELATIVE PERMEABILITY AND FRACTIONAL FLOW ...............................16 RELATIVE PERMEABILITY AND MOBILITY RATIO ......................... ...................................... .......................17 ..........17 RETROGRADE GAS RESERVOIRS ......................... ...................................... ......................... ......................... .......................18 ..........18 VOLATILE OILS ........................ ..................................... .......................... ......................... ......................... .......................... .......................18 ..........18 CRUDE “BLACK” OILS......................... ...................................... ......................... ......................... .......................... .........................2 ............20 0 CONVENTIONAL (LIGHT & INTERMEDIATE) CRUDE OIL ........................ ..................................... ..............20 .20 API GRAVITY AND HEAVY CRUDE OILS (HO) ......................... ...................................... .......................... ..............21 .21 HO & BITUMEN, ACCORDING TO USGS:................ USGS:............................. .......................... ......................... ..................22 ......22 SHALES, ACCUMULATIONS, AND “OIL SHALES”............................... ”............................................ ...................23 ......23 RESERVOIR CONDITIONS AND FLUID DENSITIES ......................... ...................................... .........................2 ............24 4 RESERVOIR CONDITIONS AND OIL VISCOSITIES ........................ ..................................... .......................... ..............24 .24 RESERVOIR CONDITIONS, POROSITIES & WETTABILITIES ........................ ....................................2 ............25 5 PRIMARY OIL RECOVERY DRIVE MECHANISMS ........................ ..................................... .......................... ..............25 .25 ORIGINAL OIL IN PLACE AND RECOVERY EFFICIENCY ......................... ...................................... ................26 ...26 CONSEQUENCES OF OIL RESERVOIR DEPLETION......................... ...................................... .........................2 ............28 8 WATERFLOOD AND EOR (IOR) UNITS ......................... ...................................... .......................... .........................2 ............28 8 SCREENING PRODUCING OIL FIELDS FOR WF & EOR..........................................29 WATER DRIVE, DISPOSAL AND SUPPLY......................... ...................................... .......................... .........................2 ............29 9 WATERFLOODING & HOT WATER INJECTION ......................... ...................................... ......................... ................30 ....30 WHY WATERFLOODS UNDER -PERFORM ........................ ...................................... .......................... ........................3 ............31 1

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CHEMICAL FLOODING (CF) INTRODUCTION ......................... ...................................... ......................... ..................32 ......32 ALKALINE FLOODING AND ASP................................. ASP............................................. ......................... .......................... ................32 ...32 SURFACTANTS, MICELLES , TYPE I MICRO-EMULSIONS ......................... ...................................... ..............32 .32 MICRO-EMULSION TYPES II & III ......................... ...................................... ......................... ......................... .....................33 ........33 SURFACTANTS IN E&P ........................ ..................................... ......................... ......................... .......................... .........................3 ............34 4 POLYMERS, G ELS, AND GELATION........................ ..................................... ......................... ......................... .....................34 ........34 OILFIELD POLYMERS AND GELS ........................ ..................................... ......................... ......................... .........................3 ............35 5 MICROBIAL EOR...................... EOR................................... .......................... ......................... .......................... .......................... ......................36 ..........36 CF EOR S UMMARY ........................ ..................................... ......................... ......................... .......................... ......................... ................37 ....37 MISCIBLE EOR (CO2) PROCESSES:.................................... :................................................ ......................... .....................37 ........37 CO2 FLOOD LOGISTICS & OPERATIONS......................... ...................................... .......................... .........................3 ............38 8 SCREENING OIL-CO2 MISCIBILITY ........................ ..................................... ......................... ......................... .....................39 ........39 EOR FOR HO FIELDS: TRHO............................................................................40 CYCLIC STEAM INJECTION (CSI)................ (CSI)............................. .......................... ......................... .......................... ...................41 .....41 STEAMFLOODING (SF).................................... (SF)................................................ ......................... .......................... ......................... ..............41 ..41 IN-SITU COMBUSTION (I-SC, OR FIRE FLOOD) ........................ ..................................... ......................... ................42 ....42 TOE TO HEEL AIR INJECTION (THAI™) (THAI™)............ ........................ .......................... .......................... ........................4 ............42 2 DILUTION OF HO FOR PIPELINES......................... ...................................... ......................... ......................... .......................43 ..........43 SURFACTANTS, HO, & B ITUMEN ........................ ..................................... ......................... ......................... .......................44 ..........44 “DEAD” OIL AND RECOVERY EFFICIENCY ....................... ..................................... .......................... ......................44 ..........44 STRIPPER WELLS IN THE US ........................ ...................................... .......................... ........................ .......................... .................45 ...45 AN EMERGING EOR CHEMICAL FLOODING PROCESS ....................... ..................................... ...................45 .....45 EOR AND CO2 SEQUESTRATION ........................ ..................................... ......................... ......................... .......................46 ..........46 FLUE GAS & GREENHOUSE GASES ........................ ..................................... ......................... ......................... .....................47 ........47 US FLUE GAS LOCATIONS ......................... ...................................... .......................... ......................... ......................... ...................47 ......47 US LOCATIONS FOR GEOLOGICAL CO2 SEQUESTRATION ......................... .....................................4 ............49 9 FLUE GAS COMPOSITION ......................... ...................................... .......................... ......................... ......................... .....................50 ........50 FLUE GAS PROCESSING ......................... ...................................... .......................... ......................... ......................... .......................50 ..........50 PROCESSING FLUE GAS NOX ........................ ...................................... .......................... ........................ .......................... .................51 ...51 PROCESSING FLUE GAS SO2 ........................ ...................................... .......................... ........................ .......................... .................51 ...51 PROCESSING FLUE GAS MERCURY, HG ......................... ...................................... .......................... .........................5 ............52 2 GREENHOUSE GAS SEQUESTRATION ......................... ...................................... .......................... ......................... ................52 ....52 CO-OPTIMIZATION FAILURE ......................... ...................................... .......................... ......................... .......................... .................53 ...53 HORIZONTAL DRILLING IN PROVEN OILFIELDS......................... ...................................... .......................... ..............54 .54 MICRO HOLE DRILLING ......................... ...................................... .......................... ......................... ......................... .......................56 ..........56 SUMMARY: LIGHT OIL LEGACY, HEAVY OIL DESTINY ......................... ...................................... ..............57 .57 US ENERGY POLICY ISSUES......................... ...................................... .......................... ......................... .......................... .................59 ...59 REFERENCES ........................ ..................................... .......................... ......................... ......................... .......................... .......................... ..............60 .60

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Abstract The Global Industry of Exploration & Production (E&P), refining, transportation, distribution, and sales of hydrocarbons (oil & gas) give and take tremendous influence from and upon International International geopolitical geopolitical economics and and logistics. Based upon environmental, environmental, ecological, personal and national economics, 2009 may mark the beginning of the end of the “Hydrocarbon “Hydrocarbon Age” of of Man. May this Age conclude conclude with as little torment as the Stone Age, ages of Bronze, Iron, Coal, etc... Should this End be near, exit strategies for individuals, companies, companies, provinces, and nations will be required. New information information and technologies are available available to assist with this eventual shift from reliance upon hydrocarbons to fuel our vehicles, heat and cool our buildings, and generally support commerce and culture on all scales. Inventory and study of these data and technologies is vital to promote progress, control human convenience, prevent human tragedy, preserve flora and fauna, foster sustainable ecology and environment, environment, and preserve political stability. Traditional and alternative alternative energy resources must be balanced in delicate compromise and interplay. This document focuses upon some so me aspects of the science, engineering and technologies of E&P, at a college freshman level. The overall role of E&P in upcoming upcomin g events will not be to solve the many many problems now in view. view. Opportunities to forestall forestall identified problems, mitigate their intensity, and reduce their consequences seem apparent, however. Transition to the New Energy Energy Economy will benefit benefit from efforts efforts to sustain and implement good ideas, maximum identification of practical oil & gas resources, and quest for sustainable modifications modifications to current systems. systems. Enhanced oil recovery recovery (EOR), especially as applied to heavy oil (HO) and bitumens, is perhaps the most powerful tool E&P can wield in the near future. Improved national energy policies and environmental policies for many nations may be attainable through through careful study and collaboration collaboration between nations. nations. Our citizens and companies would certainly benefit from application of foresight, practicality, practicality, and timing to enact genuine US National Energy Policy and US National Environmental Policy. Table of Appendices APPENDIX 1. DARCY’S LAW..................................................................................................62 APPENDIX 2. PITCH (ASPHALT) LAKES ..................................................................................63 APPENDIX 3. FAIRWAY JAMES LIME FIELD, EAST TEXAS .......................................................63 APPENDIX 4. EXXON MOBIL ADDS 1.5B BARRELS TO PROVED RESERVES ................................64 APPENDIX 5. OIL FROM CANADA’S TAR SANDS CAN BE MADE ‘CLEAN,’ OBAMA SAYS.........64 APPENDIX 6. ANWR RESIDENTS FAVOR DEVELOPMENT.........................................................66 APPENDIX 7. REVIEWS OF HUBBERT'S PEAK: THE IMPENDING WORLD OIL SHORTAGE ..........66  D ESERT : ........................71 APPENDIX 8. REVIEWS OF MATTHEW R. SIMMONS ’ T WILIGHT WILIGHT IN THE  D APPENDIX 9. RADIAL JET ENHANCEMENT..............................................................................74 APPENDIX 10:........................................................................................................................75 “SURFACTANT-BASED PHOTORHEOLOGICAL FLUIDS: EFFECT OF THE SURFACTANT STRUCTURE” .............................................................................................................................................75

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

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

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global calculations. calculations. The numbers pointed pointed to 2003 as the year of peak peak production, but because estimates of global reserves are inexact, Deffeyes settled on a range from 2004 to 2008. Three things things could upset Deffeyes's Deffeyes's prediction. prediction. One would be be the discovery of  huge new oil deposits. deposits. A second would be the development development of drilling drilling technology that could squeeze more more oil from known reserves. reserves. And a third would be a steep rise in oil prices, which would make it profitable to recover even the most stubbornly buried oil. Above summary is adapted from Scientific American review (See Appendix 7.) of  Deffeyes’ book. While exact dates dates are unknown, analysis of International International sedimentary sedimentary basins indicates that a peak in International oil producing capacity is in the very near future, if not not already past. Simmons’ Simmons’ Twilight in the Desert  (See Appendix 8.), also disturbing, dwells on Saudi reserves and deliverability. The American Petroleum Institute estimated estimated in 1999 that the world's oil supply would be depleted between 2062 and 2094, assuming total world oil reserves at between 1.4 and 2 trillion barrels and consumption at 80 million barrels per day. Geopolitics of International HO & Bitumen Deposits An abundance of information on heavy and extra-heavy oils and what USGS calls “bitumens” was published published at http://pubs.usgs.gov/fs/fs070-03/ http://pubs.usgs.gov/fs/fs070-03/fs070-03.html. fs070-03.html. Table 1 is excerpted from this publication:

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

recoverable Natural Bitumen, BBO

recovery

recoverable

recovery

factor*

Heavy Oil, BBO

factor*

North America

0.19

35.3

0.32

South America

0.13

265.7

0.09

530.9 0.1

W. Hemisphere

0.13

301.0

0.32

531.0

Africa

0.18

7.2

0.10

Europe

0.15

4.9

0.14

Middle East (ME)

0.12

78.2

0.10

Asia

0.14

29.6

0.16

Russia

0.13

13.4

0.13

43.0 0.2 0.0 42.8 33.7

E. Hemisphere

0.13

133.3

0.13

119.7

GLOBAL TOTAL

434.3

650.7

*Recovery factors were based on published estimates e stimates of technically recoverable and in-place oil or bitumen by accumulation. Where unavailable, recovery factors of 10 percent and 5 percent of heavy oil or bitumen in place were assumed for sandstone and carbonate accumulations, respectively.

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Especially for assignment to various classes of oil refineries, crude oils are classified according to their API API Gravities, sulfur content, and other other measured characteristics. characteristics. Thus the implications implications of downstream Refining and Marketing Mar keting components of the Oil and Gas Industry have influenced the Exploration and Production components’ co mponents’ (E&P) view of  crude oil classification. classification. Before quickly reviewing the definition of API Gravity and the International International classifications classifications of various classes of hydrocarbon reservoirs, a quick introduction to the International setting of the known Heavy Oil (HO) and Bitumen deposits and their potential geopolitical significance is provided. An abundance of information on heavy and extra-heavy oils and what USGS calls “bitumens” was published published at http://pubs.usgs.gov/fs/fs070-03/ http://pubs.usgs.gov/fs/fs070-03/fs070-03.html. fs070-03.html. Table 1 is excerpted from this publication: In addition, 212.4 billion barrels of natural bitumen in place is located in Russia 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 and public awareness. HO and bitumens, as strategic strategic domestic resources resources concentrated in the Western Hemisphere, could be key elements in a National Energy Policy . Environmental Bitumen & HO Issues In 2003, the USGS lumped lu mped 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, it has been used before other types of oil. Thus, conventional oil accounts for a declining share of the Earth's remaining oil endowment. In addition to assessing conventional oil resources, scientists of the US Geological Survey's Energy Resources Program collect data on the abundant energy resources available as heavy oil (including extra-heavy oil) and natural bitumen... Historically, heavy oil was found incidentally during the search for light oil and was produced by conventional methods methods when economically feasible. feasible. However, to sustain commercial well production rates, heavy and extra-heavy oil production almost always requires 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 oils by their high viscosity (resistance to flow) at reservoir temperatures, high density (low API Gravity), and significant contents of nitrogen, oxygen, and sulfur compounds and heavy-metal contaminants. They resemble the residuum from the refining of light oil… The Western Hemisphere has 69 percent of the world's technically recoverable heavy oil and 82 percent percent of the technically recoverable natural bitumen. bitumen. In contrast, the Eastern 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. s olvents. Tar sand recovery may also involve surface mining and, similarly, use water, fuels and solvents, and is often unsightly unsightly on profoundly grander grander scales. Tar sand recovery recovery involves strips and open pits of Canadian land.

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Please note that Canada Canada has huge quantities quantities of oil, gas, minerals, minerals, timber, etc. These are on monumental expanses of abundant land remote from population centers, environmental political political success, and tourist attractions. Canadian government government has legitimate, sound, and fortunate jurisdiction over exploitation and their fiscal attitude might be named. Call it “needy,” “greedy,” “greedy,” pragmatic, or statesmanlike, statesmanlike, it is very profitable to the government and perhaps a vital benefit to citizens of the Great White North. The ownership of Canadian mineral royalties by the Crown will always outweigh environmentalism. environmentalism. Canada is perfect for study of exploitation technical technical issues without undue environmental environmental and political restraint. restraint. US E&P professionals face greatly greatly enhanced ethical, moral, and legal issues overprinting those technical issues. Oilfield Jargon and Professions The oil and gas ( O&G) industry contains contains several sectors: sectors: “upstream” exploration exploration and production ( 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 those deeper; deeper ones are called “ downhole” from shallower ones. Equipment Equipment on the ground surface may also be called “uphole,” and those below the surface are usually called “downhole.” All the operations of drilling and producing oil and gas wells are recorded in the well administrative tool. Additional detailed detailed records reside reside in various history, a vital administrative documents (permits, notices) legally required by regulatory agencies. Lease Net Revenues of each Lease are shared by Joint Venture ( JV) holders of Working Interests (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, Legal Accounting and bookkeeping performs normal and exotic accounting for accounts payable and receivable, taxes, and especially Division Orders ( DO’s) by which owners of  working 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: exploration geologists geologists and geophysicists, geophysicists, also called explorationists, pick targets with hopeful potential to discover new oil and gas reservoirs underground. Geophysical data, data, including seismic, seismic, gravity, magnetic, and x-ray fluorescence surveys are used along with data from existing wells (“well control”) in these processes. Geoscience and land land services may may be performed by operating operating company employees or by outside consultants, which may be freelance partnerships between geoscientist 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-

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licensed operating company to “operate” the lease. Later in the lease development process, exploitation and development geologists and geophysicists pick additional well locations to capitalize on existing properties and/or new discoveries. discoveries. Locations are picked for downhole geology and uphole considerations and prepared, numerous other rentals and services are paid, and drilling expenses and liabilities are borne 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 geoscience labor, data, or processing, drilling, workover, recompletion, and stimulation is submitted by operating company to WI holders in an authority for expenditure ( AFE), requiring each WI to consent consent or non-consent. Actual drilling drilling and production production operations are performed in the field using procedures detailed in a prognosis for the operations. Drilling and Petrophysical Engineers Drilling Department: Department: Drilling managers, managers, drilling engineers, and wellsite wellsite foremen (“company men”) men”) track the progress of each each wells while it is being drilled. drilled. Drilling rigs rigs are commonly commonly owned by drilling contractors. contractors. First penetration of ground 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 motorized wrench, as drilling fluid is pumped through the entire “string” of drillpipe to lubricate the drillbit and return rock rock cuttings to wellsite wellsite surface. Drillpipe is occasionally occasionally withdrawn in 60-90’ “stands”; this operation is called “tripping drillpipe.” Geoscientists and/or petroleum engineers evaluate each well is evaluated evaluated after reaches its Total Depth ( TD). An openhole wireline wireline unit is dispatched to wellsite wellsite to run electric electric porosity and resistivity resistivity logs. Petrophysical engineers engineers ( petrophysicists) specialize in casing point evaluation of wells, using well logs, mud logs, cores, well tests, and other data acquired during during drilling process. process. During the casing point point decision the opportunity opportunity for 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 economics are deemed to allow the expense to set production casing, a casing 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 return behind the casing, providing a hopefully strong seal between formation rock layers and production pipe. This “cement job” may be the drilling personnel’s last wellsite duty. Petrophysicists also assist other petroleum engineers and geoscientists to further scrutinize well data for additional opportunities, especially recompletions uphole of the deepest completion, which is almost always performed first. Production and Reservoir Engineers Production engineers: Many petroleum production engineers hand both downhole completion and uphole facilities work, but these activities are discussed separately here. After running a wireline cement bond log to confirm a successful cement job , completion engineers design the downhole system the packers, plugs, and tubing, submersible

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pumps, gas lift valves, valves, and/or rods. They call out a wireline perforating perforating unit, which blasts blasts controlled perforations in the production casing by electrically electrically detonating shaped charges downhole. Perforated interval interval will probably be acidized, acidized, and a swabbing unit may may then check 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 with stairs and walkways for safety. Reservoir engineers assist in justifying the choice of a drilling location location and, with petrophysicists, to evaluate evaluate a well’s success success at TD. They then monitor monitor the data in each field to watch for problems problems and opportunities. They project the oil, oil, gas, and water anticipated from fields for many years into the the future. Economic forecasts forecasts of oil and gas prices are used with these production forecasts to estimate the economic performance performance of  these assets. Reservoir engineers have have primary responsibilities responsibilities for the 10-k Reports required by the SEC for for public corporations. corporations. Ultimately Ultimately these activities activities combine to set a present value ( PV) on each asset, employing discounted discounted net cash flow ( DCNF) method. Reservoir engineers use computer programs called reservoir simulators to match the production histories of fields and for numerical experimentation experimentation to plan waterfloods (WF), enhanced oil recovery ( EOR) projects, and reservoir gas cycling to enhance recovery in retrograde gas and volatile oil reservoirs. They use other programs to analyze the pressure-volume-temperature ( PVT) behavior of  complex reservoir reservoir fluid systems. Along with production production engineers, they use “nodal “nodal analysis” software to analyze and predict the pressure drops that occur in every interval from the perforations at a completion through downhole and uphole equipment all the way to the stock tanks or gathering lines. In the 1970’s, the Environmental Protection Agency (EPA) and Occupational Safety and Health Administration (OSHA) were created just in time for the Oil Boom following the OPEC oil embargo of 1973. Since then the O&G industry has evolved the merging of  these priorities with security to create the acronym “ HSSE” for health, safety, security, and environmental emphasis.

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Crude Oil Classification Crude oil is classified as light, medium, medium, heavy, or extra-heavy, according to its measured API Gravity, based on this crude oil’s specific gravity gravity (SAG), its gravimetric density compared compared to that of water, at 60°F. API Gravity = (141.5 / SG@60°F) - 131.5, so SG = 141.5 / (API Gravity +131.5). This temperature of 60°F is a component of Standard Temperature and Pressure ( STP). The exact temperature of STP has been numerically redefined regularly since the STP concept was introduced. Currently the North America petroleum Industry uses predominantly STP of 60°F and 14.73 psi (to define the natural gas sales unit MCF @STP, for example). example). Natural gas gas companies in Europe and South America have adopted adopted 15 °C (59 °F) and 101.325 kPa (14.696 psi) as their STP. Light crude oil is defined as having an API Gravity higher 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 is defined as having an API Gravity between 22.3°API and 31.1°API. Note the EU defines defines medium medium crude gravity between 25.7° 25.7° API and 31.1°API. Heavy crude oil is defined as having an API Gravity between or 10° and 22.3° 22.3° API. The EU has has a slightly different different definition of of ‘heavy'. Their cutoff  between ‘heavy' and ‘intermediate' lies at 25.7° API Gravity. This causes there there to be more more “heavy” crude oil in their view. Extra-heavy crude oil is generally defined as having an API Gravity below 10°. Graphic copyright Schlumberger "Oilfield "Oilfield Review.” From Carl Curtis and others, 2002, Oilfield Review, v. 14, no. 3, p. 50.

Intermediate Hydrocarbons The continuum of hydrocarbons is best understood within the unified concepts of  fractionation and equilibria related related to deposits of natural gas, volatile oils, and crude oils. These will be discussed in sections below.

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When a wellsite geologist uses a wellsite gas chromatograph (GC) to analyze the combustible gases, these hydrocarbon gases are fractionated to methane (CH 4), ethane (C2H6), propane (C 3H8), and the butanes (C 4H10’s). The 5 gases gases are reported reported as C1, C2, C3, C4, and C5. C4 and C5 are the butanes; butanes; pentane is often often a liquid and thus not always always logged.

Figure 1. Gas Chromatograph display, showing showing a retrograde gas or wet gas response. The butanes are liquids at many winter temperatures. temperatures. The pentanes would be liquids at all common uphole temperatures. All might gaseous in situ , depending upon downhole temperature and pressure. http://www.srigc.com/  http://www.srigc.com/ 

Please note that methane is CH 4, ethane is C 2H6, propane is C 3H8, butanes are C 4H10’s, pentanes are C 5H12’s, and hexanes are C6H14’s. Methane occurring occurring alone alone is often often called natural gas or dry gas; gas; a more inclusive definition definition of dry gas is provided provided below. The collection of ethane through the hexanes, CH 4- C6H14’s, is called intermediate hydrocarbons, or intermediates. The intermediates are discussed discuss ed regularly in classification 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 its only other isomer, isobutane (also called methylpropane)(CH methylpropane)(CH 3)3;; the isobutane molecule is triangular. When the butanes are blended blended with propane and other hydrocarbons, hydrocarbons, it is referred to commercially as liquefied petroleum gas ( LPG). For decades the butane’s, C 4H10’s, were commonly used as fuels, especially in agricultural engines. Propane, C 3H8, and LPG have replaced the butanes in these routine rural 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 during cold weather. Liquid hydrocarbons hydrocarbons do not burn; only hydrocarbon hydrocarbon vapors burn under control by design. Likewise, pentanes, C5H12, and hexanes, C6H14, are liquids at STP.

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All these heavier hydrocarbons require vaporization vaporization by some so me process such as carburation or fuel injection to fuel controlled combustion. Single-Phase Flow in Porous Media Darcy's law is a simple proportional relationship between the instantaneous discharge rate through a porous medium, the viscosity of the fluid and the pressure drop over a given distance. The rate at which which a fluid flows through through a permeable permeable substance per unit area is equal to the permeability, which is a property only of the substance through which the fluid is flowing, times the pressure drop per unit length of flow, divided by the viscosity of the fluid. Darcy’s Law is presented below in its 1D form: The total discharge, Q (units of volume per time) is equal to the product of the permeability of the medium, the crosssectional area (A) to flow, and the pressure drop (P b  )  , all divided by the b  − P a  a), fluid’s dynamic viscosity µ, and the length. Figure 2. Schematic view of Darcy’s Law for single-phase fluid flow through a porous medium.

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 the permeability ( 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 negative sign is needed because because fluids flow from high pressure pressure to low pressure. So if the change change in pressure is negative (in the  x-direction) then the flow will be positive (in the  xdirection). Dividing both sides of the above equation by the Area A results in a more general notation for the differential form of Darcy’s Law:

q = - κ  p / µ. This simple law, detailed in Appendix 1., is completely completely adequate to formulate numerical simulations of saturated saturated groundwater movement. movement. It also describes describes the movement of dry gas and wet gas in downhole reservoirs lacking oil or water, and is completely completely adequate for their numerical numerical simulation. Darcy’s Law is perhaps perhaps the most unavoidable unavoidable buzzword in subsurface reservoir engineering. Dry Gas Reservoirs Virtually all petroleum reservoirs contain some accumulation of methane, methane, CH 4. This methane may be dissolved dissol ved in crude or volatile oil. It may have accumulated as a gravitystable gas “cap” above above a bank of saturated saturated oil. Most oil deposits also contain contain some intermediates. intermediates. Methane in a cap above oil is usually rich in intermedia intermediates. tes. Methane

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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 all common surface atmospheric atmospheric conditions. If a petroleum reservoir contains only only water, methane, ethane, ethane, and/or propane, the deposit is is called dry gas. gas. The dry gas may may also contain butane, C 4H10’s, but these will condense at the surface during cold weather. Dry gas is primarily methane, perhaps including some intermediates. This is the phase diagram of a typical dry gas. gas. Both the line of isothermal reduction and separator condition point are outside the phase envelope. The looping lines within the phase envelope represent constant liquid volume as fractions of total volume. volume. They are called iso-vols or quality lines. The dry gas hydrocarbon mixture is 100% gas in the reservoir, the tubing, at surface, and even at separator conditions. The very light intermediates, C2H6, and/or C3H8, will require processing equivalent to refrigeration for separation from 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 to methane can be very profitable, profitable, however. These are generally 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 3 rd-party midstream midstream specialist. Ethane and and butane may have have markets as petrochemical petrochemical feedstocks or heavy heavy oil diluent. Butane and propane and LPG are also commercial fuels, of course. These most convenient gases can also remain dissolved in natural gas and contribute to the heat value value of the gas. Their contribution should be honored when negotiating gas unit sales value. Specification Specification and timing of the heat value measurement measurement will help optimize pipeline sales contracts. The International International oil markets which swirl with superstition and uncertainty are not completely reproduced reproduced in the Continental markets markets for natural gas. Thus some additional stability occurs in the natural natural gas markets. markets. For the first 100 years of E&P, E&P, markets for natural gas were very limited; many gas discoveries were plugged plu gged as disappointments, and much gas associated associated with oil wells was wasted by flaring. flaring. Great abundance, low prices, gathering, transmission, and distribution pipeline systems combined with oil rationing and labor shortage to accelerate heating with gas during WW2. LNG and Energy Policy Before 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

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deposits and markets. markets. Methane is refrigerated refrigerated to –163°C, -258°F, reducing the methane’s methane’s volume 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 without adequate domestic domestic natural gas supplies. supplies. LNG is a “transparent, “transparent, odorless, non-toxic, noncorrosive,” very cold, very flammable liquid, stored and transported in insulated pressure containers. About 200 LNG transport transport vessels are in service, service, and at least 13 nations export to 17 nations importing importing LNG. LNG prices are sometimes sometimes more than twice twice those for natural gas. In absence of very long pipelines and/or LNG shipments, natural gas supplies are huge geopolitical issues, issues, especially in Eurasia. Europe and Asia rely rely upon former Soviet Republics for natural gas gas supplies. Hopefully the gas gas markets on other Continents Continents will perform less brutally than has Eurasia’s market. About 84% of the US natural gas supply, about 19.3 TCF annually, comes from the approximately approximately 500,000 US natural gas wells and associated gas from a similar number of  US oil wells. About 83% of US gas imports, imports, 3.3TCF annual, come from Canada. Slightly more US gas is exported exported to Mexico than is imported imported from Mexico. The 2% balance of US natural gas needs, 771BCF annual, is met by importing LNG from Trinidad/Tobago Trinidad/Tobago (58%), Algeria, Egypt, Nigeria, Equatorial Guinea, and Qatar. The 8 US LNG import terminals terminals are located located on the Gulf of Mexico coast (4), in Massachusetts (2), in Maryland and and Georgia. Mexico has terminals terminals at Altamira Altamira and Baja California. The US exports LNG LNG to Japan, Mexico, and Russia. The oldest marine terminal has been in service at Kenai, Alaska since 1969, exporting mostly to Japan and other Pacific Rim customers. At least 12 LNG import terminal proposals are now before the FERC, including Atlantic, Pacific, and Gulf Coasts, including including the Pacific Northwest Northwest region. Compared to to 2005 demand, International Internationa l LNG import demand will double in the next few years. With Total’s commitment to develop a terminal in Yemen, that nation is posed to become the World’s newest exporter of LNG. The US natural gas Industry has underwritten moderate product cost increases by its aggressive replacement replacement of reserves since 2000. 2000. The bulk of these new new reserves have been provided by offshore oil and gas fields and unconventional unconventional gas reservoirs (“tight ( “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 domestic strategic resource.

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Wet Gas Reservoirs Wet gas reservoirs produce condensate stock tank liquids, with GOR’s above 5,000 (even (e ven 50,000) scf/STB. The gravity of the stock tank liquid liqui d is in in the 40-50°API 40-50°API range and does not change during reservoir life; GOR is also constant during reservoir life. life. This liquid liquid is usually clear as water. No hydrocarbon liquid exists in the wet gas reservoir downhole. The pressure path line in a wet gas phase diagram does not enter the liquid phase envelope. Separator conditions lie within the phase envelope, however, causing liquid to be formed at the surface.

Figure 4. Phase diagram for a wet gas reservoir. McCain, 1990.

The hydrocarbon accumulations in most petroleum reservoirs are saturated with water due to their contact and and equilibrium with with water. Luckily Luckily the solubility of water in hydrocarbons is low. As a classification, the term “wet gas reservoir” is named, not for water, but for their rich cocktails of downhole downhole hydrocarbons in gaseous gaseous form. Those downhole gases gases that condense in separators at surface facilities are called condensates. These volatile, (brown, orange, or green) translucent and perhaps almost transparent stock tank liquids may contain hexanes and above, pentanes, butanes and limited evaporating propane. propane. In the early oil and and gas business these were sometimes sometimes called “ drip might be burned as gasoline gasoline in a vehicle. Gasoline’s API Gravity Gravity gas” because they might averages 50°, so its SG= 141.5 / (50° + 131.5) = 0.778. 2-Phase Relative Permeability and Fractional Flow The Buckley–Leverett equation or the Buckley–Leverett displacement can be interpreted as a way of incorporating the microscopic effects due capillary pressure in two-phase flow into Darcy's law. law. In a 1D sample sample (control volume), volume), let S( x  x,t ) be the water saturation;  f is the fractional flow rate, Q is the total flow, Ф (φ, phi) is porosity and  A is area of the cross-section in the sample volume. Forward in this primer, subsequent types of oil and gas accumulations will require concepts of 2-phase reservoir reservoir flow. Interfacial Interfacial tension (IFT) forces are responsible responsible for wettability (hydrophilic (water-wet), lipophilic or hydrophobic (oil-wet), or amphiphilic amphiphilic (mixed or “dalmation” wettability)) between oil and rock, and capillarity and gravity segregation between oil, gas, and water and water. In fluid dynamics, the Buckley–Leverett equation is a transport equation used to model two-phase flow in porous media[1] media[1] . The Buckley–Leverett Buckley–Leverett equation equation or the Buckley– Buckley–

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Leverett displacement can be interpreted as a way of incorporating the microscopic effects 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

d pc / 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  x,t ) = S( x  x − U (S)t ) which means that U (S) is the front velocity of the fluids at saturation S. Relative Permeability and Mobility Ratio Especially during the development of reservoir engineering for secondary recovery (waterflooding), the relative permeability concept received generations generations of empirical and theoretical research. A reservoir mobility gas-liquid mobility ratio, M g-l, of gas to liquid, can be defined as 

M g-l = k g µ l / k l µ g where M= µ l and µ g. are the viscosities of the liquid and gas phases, k g and k l are the 2-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, M w-o, gas to oil, M g-o, etc. The

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most interesting relative permeability considerations are in 3-phase reservoir circumstances, where Herb Stone’s 3-phase relative permeabilities permeabilities equations are required to estimate 30-phase data from 2-phase data for use in numerical reservoir simulation simulation programs. Retrograde Gas Reservoirs An initial producing producing GOR of 3,300 to 5,000 indicates a very very rich retrograde retrograde gas. Without pressure maintenance, such a rich gas will condense sufficient retrograde liquid to represent a saturation of 35%. Even such a large quantity quantity of retrograde liquid normally cannot be produced, due to its unfavorable unfavorable mobility ratio as compared to reservoir gas. Economics incentive pressure maintenance and/or gas cycling to keep this valuable solvent/gas in its gaseous gaseous phase! GOR > 50,000 indicates negligible negligible retrograde retrograde effect. Retrograde gas reservoirs produce lightly colored, brown, orange, greenish, or waterwhite stock tank condensates with the same range of API Gravity, 40-50 ° API, as the liquids from wet gas reservoirs. The surface gas is very rich in intermediates; intermediates; it is usually processed to remove propane, butanes, pentanes, and/or heavier heavier hydrocarbons. hydrocarbons. These are often called called plant liquids or plant products. Retrograde gas reservoir phase diagrams have the critical point on the left side. Critical temperature temperature is less than reservoir temperature; the cricondentherm is greater. Initially retrograde gas is totally gas downhole (1); under production pressure may drop to dew point (2). Then liquid condenses downhole. downhole. This liquid is called retrograde liquid. Laboratory phase diagrams indicate lower pressures (3) where retrograde liquid revaporizes. This effect is uncertain in producing reservoirs due to downhole fluid composition 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 drops below the dew-point (2). Retrograde gas reservoirs are cycled with reinjection of miscible gases (especially methane) to facilitate surface liquid recovery. They may also undergo water injection to maintain pressure and retard the retrograde process. Volatile Oils The class of light petroleums that are 100% liquids under initial downhole reservoir conditions, those in the 40-50 ° API Gravity range, is called volatile oils. Volatile oils contain fewer heavy molecules and more intermediates intermediates (ethane through hexanes) than

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crude oils. Note that volatile oils, wet gas, and retrograde gas/condensate gas/condensate reservoirs all have very low viscosity and high API Gravity Gra vity and very low fractions of very large heavy hydrocarbon molecules. molecules. The distinction between between downhole liquids liquids and gases can be arbitrary and/or academic among such light hydrocarbons. Laboratory-determined Laboratory-determined compositions of volatile oils will have mole 12.5-20% heptanes and above. The dividing line between volatile volatile oils and retrograde gases at 12.5% mole percent heptanes plus is fairly definite. When the mole concentration of heptanes-plus is below 12.5%, the reservoir fluid is almost always always gas and exhibits a dew point. When this concentration concentration is above 12.5%, 12.5%, the reservoir fluid is is almost always a liquid and exhibits exhibits a bubble point. Any exceptions exceptions to this rule normally do not meet the rules of thumb regarding stock-tank oil gravity and color. Laboratory observation of a volatile oil will reveal an initial formation for mation volume factor greater than than 2.0 RB/STB. The oil produced produced at point 2. of the Figure Figure will shrink by more than 0.5, often 0.75, on its journey to the stock tank (3 or more stages of surface separation are recommended). recommended). Volatile oils have also been called called “high-shrinkage crude crude oils” and “near-critical “near-critical oils.” The volatile oil reservoir phase envelope critical point is low and close to reservoir temperature. The iso-vols are not evenly spaced; they are shifted upwards toward the bubble-point line. The vertical line shows the path taken by the constant-temperature pressure reduction during production, releasing a large proportion of gas for a small pressure drop. A volatile oil may become as much as 50% reservoir gas at only a few hundred psi below the bubble-point pressure. pressure. Also, an iso-vol with even lower gas proportion crosses the separator condition point. for a volatile oil reservoir. McCain, 1990. Figure 7. Phase diagram for As reservoir pressure drops to point 2 in Figure 4, creation of a secondary gas saturation saturation begins. The secondary downhole downhole gas associated with with a volatile oil reservoir reservoir is very rich, usually a retrograde gas; also, often over 50% of stock tank liquid produced from a volatile oil reservoir reservoir entered the wellbore as a gas. Remember Remember the favorable mobility ratio allowing gas to flow preferentially due to its low viscosity.

The critical temperature of a volatile oil is always greater than the reservoir temperature; temperature; its initial production production GOR is between 2,000 and 3,3000 scf/STB. scf/STB. Producing GOR and stock tank API Gravity increases with primary production.

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Literature Literature is slight on volatile oil deposits. The largest accumulation accumulation I personally observed is the Fairway James Lime Field, East Texas with 410 MMBOIP, of which 213 MMBO had been recovered in 2007 after 4 decades of gas cycling and water injection to maintain reservoir pressure. (Appendix 3.) Another noteworthy volatile oil accumulation accumulation is in Eugene Island , Block 99 , Lease OCSG 21637, 20 miles offshore of Louisiana in the Gulf of Mexico. The extremely poor characterization characterization and operation of this field by Columbia Gas Development Corp. left many millions of barrels of volatile trapped at abandonment despite the extremely low price and high availability of natural gas to optimize recovery by gas cycling. The Properties of Petroleum Fluids By William D. McCain states: “Volatile oils contain relatively fewer heavy molecules molecules and more intermediates, ethane-hexanes [methane is CH 4, ethane is C2H6, propane is C3H8, butane’s are C4H10’s, pentane’s are C5H12, hexanes are C 6H14]. Their critical temperatures are much much lower than for black oils and are close to reservoir reservoir temperatures. temperatures. Their gas-oil ratios ratios (GOR’s) are in the range of  of  2,000-3,3000 scf/STB.” Crude “Black” Oils Note that Dr. McCain wrote the Book, and refers to the non-volatile light oils as “black,” low-shrinkage crude oils, oils, or ordinary oils. So, black oil is a synonym for crude oil, and is expected to have a GOR < 2,000scf/STB, an API Gravity < 45, and to be dark due to presence of heavy hydrocarbons. Black, or crude oils contain a wide variety of chemical species, including those large, large, heavy, molecules molecules resistant to evaporation. evaporation. Black, or crude, oils contain contain more heavy heavy molecules 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 during production. Oil volumes volumes shrink slightly as their dissolved dissolved gases evaporate from this hydrocarbon mixture downhole. Conventional (Light & Intermediate) Crude Oil Intermediate crude oil or Medium crude oil is defined as having an API Gravity between 22.3°API and 31.1°API. Note the EU defines medium medium crude gravity between between 25.7° API API and 31.1°API. Especially the most economically favorable crude oils are classified by API Gravity Gra vity and sulfur content content and given given names. For example, example, Brent Crude is actually a combination of  crude 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 around 39.6 (specific gravity gravity of around 0.827), lighter than than Brent Crude. It contains about 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 and petrochemical petrochemical products is high. Thus its listed market market price is often higher higher than Brent crude. WTI is extensively extensively stockpiled at locations locations like Cushing, Oklahoma. Oklahoma.

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From January 1, 1987 to June 15, 2005, OPEC calculated an arithmetic arithmetic average of seven crude oil streams (known as the OPEC Basket). This basket basket included included Algeria's Saharan Saharan Blend, 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 basket price. Effective June 16, 2005, OPEC's new reference basket consists of eleven crude streams representing the main export crudes of all member countries, weighted according to production productio n and exports to the main main markets. The crude oil streams in the basket are: Saharan Blend (Algeria), Minas (Indonesia), Iran Heavy (Islamic Republic of Iran), Basra Light (Iraq), Kuwait Export (Kuwait), Es Sider (Libya), Bonny Light (Nigeria), Qatar Marine (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 to 34.6º). In addition, the sulfur sulfur content of the new basket basket is more sour (1.77% compared compared to 1.44%). The black (crude) oil phase envelope has the critical point higher above reservoir temperature. Iso-vols are spaced rather evenly within the envelope. Line 123 indicates the reduction in pressure during primary production. Along Line 12, the oil is undersaturated; if more reservoir gas were present, it would dissolve at these higher pressures. Along Line 23, the gas is saturated, and pressure reduction releases gas from the crude oil to form a volumetric pore system saturation of a free gas phase. Figure 8. Phase diagram for for a “black,” or “crude” oil reservoir. McCain, 1990. API Gravity and Heavy Crude Oils (HO)

having an API Gravity Gravity between or 10° and and 22.3° API. The Heavy crude oil is defined as having EU has a slightly different different definition of ‘heavy'. ‘heavy'. Their cutoff between between ‘heavy' and ‘intermediate' ‘intermediate' lies at 25.7° API Gravity. This causes there to be be more “heavy” “heavy” crude oil in 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-heavy crude oils, is presented below.

This indication of oil specific gravity at temperature 60°F places the heaviest of the HO class, with API Gravity = 10°, at the specific gravity (SG) of 1.0 1. 0 (identical to water at 60°F).

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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 for pavement composites. The heaviest crude oils and natural bitumens, composed of very large complex carbonrich hydrocarbon molecules, have very high heat contents . They were were originally originally refined to produce fuel oil, but require specialized refining to yield the petrochemical products in highest demand today. Some of the rarest and most profitable petroleum refineries today are those devoted specifically to processing processing heavy and extra-heavy extra-heavy crude oils. A memorable memorable example is Valero’s Bill Greehey Refinery in Corpus Christi, TX ; one of the most profitable refineries in the USA is refining very heavy oils to produce gasoline and other topprice petrochemicals! The properties of heavy and extra-heavy crude oil and bitumens are very strongly influenced by temperature. temperature. Their form as perhaps perhaps solids, perhaps liquids, is much much different depending depending upon temperature. temperature. The crude oil may may be on the surface at 0.0° C, or at 100.0° C also on location, or at 100.0° C in a thermal recovery process at a depth of  2,000’. These Celsius temperatures temperatures convert to to 32° and 212° Fahrenheit. The very high high kinematic viscosities of these heaviest crude oils and bitumens are especially strongly affected by their temperatures in their various environments. Cumulative percentage of annual production (blue) and cumulative percentage of technically recoverable resources (brown) of heavy oil as a function of oil density (API Gravity) in 2000. Less than 10 percent of the heavy oil produced annually is extra-heavy oil (API Gravity of 10°or less), whereas 33 percent of the technically recoverable heavy oil oi l has an API Gravity Gr avity of 10° 10 ° or less. 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 Athabasca Tar Sands in Canada. Canada. These tar sands are shallow, shallow, and due to their northern northern latitude these shallow deposits are rather rather cool. When the Tar Sands Sands are sampled in core barrels, barrels, only the 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 classes together as …:

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“(USGS) Light oil, also called conventional oil, has an API Gravity Gr avity of at least l east 22° and a viscosity less than 100 centipoise (cP). Heavy oil is an asphaltic, dense (low API Gravity), and viscous oil that is chemically characterized by its content of asphaltenes (very large molecules incorporating most of the 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 ha ving an API Gravity of less than 10°. 10°. Natural bitumen, also called tar sands or oil sands, shares the attributes of heavy oil but is yet more dense and viscous. Natural bitumen is oil having a viscosity greater than 10,000 Centpoise (cP).” Water has a kinematic viscosity of 1.0 cP at 60°F. 60°F. Natural bitumen (often called tar sands or oil sands), extra-heavy and heavy crude oils differ from lighter oils by their high viscosity (resistance to flow) at reservoir temperatures, high density (low API Gravity), and significant contents of nitrogen, oxygen, and sulfur compounds compounds and heavy-metal contaminants. They resemble the refinery 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 original constituents were clay clay minerals or muds. It is “fissile,” “fissile,” its thin laminae breaking breaking with an irregular curving curving fracture, often splintery. splintery. Non-fissile rocks of similar similar composition are mudstones. Related rocks rocks but with less clay and more very very fine-grained silica silica are siltstones. Shale beds are of immense immense importance in E&P E&P as sources, seals, and reservoirs. Their study is also part of the the “shaly sands sands problem” in petrophysics. petrophysics. Every hydrocarbon accumulation relies on its resident reservoir porosity system, a seal and trap to confine the oil and/or gas, and migration of the hydrocarbons from the source formation in which the hydrocarbons hydrocarbons were geochemically geochemically created. created. Those are classically 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 extending over huge areas. By virtue of their very very limited hydraulic hydraulic permeabilities permeabilities and huge volumes, shale beds are the most common “seals” above oil and gas reservoir rocks, serving along with structural and stratigraphic “traps” to confine accumulations of  hydrocarbons. Halite (table salt) formations formations are also also excellent seals by virtue virtue of their low permeability and flowing behaviors of plastic deformation. deformation. Since organic-rich shale beds are the predominant “sources” of hydrocarbons, few of  these beds are lacking in hydrocarbon content. content. Unlike the focused limited limited definition of  shale as a rock type, a thick shale bed’s depositional cycles commonly included silty and sandy episodes, resulting in laminae of sufficient primary porosity containing natural gas to allow these massive beds to serve as gas reservoirs after horizontal drilling and hydraulic fracture treatments. treatments. Thinner shale beds and those with inferior organic organic content do not offer similar potential for gas production.

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An 'oil shale' is neither oil, nor shale. Oil shale contains kerogens (immature

precursors to oil and gas), gas), and theoretically can can be burnt without processing as a fuel. In a documented episode, a personally built mountain cabin was constructed with a fireplace built from “oil shale.” The first fire in that fireplace was a real house warming, and the cabin was destroyed. First Exxon in the 1970’s, then more recently Shell Oil, have invested $ billions attempting to create synthetic oil and gas from “oil shale” in the Rocky Mountain states. Huge technological and environmental challenges challenges remain, and these will be some of the final energy resources exploited in North America. Reservoir Conditions and Fluid Densities The oil and gas Industry’s exploration and production (E&P) activities, a legacy of  observational context based on gravimetric density permeates the views of the geoscientist and engineer. engineer. In this legacy, gas gas floats on oil, and oil floats on water. water. Innumerable geologic crossections, crossections, areal maps, and well log breakdowns are thus aligned. The maps show primary primary and secondary gas “caps” “caps” perched upon rings of light light and intermediate intermediate oils. The oil rings very very often float on aquifers aquifers or smaller deposits of  formation water. The Yates Field Unit of Pecos Co., Co., Texas, is an example: example: After generations generations of injection of possibly every available fluid, including nitrogen, CO2, heated and unheated water, this is still a $billion property. property. The oil accumulation accumulation is now described described as a “seven-foot “seven-foot oil column,” above a water column, below a gas “cap.” Subsurface accumulations of heavy and especially extra-heavy crude oils challenge this gravimetric stereotype. stereotype. The lightest of the extra-heavy extra-heavy crudes have neutral buoyancy in fresh waters. Formation brines brines have specific specific gravities up to about 1.1, but low-salinity low-salinity connate waters may may be gravity-stable above above heavy oils. This density contrast defies defies the Industry stereotype of the oil-water contact, replacing it with a water-oil contact. Reservoir Conditions and Oil Viscosities The API Gravity a crude oil and its basis in specific gravity gravity (SG), based on the density of  water, reflect the molecular molecular weights of their constituent liquid liquid hydrocarbons. Generally liquid hydrocarbon viscosities increase as do their densities, but this correlation exhibits considerable statistical scatter, especially when the various international occurrences of  these very heavy hydrocarbons are examined. Note that while API Gravities of reservoir oils and their gravimetric implications implications are themselves of interest interest in thermal thermal recovery of heavy oil (TRHO), HO’s very high kinematic viscosities have even more impact on their performance under all recovery processes. The primary recovery characteristics of California’s largest fields benefited greatly from their extreme extreme overpressure, however. This extreme extreme pressure regime temporarily overcame the disadvantage disadvantage of the very high viscosities of the HO’s, and was probably greatly influenced by the region’s pronounced tectonic stresses. This discussion assumes subject HO’s have viscosities more than 50 times that of water

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under reservoir conditions. conditions. This is consistent with real HO’s under recovery using using TRHO options. Reservoir Conditions, Porosities & Wettabilities Perhaps the most accessible parameters in reservoir characterization characterization are average porosities. Perhaps the least accessible parameters parameters in reservoir characterization characterization are wettabilities. A reservoir pore may be primary (created during sedimentary deposition) or secondary (created during lithification or diagenesis diagenesis long after sediments sediments are deposited). The primary porosity systems may be intergranular, especially in sandstones, siltstones, and even in shales (thus the current wave of “shale gas” projects which has added significant US natural gas reserves through combined use of horizontal drilling and hydraulic hydraulic fracturing technologies). technologies). Porosity systems may be intercrystallin intercrystalline, e, karstic, fractured, or all of the above, especially in carbonate reservoir reservoir rocks. Wireline compensated compensated neutron lithodensity combinatio combination n porosity logs lo gs give average reservoir porosity measurements with accuracy ranging ranging from excellent to barely barely adequate. Generally these nuclear nuclear porosity 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 cling electrostaticly electrostaticly to hydrophobic surfaces. Water will will cling similarly to hydrophilic surfaces. surfaces. These concepts are easily demonstrated demonstrated in simplistic experiments. Many reservoir porosity systems exhibit mixed, checkerboard, or “Dalmatian“ nonuniform wettabilities. wettabilities. Since many techniques techniques to evaluate evaluate reservoir systems’ wettability states and distributions unfortunately involve alteration of these states, wettability evaluations are very difficult. Primary Oil Recovery Drive Mechanisms Primary recovery in oil reservoirs depends on a primary reservoir drive mechanism. Hydrostatic and/or lithostatic forces have charged the co mpressible oil accumulation with potential energy. Gravity drainage occurs when heavy oil "drips" down through the reservoir porosity system into production production wells. This is significant significant in reservoirs with depleted depleted pressures. If the oil is saturated with gas, a primary gas cap may exist gravity-stable above banks of  oil and water. If the water water bank is small, small, water drive drive will not be significant. In gas cap drive, the very high compressibility co mpressibility of natural gas may allow the gas cap’s expansion to significantly support support pressure and maintain maintain reservoir energy during during production. With great care, oil production may be controlled and limited to prevent premature fingering of  a gas bank into production production wells. Since gas has has very low viscosity and very high high mobility ratio, this is a difficult engineering task. Volatile and crude oils without water drive often depend upon dissolved gas drive (DGD). This mechanism, mechanism, also known as depletion drive, drive, is especially important important in the early period of high production rate sometimes called flush production. Above bubble point, the oil enters the wellbore without gas liberation or significant reduction of 

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reservoir potential energy.

Figure 10. Schematic cross sections sections of 3 basic reservoir drive mechanisms: mechanisms: depletion or dissolved gas drive, gas cap drive, and water drive.

As the DGD oil reservoir’s pressure drops during production, it eventually reaches bubble point, and gas is liberated liberated from the oil. oil. Especially near near the wellbore, regions regions of  free gas occur. Viscosities and mobility mobility ratios predict predict preferential flow of gas, gas, and the producing GOR increases. increases. Oil composition composition is thus changed, and reservoir reservoir oil gradually gradually shrinks slightly and loses much much of its natural gas gas and intermediates intermediates content. Without pressure maintenance operations the reservoir’s oil loses its potential energy, becomes heavier and more viscous. This undesirable and destructive loss of DGD oil reservoir energy can be prevented by instituting a pressure maintenance plan before reservoir pressure drops significantly below bubble point. Encouragement Encouragement or requirement of such such conservation measures measures is admirably institutionalized institutio nalized in Canada and China, for example. The US E&P Industry is now super-mature way beyond much benefit from such regulation in any emerging energy policy, however. An oil reservoir with an oil-water contact directly connected to an extensive aquifer may benefit from the aquifer’s advance toward production wells, water drive. Given adequate management to moderate production and minimum heterogeneity regarding reservoir/aquifer reservoir/aquifer permeability, a large aquifer may support reservoir pressure for a generation before the the free water impinges impinges upon production wells. wells. These water drives drives may be considered strong and active (large aquifer moving quickly as oil is produced), moderate, or weak. Original Oil in Place and Recovery Efficiency A reservoir engineer’s evaluation of an oil deposit begins with calculation of original oil in place (OOIP). (OOIP). This calculation calculation is simple: simple: multiply the volume of the the oil accumulation accumulation by its average porosity porosity by its porosity-weighted porosity-weighted oil saturation. After volumetric volumetric units like acre-feet are converted to barrels of oil (BO), an estimate of the original oil in place in BO results. The Lower 48 States States of the US abounds with counties counties which have produced produced over 1 billion BO; some of these records were set before WW2, and very many have followed. The ratio of cumulative cumulative oil recovery recovery to OOIP, in BO, is called recovery

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efficiency.

In carefully engineered conditions, under the most fortunate drive mechanisms and other reservoir details, more than half of OOIP (50%) may be produced during primary recovery. This is most likely under under conditions of strong water water drive, very high reservoir reservoir porosity, and permeability, with moderate drawdown of bottomhole bottomhole tubing pressure (BHTP). The bank of water moves toward the oil column as the oil column moves moves toward the wellbore, maintaining downhole reservoir pressure. Along with oil fields on land where the oil column is in direct contact with a very large aquifer, these conditions are especially likely in marine settings like the Gulf of Mexico (GoM). Occasionally a column column of reservoir reservoir brine may even outcrop 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 drive seldom approach approach such high recovery efficiency efficiency as 50%. Accumulations Accumulations depending upon DGD never approach such a high value of recovery efficiency, and the economics of  primary production eventually eventually becomes marginal, leaving most of OOIP remains in the reservoir. Recovery efficiency efficiency under primary primary recovery for DGD reservoirs ranges ranges from 3% to 30%, at an average of around 12%.

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

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Consequences of Oil Reservoir Depletion In the Lower 48 States States of the US, during primary recovery, recovery, most active active oil fields produce by the dissolved gas drive ( DGD) primary recovery mechanism, also called depletion drive. As was just mentioned, mentioned, drawing an oil reservoir’s reservoir’s far below bubble point quickly quickly promotes a premature premature severe change in downhole downhole reservoir conditions. conditions. Several changes changes in the reservoir’s character are then inevitable: 

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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 rich in intermediates, having been in contact with oil. Thus methane and intermediates are progressively stripped stripped from the oil, making the oil heavier. Eventually the 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” “shrinking” within the reservoir pores. Additional pore space is thus evacuated. Oil may shrink into the the less accessible volumes of the porosity system. This reduced oil saturation increases increases relative permeability to gas, enhancing the already-unfavorable oil-gas mobility ratio. The progressively heavier oil becomes be comes more viscous, “thickening” in viscosity, further enhancing the unfavorable oil-gas mobility ratio. High gas flow rates near the wellbore enhance the stripping of reservoir oil from the completion 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 is seldom as high as 20%.

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

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displace oil to producing wells begin. Before launching the complicated complicated study and economic expense of EOR, oil fields may be waterflooded, with all the the issues mentioned mentioned above. The unfavorable unfavorable viscosity ratio between water and most crude oils enhances the bypassing of oil banks and premature breakthrough of water banks banks during WF. This secondary recovery recovery process also provides provides invaluable information regarding reservoir characterization, characterization, however. After economic performance of a waterflood unit becomes inadequate, the operator may propose additional measures measures to increase the unit’s profit profit and producing life. life. These measures are collectively collectively known as enhanced oil recovery ( EOR) or tertiary recovery. Screening Producing Oil fields for WF & EOR The bases for planning and organizing a WF or EOR operation can perhaps be divided into these components: 

reservoir rock (depth, permeability, porosity, wettability) characterization

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oil properties (especially viscosity)

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reservoir drive mechanism

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water quality and availability

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analog field examination

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pilot projects, and

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Unitization.

When screening oil fields regarding WF, heterogeneity, heterogeneity, continuity, and non-oil-bearing non-oil-bearing reservoir volumes (“thieves” or “thief zones”) are dominant reservoir characterization characterization issues. The geologic geologic thieves may be connected connected aquifers below the hydrocarbon hydrocarbon column column and/or wet areas on its flanks. Due to the limitations of cement jobs, major WFs often inadvertently inadvertently provide pressure maintenance in uphole uphole and even downhole downhole reservoirs. These unplanned flows flows can enhance oil well performance, performance, even even on relatively distant distant adjacent leases. These operations problems problems may also be regarded regarded as thief zones. They are huge huge windfalls for nearby ventures receiving this free pressure maintenance. maintenance. The accepted methods to screen a field or lease for secondary recovery (WF) are reservoir characterization characterization and subsequent subsequent study of analog fields. fields. Both these steps are best taken in concert concert between engineering engineering and geosciences. The next step before unitization for WF is the choice of an area of the field for a pilot WF involving a reasonable number number of injectors and producers. This and all other other decisions preliminary preliminary to unitization 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 of  3,592 feet in the Woodbine sand on September 5, 1930, and flowed 300 barrels of oil per day, and was completed completed on October 5, 1930. This landmark landmark discovery was followed by multitudinous additional additional successful wells. wells. 30,340 wells have been drilled drilled within its 140,000 acres. Located in central Gregg, Gregg, western Rusk, southern Upshur, southeastern southeastern

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Smith, and northeastern Cherokee counties in the east central part of the state, is called the largest and most prolific oil reservoir in the contiguous United States. The magnitude of the field’s reserves and productivity set off many unique precedentsetting events in understanding mechanisms of oil recovery (the primary recovery mechanism of water drive, for example), example), pipeline construction, and production regulation. The price of a barrel barrel of oil dropped from about $1.00 to $0.10 and below below during the 1930’s. Roosevelt’s New Deal administration, the US Congress and Supreme Court’s crablike attack of the “hot oil” problem combined with Texas executive, judicial, and legislative steps to provide authority to regulate and limit oil and gas production to the Texas Railroad Commission. Commission. These were direct results results of overproduction overproduction from the East Texas Texas field. By January 1, 1993, cumulative cumulative East Texas Texas field oil production from was reported as 5,145,562,000 barrels, perhaps not including huge volumes of “hot oil” stolen in the 1930’s. Originally skeptical operators were convinced by 1938 that ultimate recovery of the field's production production depended upon the conservation conservation of its water-drive mechanism. mechanism. They initiated a pressure maintenance program by re-injecting produced salt water into the aquifer, reducing the rate of pressure decline. Thus produced formation water had advanced from the status of inconvenience or nuisance 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-term advantages in operation of oil fields. Early commencement commencement of re-injection of produced water from oil wells, and injection of water from water supply wells is now a hallmark of  foresight in reservoir engineering, especially in Canada and China. Waterflooding & Hot Water Injection A waterflood (WF) pilot or unit attempts to mimic the natural strong water drive, which is one of the most efficient drive mechanisms mechanisms observed in primary pri mary recovery operations. operations. Waterflooding is also called secondary recovery. Banks of of this injected water can displace banks banks of oil toward producing wells wholesale. wholesale. Reservoir rock heterogeneity heterogeneity and wettability cause some oil banks to be bypassed, however, as water banks break  through prematurely prematurely at production wells. This premature premature water breakthrough breakthrough is greatly enhanced when reservoir reservoir oil is many times times more viscous than reservoir water. water. This viscosity contrast is called an unfavorable mobility ratio. Hot water injection, injection, the most basic and probably probably the earliest thermal thermal recovery technique uses water heaters at surface injection facilities to provide hot water for injection. Remember the term term “hot” is relative, relative, especially under cold cold surface conditions. The warming of water for injection can be a vital measure measure in its overall assistance to field operations. Especially when some heavy oil or fractions are involved, accumulations of paraffin or other solids can be major themes themes in maintenance. Field facilities professionals professionals routinely

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employ “heater-treaters” “heater-treaters” to remediate 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 operator production component. component. So, the ability to bring bring this practicality practicality of heating water water at a water injection site is a very important important option. Combined with general general detergents and industrial chemicals to control injectant properties, heating water is just a routine industrial activity. WF’s can also be augmented by using additives to increase the viscosity of injection water, thus reducing mobility ratio problem and premature water breakthrough, and constituting an element of chemical flooding (CF). Why Waterfloods Under-perform The Petroleum Technology Transfer Council (PTTC) workshop on Permian Basin ( PB) waterfloods presented these “top 10” list reasons why waterfloods under-perform: 

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Misunderstanding Misunderstanding reservoir heterogeneity: The carbonate reservoirs reservoirs of the the PB are notoriously heterogeneous. Petrophysical and geological review of existing existing and new well logs, including correlation of injection and production data are vital to refine descriptions of these porosity systems. Injecting above formation fracture pressure enhances heterogeneity and premature water breakthrough. It can be avoided by automatic control of water injection systems systems and automatic monitoring of wellhead pressures using satellite satellite communication. IHS and competing vendors have this technology for hire; h ire; in-house networks may be contracted for projects 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 emerging EPARS technology help to mitigate this with crude oil analysis ana lysis 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, a well is usually shut in and eventually converted to water supply or injection. Out-of-zone injection, related to incorrect inco rrect 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, to provide adequate treatment for injection inje ction water and employment of optimum well treatments.

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

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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 be achieved, and some operators actually achieve achieve rates of 0.25 per well per year or less.” Chemical Flooding (CF) Introduction Chemical flooding ( CF), involving surfactants to reduce interfacial tension (IFT) between oils and water and polymer gels to increase water viscosity, is an augmentation of the waterflood process. CF has been the subject of major oil company and service company research and and development development for many decades. Surfactants to reduce reduce oil-water IFT can act similarly to household detergents, dissolving oil fractions in the injected aqueous phase. Engineered Engineered aqueous polymers increase increase water viscosity viscosity to reduce unfavorable oil-water oil-water mobility ratios. ratios. A variety variety of “recipes” has been researched, researched, and many have had field trials. Perhaps the most proven and successful CF method is the micellar or micro-emulsion flood, in which a slug of a stable solution of oil, water, alkalines or surfactant(s), and salt electrolytes is injected injected to reduce interfacial and capillary forces. forces. This slug then displaced by a slug of high-viscosity mobility control buffer polymer solution, and finally followed by 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 /polymer flooding. Alkaline Flooding and ASP Perhaps 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 to produce surfactants that dramatically lower IFT between oil and water, creating emulsions to entrain and and mobilize oil. oil. These caustics also react react with reservoir reservoir rock  surface to modify wettability. Caustic slug injection may be preceded by a “preflush” of  low-salinity water and/or followed by a viscous mobility-control slug injection. The alkaline flooding and ASP concepts deserve the increased attention they are currently receiving. Some alkalines, alkalines, like sodium hydroxide (NaOH, “lye”, “lye”, or “caustic “caustic soda), famous for cleaning drains, dissolving organic matter, making soap, and its extreme solubility in water with liberation of heat, are so inexpensive inexpensive as to lend themselves to economic performance in well-configured recovery processes. Alkaline industrial industrial waste products are also readily readily available. available. Wood ash, for example, example, can be processed to provide provide a low cost environmentally environmentally friendly alkali. alkali. Emerging laboratory laboratory and field technologies to refine the designs of chemical floods should be especially effective on alkaline flooding applications due to their potentially low chemical costs. Surfactants, Micelles, Type I Micro-emulsions Surfactants are broadly defined as organic compounds that can enhance cleaning efficiency, emulsifying, emulsifying, wetting, dispersing, solvency, foaming, defoaming, and lubricity of water-based compositions. compositions. Surfactants Surfactants are produced from petrochemical petrochemical (synthetic) (synthetic)

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feedstocks or oleochemical oleochemical (biological) (biological) feedstocks. They can stabilize stabilize mixtures of oil and water by reducing the interfacial surface tension (IFT) at the interface between the oil and water molecules. molecules. Because water and oil do not dissolve in each other, other, a stable homogeneous mixture ( emulsion) requires a surfactant to keep it from separating into layers. Soaps and detergents are surfactants. surfactants. Sodium dodecyl sulfate sulfate (SDS) is an example of a regularly studied anionic surfactant. The word "surfactant" is the shortened shortened form of "surface-active "surface-active agent.” agent.” Surfactants accumulate at interfaces due to their amphiphilic natures: The hydrophilic hydrophilic “head” segment ( moiety) of a surfactant molecule molecule (monomer) is polar, like like water. Another “tail” “tail” hydrophobic moiety moiety of the molecule is is nonpolar, like oil. Surfactant molecules molecules accumulate at the oil-water interface with their polar moiety in the aqueous phase and their non-polar moiety in the oil phase, minimizing Gibbs free energy. A surfactant solution solution has three components: components: surfactant monomers monomers in the aqueous solution, micellar aggregates, aggregates, and monomers adsorbed as a film at the interface (surface of bubble, oil-water, etc.) etc.) The surfactant is in dynamic dynamic equilibrium equilibrium among these components. Each micelle is a dynamic structure. When the aqueous surfactant concentration exceeds critical micelle concentration (CMC), surfactant monomers selfaggregate into spherical or wormlike monomer aggregates called micelles. The micellar aggregate of “n” micelles has stability (relaxation time, n τr ) in the range of  milliseconds (ms) to seconds, seconds, breaking and reforming reforming rapidly. A large relaxation relaxation time represents high micellar micellar structure stability. Relaxation time time correlates quantitatively quantitatively strongly 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 water phases, an emulsion is called a microemulsion. An oil-in-water oil-in-water (Type I) I) microemulsion microemulsion can be formed with micelles’ polar micelle exteriors in contact with water phase, and nonpolar micelle interiors containing oil. Micro-emulsion Types II & III Oil-based drilling fluids are composed primarily of diesel fuel, often configured as a water-in-oil ( Type II) microemulsion. microemulsion. Oil-soluble surfactants surfactants form inverse micelles micelles with their tails exterior and their heads interior, where water is trapped. In an oil reservoir, a surfactant will partition between oil and water phases according to the monomer’s relative hydrophilicity; surfactant hydrophilic-lipophilic balance ( HLB). 

Water-soluble surfactant mixtures with micelles have HLB’ of abou t 20. For transitional mixtures, 8 < HLB < 12.

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Oil-soluble mixtures with inverse micelles have HLB’s a round 5.

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Chemical system conditions can be varied to force water-soluble surfactants to partition into the oil phase. For example, in an ionic ionic surfactant system, system, increasing water water salinity can lower HLB and force force surfactant monomers monomers to partition into the oil phase. phase. HLB’s for nonionic surfactant systems are decreased with temperature temperature increases. At aqueous surfactant concentrations >10-20 times CMC, high micelle concentrations

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can produce “middle phase” oil-in-water microemulsions with ultra-low oil-water IFC’s to mobilize oil trapped by IFC in a porous reservoir. To achieve a middle phase microemulsion ( Type III) system, HLB is adjusted so surfactant is ready to leave the water phase, but not to enter the oil phase, so the monomers accumulate accumulate at the surface. Since all the surfactant cannot fit in the interface, a new “middle” phase forms, containing oil, water, and virtually all the surfactant, in middle phase equilibrium with free oil and water phases . Theoretically, these middle achievement under reservoir microemulsions do not break with time , so their achievement conditions is a very favorable goal. Surfactants in E&P Other 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 su spending, biocides.

These oilfield surfactants are involved in well stimulation, drilling, cementing completion, production, refining, refining, and pipeline transport, as well as EOR. EOR and other downhole applications require surfactants that meet demanding downhole environmental environmental regulations and performance performance requirements. requirements. Emulsifiers Emulsifiers to allow oil and water to mix perhaps perhaps require the majority majority volume of oilfield oilfield surfactants. The dramatic rise in oil and gas prices, peaking in 2008, caused significant increases in EOR activity and demand for more effective EOR processes and materials. materials. This has stimulated market demand for specialty, higher cost surfactants such as cationics and amphoterics amphoterics (anionic or cationic cationic depending on conditions). conditions). These are more costly costly than nonionics and anionics (negative charge on surface-active moiety) but perform more effectively. Interest in use of surfactants for EOR in HO and bitumen reservoirs reservoirs is beginning to compete with with traditional emphasis emphasis of thermal recovery of heavy oil ( TRHO). Polymers, Gels, and Gelation Polymers, macromolecules, macromolecules, high polymers, and giant molecules molecules are high-molecularhigh-molecularweight materials materials composed of repeating subunits. Natural organic organic polymers include polysaccharides polysaccharides (or polycarbohydrates) such as starch and cellulose, nucleic acids, and proteins. A gel is a continuous solid network enveloped in a continuous liquid phase; the solid phase typically occupies occupies less than 10-volume 10-volume % of the gel. Gels can be classified in terms of the network structure. structure. The network may may consist of agglomerated 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;

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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 free liquid. Thus, the gel seems seems to resemble a saturated saturated household sponge, but it is distinguished by its colloidal colloidal size scale. The dimensions dimensions of the open spaces and of the solid objects constituting the network are smaller (usually much smaller) than a micrometer. Thus the interface joining the solid and liquid phases has an area on the order of 1000 m 2 per gram of solid. As a result, interfacial interfacial and short-range forces, forces, such as van der Waals, electrostatic, electrostatic, and hydrogen bonding, control control the properties of a gel. gel. Factors that influence these forces, such as introduction of salts or another solvent, application of an electric field, or changes in pH or temperature, temperature, affect the interaction between the solid and liquid phases. The process of gelation, which transforms a liquid into an elastic gel, may begin with:

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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

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the initiation of a chemical reaction that creates or links polymers.

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Conversely, the reason that water cannot be gently squeezed out of such a gel is that the network of solids has a strong affinity for the liquid, and virtually all of the molecules molecules of  the liquid are close enough to the solid-liquid s olid-liquid interface interface to be influenced by those attractive attractive forces. The most striking feature feature of a gel is its elasticity. elasticity. If the surface of a gel gel is displaced slightly, it springs back back to its original position. position. If the displacement displacement is too large, gels, except those with polymers linked by covalent bonds, may suffer some permanent plastic deformation, because the network is weak. Oilfield Polymers and Gels Commercial oilfield oilfield polymers include solid beads to adsorb hydrocarbons as well as gels. The gels are available available in both dry powder and very very dense and viscous viscous “liquids.” Xanthan Gum, for example, is a polysaccharide polysaccharide biopolymer well known to have excellent performance in high salinity brine. “Standard” EOR polyacrylamides have molecular weights in the >12,000,000 range and are suited for bottomhole bottomhole temperatures 90 °C, have molecular weights in the 40. Heavier oils at 22 < API API gravity < 32 require reservoir reservoir depths of about 4,000’ to 2,800, respectively. Precise experimental oil-CO 2 MMP measurements are performed in specialized laboratories, and have required generations of research for their development. Computational estimates of oil-CO 2 MMP’s also continue to be topics of intense research. Experience with many CO 2 floods in the Permian Basin of West Texas has yielded two Incremental recovery recovery from Rules of Thumb for recovery efficiency under CO 2 flooding. Incremental miscible 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 OOIP is left abandoned in the reservoir after tertiary recovery! recovery! Remember, however, that that recovery efficiency is sensitive to the price of oil and other economic parameters.

EOR for HO Fields: TRHO Many of the known HO deposits exist in sandstone reservoirs; CA’s most prolific oil fields are examples. Thus, the use of water or steam for downhole injection may activate downhole clay minerals, minerals, causing these clays clays to swell. This swelling is a notorious mechanism to reduce formation permeability by the blocking pore throats by swelling and/or migrating migrating clay crystals. Water must be procured procured and treated for injection, injection, and motors must be operated to inject the water. Industry introductions introductions of thermal thermal recovery of heavy oil ( TRHO), steamfloods ( SF) and cyclic steam injection ( CSI), were based on waterflood experience and/or use of heat to handle oil on surface production production facilities. facilities. Steam was generated generated at the ground surface surface and substituted for water as as an injectant as in a waterflood. waterflood. When a bank of super-heated super-heated steam progresses in an oil reservoir,  

oil viscosity is reduced as temperature increases. Reservoir pressure is increased through

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

additional water volume



partial distillation of the oil.

Whether SF or CSI was introduced introduced first is not clear. The discovery of the SCI SCI process is attributed by at least one source to a steamflooding steamflooding accident in Venezuela noticed by Shell in 1959. I suspect this was the independent independent discovery discovery of a secret proprietary proprietary and confidential unpatented stimulation treatment already being performed behind locked lease gates in CA and perhaps elsewhere. By 1966 the Kern River Field’s production rate had exceeded its 1904 rate of 47,100 BBL/day. This California achievement achievement almost almost matched the total daily oil oil production rate of the entire State of Texas! Cyclic Steam Injection (CSI) The most basic step in TRHO is cyclic steam injection ( CSI). This is a single-well stimulation method in which high-pressure steam is generated at the ground surface for injection into 1 or more wells. After a period of injection into each well, the same well is temporarily converted to a period of production. Between steam injection and production periods there is an idle period, allowing additional fluid flow flow and heat transfer, leading to the term “Steam “Steam Soak.” This cycle is repeated while recovery is economic; it is also called “huff ‘n’ puff.” Advances in the details improving the CSI option of TRHO were introduced and developed in prolific HO deposits like the Kern County area of California (CA), Venezuela and Indonesia. Indonesia. Many of the legendary legendary CA producing fields were identified identified around 1900, so today they are some of the most super-mature assets in the USA, leaving remaining recoverable 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 in petrophysical, geological, 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 effectiveness effectiveness eventually declines over its period of application. Wellbore heat absorption absorption limits limits CSI formation depth to less than 3,000ft 3,000ft (1,000m). The requirement of surface steam generation depends upon the procurement and treatment of  water for injection, the use of natural gas to generate steam from said water, and the management of related environmental issues. Steamflooding (SF) CSI has continued as a mainstay of TRHO, holding steady in CA during the period of  relatively relatively low oil prices in the Industry Industry slump ending in 2005, for example. example. During this period WF recovery declined in CA. The employment of more advanced techniques such as Steamflooding (SF) and In-Situ Combustion (I-SC, also called Fireflooding) has been in flux over the same period. The Steamflood rationale combines some waterflooding principles and some CSI principles. Downhole injected injected steam warms the oil to reduce reduce its viscosity. viscosity. This effect is

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reduced by absorption of steam heat by the reservoir rock, water, wellbore, and adjacent formations. Employment Employment of SF has gradually increased increased since 1995; these SF projects projects often enhance or replace CSI processes. As for CSI, wellbore heat absorption limits formation formation depth for SF to less than 3,000ft (1,000m). Steam condenses downhole downhole to yield yield liquid water. As with CSI CSI and WF, these wet processes have dangerous dangerous possibilities of clay clay activation. Their requirement requirement of  surface steam generation depends upon the procurement and treatment of water for injection, the use of natural gas and treated water to generate steam, and the management of related environmental environmental issues. Regarding reservoir characterization, 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 characterization data. The financial expenses and the physical issues are so enhanced for SF, however, that characterization characterization must be truly sophisticated during the screening, pilot, and unitization phases. Loss of effective effective injection to various various thieves and injectant bypassing bypassing oil no longer involves only treated water and its injection horsepower, but also heating cost and the increased complexity of SF facilities. In-Situ Combustion (I-SC, or fire flood) The incentives to reduce uphole heat loss, clay activation, and various environmental environmental issues have accumulated to motivate research and production personnel to seek  alternatives to the wet methods mentioned above. So, the In-Situ Combustion (I-SC) process, also called fire flood or fireflood, has benefited from considerable analysis, experiment, experiment, and discussion. discussion. In-situ combustion combustion is a flameless dry process. process. As a bare minimum, minimum, oxygen oxygen (O 2) must must be injected. O 2 (pure, atmospheric with Nitrogen, staged or otherwise combined) then reacts with a downhole fuel flamelessly to heat the reservoir rock and HO. Reliance upon reservoir HO alone as a downhole fuel is a convenient notion, but probably impractical. impractical. Methane, a solvent, and/or other staged staged and/or optimized additives additives are probably required required to engineer this combustible combustible injectant. injectant. Note that CH 4 and O2 combine to form CO 2 and H20 in combustion, along with at least traces of CO (carbon monoxide) and perhaps O 3 (ozone), so such such a process is not completely completely dry! CO 2 is, of  course, desirable since it will will dissolve in water and and oil at low pressures. Larger fuel molecules would yield more complex combustion product compounds. Theoretically, Theoretically, I-SC avoids wellbore heat loss, most of the water involved with CSI and SF, and some surface environmental environmental issues. I-SC introduces, introduces, however, many complex complex physical issues like ignition method, choice of fuel(s), choice of O 2 or mixture, sources of  these, the flameless processes visualized downhole, and the details of their effects on rock and HO. Toe to Heel Air Injection (THAI™) Toe to heel air injection (THAI) is a new method of extracting oil from heavy oil deposits, which may have significant advantages over existing methods, including

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previous I-SC implementations. implementations. The method method was developed by Malcolm Greaves of the University of Bath and has been patented by Petrobank. THAI™ is an evolutionary evolutionary new combustion process that combines a vertical air injection well with a horizontal production production well. During the process process a combustion front is is created where part of the oil in the reservoir is burned, generating heat, which reduces the viscosity 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 producing well, recovering an estimated 80 percent of the original oil-in-place, oil-in-place, while partially upgrading the crude oil in-situ. Combustion continues continues as long as air is injected, injected, estimated at about five years. years. Combustion gasses gasses bring the mobilized 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 in vertical injection injection well. After this initial period, for the estimated estimated 5-year project life, neither water nor natural natural gas is used. The second quarter quarter test report indicates indicates oil cut is over 50%. No new water is added after after the first three months; months; produced water water combines condensed previous steam, reservoir water, and combustion combustion product. Petrobank estimates that THAI will recover 70% to 80% of oil originally in place (OOIP). If 10% of the oil originally originally in place were burned burned in the process, this would leave leave 10% to 20% of the oil originally in place in the ground. According to the Petrobank website, besides yielding 70% to 80% recovery efficiency, 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 a s 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% in the high-grade, homogeneous areas where steam methods can be used. Dilution of HO for Pipelines Extra-heavy oil requires addition of diluents (gas condensate, natural gas liquids, or light crude) to enable pipeline transport. transport. Extra-heavy Extra-heavy oil must also be chemically upgraded to reduce density and remove remove contaminants for refinery refinery feedstock. In recent Venezuelan Orinoco heavy oil belt projects, 1 barrel of diluents is required for every 3 or 4 barrels of  extra-heavy oil produced. Horizontal wells and optimally positioned lateral branches equipped with improved electrical submersible submersible or progressing cavity pumps can deliver up to 2,000 BO/day in the Venezuela’s Orinoco Orinoco heavy oil belt. Horizontal well costs costs dropped in recent years, and and this extra-heavy crude oil is commercial. Fuel use for reservoir injection and facilitating transport to upgrading facilities is still significant. In 2001, concession operators operators still planned to increase increase Orinoco production production to

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600,000 barrels of extra-heavy oil per day by 2005, however, and to sustain that rate for 35 years. (Petroleum Review, 2001, v. 55, no. 653, p. 30). Surfactants, HO, & Bitumen In Venezuela, from 1980 to 1984, PDVSA, jointly with British Petroleum, developed a new method to reduce reduce the high cost of transporting transporting bitumen by pipeline. pipeline. This effort resulted in new and simple technology to process Cerro Negro bitumen, known as Orimulsion. In this proprietary proprietary process the bitumen bitumen is mixed with water and a surfactant surfactant chemical chemical in order to produce a stable emulsion, which can be transported by pipeline and by ship in a similar way as fuel oil. Orimulsion is an emulsion of approximately 70% natural Cerro Negro bitumen 8.5° API suspended in 30% fresh water by means of mechanical energy and the addition of less than 1% alcohol-based surfactants (emulsifiers) that allow the bitumen droplets to remain suspended suspende d in a stable mode. mode. This product can be easily handled at room temperature and with standard equipment. equipment. Furthermore, the presence presence of water improves improves the combustion characteristics characteristics of the natural bitumen. bitumen. PDVSA’s BITOR division enjoyed enjoyed massive international success due to Orimulsion’s 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 eastern operating division and not expanding production of Orimulsion because it could make more profits from Venezuelan extra-heavy oil and bitumen selling blends or syncrude instead of Orimulsion. PDVSA intended to fulfill long-term contracts, which BITOR had with utilities in Canada, Denmark, Italy, and Japan, but to discontinue any contracts in negotiation negotiation and close UK, UE, and North American American operations. This leaves a huge huge vacuum for related technologies to replace Orimulsion. www.soberania.org/Articulos/articulo_1375.htm

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

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crude oil “dead”, lacking methane and intermediate hydrocarbons, and thus more viscous and dense than its original character. Yet, of the 430,000,000,000 barrels of crude oil proven to be in place within the various oil-bearing formations throughout throughout the United States and Canada, no more than 25% of  that crude oil, on the average, average, has actually been recovered, recovered, leaving about 325,000,000,00 billion barrels of crude oil still in place within the various rock formations. Stripper Wells in the US In the United States of America, one out of every six barrels of crude oil produced comes from a marginal oil well, and over 78 percent of the total number of US oil wells are now classified as such. There are over over 400,000 of these wells in the the United States, and together they produce nearly 900 thousand barrels of oil per day, 15 percent of US production. These are are known known as stripper wells. Many of the huge population of stripper wells lie in these fields; some are tiny accumulations accumulations known as “single-well fields.” Until a field reaches reaches a critical size with quite 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 and abandoned. The resultant loss in oil oil revenue is significant: significant: more than than $3.0 billion in lost oil revenue at the the 2003 average world world oil price. Until improved improved economics occurs, especially based on oil pricing, these wells cannot be replaced by drilling replacement wells. During this interminable interminable period period local, regional and National National payrolls, rental fees, fees, property taxes, and balance of trade are lost. Some may even be temporari temporarily ly 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 feasible due to geologic or environmental environmental limitations. limitations. Industry badly needs needs new EOR alternatives. Petroleum geochemists geochemists have investigated long and hard to provide analysis analysis and operations to bridge the gap between a stripper well and enhancement of its economics and longevity. http://stripperwells.com

An Emerging EOR Chemical Flooding Process One such bridge is a proprietary proprietary technology technology presented by EPRS Energy. Dr. R C Ropp, VP of Technical Affairs, Fellow and Certified Chemist of The Royal Society of  Chemistry (London) (London) has patented this process. EPRS performs performs the patented chemical chemical analysis to characterize each specific accumulation of crude oil. A concentrated stimulation treatment chemical is then designed specifically for the accumulation at hand, and EPRS sends a team to that specific location to implement that treatment. treatment. About a barrel of this aqueous aqueous chemical concentrate concentrate is injected injected per well, followed by a “chaser” slug of 15-20 barrels of water to displace and dilute the engineered concentrate. A reaction between heavy components of the crude oil’s hydrocarbon molecular molecular weight

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range and the contents contents of the engineered engineered concentrate forms forms natural gas downhole. The result of this effect can be compared to TRHO’s “distillation,” “distillation,” Miscible Recovery’s mixing, or even the catalytic cracking reactions performed in petrochemical refineries. Reservoir crude oil is thus depleted of these unfavorable heavy fractions fractions and restored with light hydrocarbons. hydrocarbons. Some of the restored methane methane and intermediates intermediates dissolve in the enhanced reservoir crude, and some remains as a free gas phase downhole. The reservoir crude crude oil is thereby rendered rendered less dense and less viscous. API Gravity is increased. Reservoir and wellhead wellhead pressures increase. Post-treatment Post-treatment wellhead wellhead pressures as high as 1600psi have been achieved. EPRS has experimented with about 65 different crude oils from all o ver the US and has generated significant significant gas volumes from each. each. The EPRS chemical chemical flooding technology technology exhibits considerable potential to accomplish these effects in accumulations accumulations of heavy and extra-heavy crude oils. oils. This may extend extend even to tar sands, bitumens, bitumens, and even the kerogens in “oil shales.” shales.” EPARS is one E&P’s E&P’s newest alternatives in the field of EOR. EOR. EOR and CO2 Sequestration New opportunities for environmental remediation, increased oil production, and job creation are emerging due to recently identified global and US priorities to reduce emission of greenhouse greenhouse gases into into the atmosphere. atmosphere. Naturally, CO 2 withheld from such release must be impounded (sequestered) somewhere. The mature and successful EOR technique of miscible displacement relies primarily on programs to inject CO 2 into oil reservoirs as a “solvent” to mix and dissolve with reservoir oil, including additional injection injection of various grades of water for reservoir fluid mobility control. control. There is a growing growing inventory of existing CO 2 sequestration EOR ( CO2volume of related literature on screening for and coS-EOR) projects, and an expanding volume optimization of new CO 2-S-EOR opportunities. Energy and environmental agencies have strong interest in co-optimization co-optimization of EOR by gas injection and greenhouse gas sequestration ( EOR-GGS) by disposal of CO 2, CO, oxides of nitrogen, H 2S, SO2, etc., as exist in flue gases and especially in output of oil and gas processing plants. plants. There are enough enough EOR-GGS examples around the the world (Algeria, Australia, Canada, Norway, etc.) in operation or post-proposal stages to help EPRS avoid previous wrong turns in planning. planning. Two prominent Canadian Canadian projects are the the widely publicized Weyburn Pilot Project in Saskatchewan and the much more interesting Zama oil field in Alberta. The Zama Field project injects both CO 2 and H2S from its nearby processing plant into the top of a Devonian pinnacle reef. Oil is produced from a completion near the reef  bottom, making this this project somewhat gravity-stable. gravity-stable. A shallower well serves serves to monitor leakage of these “acid gases.” These projects also use the term term “carbon “carbon sequestration.” E&P companies companies are prepared to seek industrial sources of CO 2 and other greenhouse gases (especially output from gas processing plants which scavenge these gases from crude oil and/or natural gas, and perhaps flue gases from power stations), and to formulate plans to sequester these

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undesirable emissions underground. Flue Gas & Greenhouse Gases New opportunities for environmental remediation, increased oil production, and job creation are emerging due to recently identified global and US priorities to reduce emission of greenhouse greenhouse gases into into the atmosphere. atmosphere. Naturally, CO 2 withheld from such release must be impounded (sequestered) somewhere. The mature and successful EOR technique of miscible displacement relies primarily on programs to inject CO 2 into oil reservoirs as a “solvent” to mix and dissolve with reservoir oil, including additional injection injection of various grades of water for reservoir fluid mobility control. control. There is a growing growing inventory of existing CO 2 sequestration ( CO2-S) EOR (CO2-S-EOR) projects, and an expanding volume of related literature on screening for and co-optimization of new CO 2-S-EOR opportunities.

US Flue Gas Locations Energy and environmental agencies have strong interest in co-optimization co-optimization of EOR by gas injection and greenhouse gas sequestration ( EOR-GGS) by disposal of CO 2, CO, oxides of nitrogen, H 2S, SO2, etc., as exist in flue gases and especially in output of oil and gas processing plants. plants. There are enough enough EOR-GGS examples around the the world (Algeria, Australia, Canada, Norway, etc.) in operation or post-proposal stages to help EPRS avoid previous wrong turns in planning. planning. Two prominent Canadian Canadian projects are the the widely publicized Weyburn Pilot Project in Saskatchewan and the much more interesting Zama oil field in Alberta.

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The Zama Field project injects both CO 2 and H2S from its nearby processing plant into the top of a Devonian pinnacle reef. Oil is produced from a completion near the reef  bottom, making this this project somewhat gravity-stable. gravity-stable. A shallower well serves serves to monitor leakage of these “acid gases.” These projects also use the term term “carbon “carbon sequestration.” E&P companies companies are prepared to seek industrial sources of CO 2 and other greenhouse gases (especially output from gas processing plants which scavenge these gases from crude oil and/or natural gas, and perhaps flue gases from power stations), and to formulate plans to sequester these undesirable emissions underground. So, actual feasibility of co-optimizing EOR , especially the gas-injection gas-injection processes of  immiscible and miscible displacements, displacements, is a crucial issue to be questioned in every realistic sense. 



Characterization of flue gas compositions, especially flue gases f rom the gas-fired and coalbe fired power plants which dominate the US power utility industry. Can flue gases be directly injected into oil reservoirs for these the se EOR processes? If processing is required to prepare flue gases for EOR injection, what are the nature, scale, and expense of these processes? processes? Will existing flue gas processing methods be adequate, or must additional techniques be researched?

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US Locations for Geological CO 2 Sequestration

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Flue Gas Composition CO2 is NOT the only only greenhouse gas: nitrogen oxides, NOX, are considered MUCH more hazardous, for example . Unprocessed flue gases are seldom good candidates for EOR by gas injection due to their very high (78-80%) atmospheric nitrogen (N2) content. Fuel Choices & OSHA: Chemical Species 

Natural Gas

Fuel Oil

Coal

78-80%

78-80%

78-80%

10 – 12%

12-14%

2-3%

2 -6 %

50

70-110ppm

70-160ppm

NO-25, NO2-5*

50-70ppm

50-110ppm

OSHA TWA *ceiling, ppm

Nitrogen, N 2  2  Carbon dioxide, CO 2  2 

5000

Oxygen, O 2  2  Carbon monoxide (CO) Nitrogen oxides (NO x  x )   Ammonia, NH 3  3  Sulphur dioxide (SO 2  2 )  

50

7% 1%

Used in removal of NOx.

H2S-20*, SO2-5

180-250ppm

Hydrocarbons (C X  XH    Y  Y )  

>2,000ppm

200lb/year/plant

Fly Ash 

none

minimal

12%

Table. Summary of flue gas gas composition ranges for power plants fueled by gas, oil and coal. Given these inconvenient contaminants contaminants it is no surprise that that EOR by flue gas injection injection has been discontinued, sometimes converted to nitrogen n itrogen injection, in most projects which attempted that EOR implementation. implementation. OSHA’s TWA limits are are allowed for 8-hour personnel shifts. OSHA’s Ceiling limits should should not be exceeded at any time for personnel.

Flue Gas Processing An 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 produce required chemical reactions. Incineration reaction results results depend on composition, 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 adso rb 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. temperatures. These devices have been adapted to “ionic” “ionic” household air cleaners. Wet scrubbers can accept high-temperature moist flue gas to remove particulates and/or gaseous contaminants. Dry scrubbers (cooling followed by carbon, lime or sodium reagent injection, and fabric “baghouse” filter) can remove re move particulates.

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

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inflammable. inflammable. Carbon monoxide, monoxide, like oxygen, has an affinity affinity for iron-containing molecules, and it is about 210 times more effective in binding to iron-containing iron-containing haemoglobin than oxygen. oxygen. Blast furnace furnace gas contains contains 25% carbon monoxide. monoxide. Coal gas, gas, which was used as a fuel in Europe up until North Sea (natural) gas became plentiful, plentiful, contains 16% CO. Processing Flue Gas NO x Nitrogen oxides ( NOx) occur in all fossil fuel combustion, through oxidation of  atmospheric nitrogen (N 2) and also from organic nitrogen fuel content, and flue gas NO x concentrations concentrations are enhanced by high combustion combustion chamber temperatures. temperatures. Nitric oxide (NO) oxidizes with time and forms nitrogen dioxide ( NO2), a brown, toxic, water-soluble gas 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 with both species: 4NH3 + 6NO  5N2 + 6H2O, 8NH3 + 6NO2  7N2 + 12H2O. Use of ammonia in NOx reduction technologies technologies or for flue gas conditioning can have a substantial balance-of-plant balance-of-plant impact impact on coal-fired plants. plants. Ammonia adsorbs adsorbs on fly ash within the flue gas processing system as both free ammonia and ammonium sulfate compounds, however. This ammonia can then desorb during subsequent transport, disposal, or use of the fly ash. This desorption of ammonia ammonia presents presents several technical technical and environmental concerns concerns as fly ash disposal occurs in surface water water and landfills. landfills. SCR can optimize optimize the NH 3-NOx reduction with a minimum of downstream problems developed by ammonia slip. Processing Flue Gas SO 2 Almost all hydrogen sulfide, H2S (OSHA “ceiling” = 20ppm), oxidizes within a day to SO2. SO2 is smelly, toxic, and contributes to acid rain. SOX can be removed from flue gas by dry alkaline adsorption before particulate removal. Addition of sodium bicarbonate into the flue gas causes it to react in the following manner: 2NaHCO3  Na2CO3 + H2O + CO2. This allows for the sodium carbonate to react with the oxygen and sulfur dioxide in the flue 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, complete, awaiting capture of solid sodium sulfate particles. In wet limestone scrubbing after particulate removal, limestone slurry in water comes into contact with the flue gas SO2 + CaCO3 + H2O  CaSO3 + H2O + CO2. This calcium sulfite (CaSO 3) is then oxidized to form calcium sulfate, CaSO 4, gypsum.

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Contaminants in “sheet rock” made from recycled gypsum are suspect household environmental hazards. Processing Flue Gas Mercury, Hg Since the average mid-sized coal-fired plant releases at least 200-300 pounds of  mercury per year, and mercury pollution has immense environmental impact, mercury emission control is receiving large “doses” of money and professional attention, and benefits from specialized industry knowledge. knowledge. Oxidized mercury, mercury, Hg 2+, and Hg bound to particles is easily removed with ESP’s or wet flue gas desulfurization (FGD); removal of free elemental mercury is more challenging. Technologies that impact mercury speciation include most existing air pollution control methods: Selective Catalytic Reduction ( SCR) mercury oxidation is gaining emphasis for mercury removal, since it is often already used to remove NO x; sorbent injection, dry scrubbers, dry and wet ESP's, and wet scrubbers are oldest and most commonly commonly employed methods. The accepted existing activated carbon mercury sorbent process is that it takes many, many times more more pounds of carbon per pound of mercury mercury removed. Since the average average mid-sized plant releases at least 200-300 pounds of mercury per year, it equates to anywhere from four hundred thousand to almost four and one half millions pounds of  injected carbon needed needed per year. Once polluted with mercury mercury and captured, this carbon carbon is useless, cannot be recycled, and must sit in a landfill. ADA’s patented Mercu-RE process has been introduced to provide a sorbent which can be 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 NO X pollutants, and those can then pass through the system as nitrogen gas, without the problem of ammonia a mmonia slip contaminating contaminating fly ash. http://www.wshinton.com / 

Greenhouse Gas Sequestration US Federal agencies DOE, DOI (especially USGS), and EPA are showing strong interest in co-optimization co-optimization of EOR by gas injection and greenhouse gas sequestration ( GGS) for disposal of COX, NOX, H2S, SO2, CXHY, etc. There are enough EOR-GGS EOR-GGS examples around the world (Algeria, Australia, Canada, Norway, etc.) in operation or post-proposal stages to help researchers, planners, and developers avoid previous wrong turns in planning. Regarding power stations, separation of greenhouse gases from N 2 in flue gases seems a dominant problem, since N 2 injection is only favorable for gravity-stable EOR displacement of light oils (API Gravity > 30 °) at depths beyond the common range of oil reservoir depths. depths. So, most US oil fields would would be eliminated “out” “out” of screening processes for injection of raw flue gas. A possible example that might screen “in,” regarding depth, reservoir pressure, and

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

Co-optimization Failure The deepest oil reservoirs reservoirs are generally shallower shallower than 20,000 feet. The Semitropic Semitropic Field in California produced produced oil from an interval interval between 17,610-18,060 17,610-18,060 feet. Heat levels at those depths eventually "cook" the oil, converting it to natural gas. Mexico’s Cantarell Field is considered the world’s biggest N 2-injection project, producing 500,000 BO/D incremental incremental in recent recent reports. Bechtel/IPSI’s Bechtel/IPSI’s 2001 design report explores all the problems with flue gas injection and several other processes, culminating in the choice of N 2 injection to provide pressure maintenance, maintenance, immiscible displacement, and increased increased production in the huge Cantarell project. project. That report all but eliminates the practical potential for flue gases as EOR solvents. The extensive contamination of flue gases, reported in Table above, makes their processing to eliminate N 2 a chemical engineering design nirvana, but a construction and maintenance infinite infinite nightmare. nightmare. All those greenhouse greenhouse contaminants in flue gas, gas, including COX, are associated with corrosion corrosion and/or toxicity. In the gas injection injection EOR processes they would not be processed once; they would be processed indefinitely in cycles for the life of the project. www.ipsi.com/Tech_papers/cantarell2.pdf

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

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

Figure 13. Geologic cross-section illustrates advantages for reservoir exploitation (increased initial potential, IP, and ultimate u ltimate recovery, OR) and surface land conservation advantages of directional drilling. http://www.americandirectionaldrill.com.

In the last 10 years the Natural Gas Industry has invested the time and money to perfect most aspects of directional drilling and measurement while drilling (MWD) to replace considerable fractions fractions of US natural gas consumption. consumption. This has moderated moderated pricesand exploded the performance performance of tight gas wells. Along with the the “slick water” fracture fracture treatments treatments this has created most of the “unconventional” shale gas plays like the Barnett Shale.

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Figure 14. American Directional Drilling’s VR-500 eliminates man y traditional drilling components, such as draw works, cables, manual tongs, and catheads, which reduces injuries and downtime. Standard Operating Procedures limits the need for crewmembers to be on the drilling floor, which contributes to improved improved jobsite safety. Push/Pull Thrust and Rotary Torque Torque for increased working power and reserve capacity. capacity. The Best-In-Industry Top Top Head Drive equipped 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 drilling operation. Operators also have the ability to to immediately start a horizontal curve curve after surface penetration resulting in greater g reater access to shallow formations, possibly as shallow as 1,200’. www.americandirectionaldrill.com.

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

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due to sensitive reservoir clays. Horizontal drilling in such settings has multiple appeals: 

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Initial production Potential (IP): Vertical completion, sandstone, vertical vertical thickness 40’, for example, 50,000 BO cumulative, can be completed across a 4,000’ horizontal interval. Ultimate Recovery (OR): Horizontal completion contacts contacts much more formation volume, volume, especially banks of oil bypassed by b y previous development, and may be expected e xpected to produce at least 10 times the vertical completions’ cumulatives. As is already demonstrated for thermal recovery of heavy crudes, low-permeability sands with viscous intermediate crudes are horizontal drilling d rilling targets.

New drilling rig designs allow horizontal “kick-off” from vertical wells at much shallower dep ths, allowing targeting shallower oil reservoirs.

Micro Hole Drilling Figure 13. Small trailer mounted coiled tubing “Micro Hole” system. DOE and LANL funded design, which uses coiled tubing, mud motor, bent bit sub, reduction gear sub, and ultra-compact steering tool.

Horizontal depth can be far less than 1,000’.

Figure 15. Schematic displays its hole diameter range vs. conventional hole sizes.

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Micro-hole drilling has the potential to greatly reduce the cost of drilling shallow and moderate-depth moderate-depth holes for exploration, field development, development, long-term subsurface s ubsurface monitoring and, to a limited degree, degree, actual oil and gas production. It also offers greatly enhanced reservoir imaging, imaging, making access to data cheaper and more precise, as well as being invaluable during exploration activities. These new low-cost production capabilities are needed to invigorate the domestic oil and gas industry so that more of the petroleum resources in the USA's mature basins can be recovered. Dedicated boreholes boreholes with permanent permanent reservoir monitoring systems systems will provide high-resolution, real-time information while monitoring and optimizing improved oil recovery recovery (IOR) processes. This low-cost, long-term, long-term, improved imaging imaging method of monitoring fluids in the reservoir will enhance oil recovery and allow dedicated boreholes for reservoir monitoring, eliminating production interruptions. Summary: Light Oil Legacy, Heavy Oil Destiny USGS: HO & Bitumen “In spite of an immense resource base, heavy oil and natural bitumen accounted for only about 3 billion barrels of the 25 billion barrels of crude oil produced in 2000. Compared to light oil, these resources are generally more costly to produce and transport. Also, extra-heavy extra-heav y oil and natural bitumen must usually be upgraded by reducing their carbon content or adding hydrogen before they can be used as feedstock for a conventional refinery. The extra production, transportation, and upgrading costs explain why development and production of extra-heavy oil and bitumen are still limited. Their abundance, strategic geographic 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 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 extracted from Alberta oil sand deposits that are too deep to surface mine by a process known as steamassisted gravity drainage drainage (SAGD). Production wells could produce in excess of 2,000 barrels of bitumen per day. (USGS) Graphic Graphic copyright Schlumberger "Oilfield "Oilfield Review.” From Carl Curtis and 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

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the wholesale finding, developing, recovering, transporting, and refining of Light and Intermediate grades grades of crude oil. Virtually all the Earth’s Earth’s remaining remaining reserves of these most convenient feedstocks feedstocks occur in the Eastern Hemisphere. These geopolitical geopolitical settings include many governments that are unstable and/or unfriendly to the USA and its allies. Emerging technologies and geopolitical pressures are pointing to future enhancement enhancement of  and reliance upon the recovery recovery of heavy heavy and extra-heavy oils. This same trend applies applies to large deposits deposits of natural bitumens, especially especially regarding tar sands. It is time to study study and plan for the large potential environmental environmental consequences of commercial recovery of these vast resources. In 2001, about 735,000 barrels per day were extracted by mining and by in-situ production from Alberta oil sands, accounting for 36 percent of Canada's total oil production. Projected 2011 production production is 2.2 million million barrels per day (Alberta (Alberta Energy and Utility 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 solid hydrocarbons. This is an example of of E&P’s historic unfamiliarity unfamiliarity with deposits deposits of heavy and extra-heavy crude oils and bitumens.

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US Energy Policy Issues In review, key issues in formulating for mulating a US Energy Policy for the 21 st Century include: 

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Excessive reliance upon light and medium crude oils to provide the refined domestic products necessary for domestic commerce, science, health, and welfare continues toda y. This reliance is despite the heavy concentration of global heavy oil and bitumen resources in California, Canada and South America. A precarious state of up to 250,000 25 0,000 stripper wells continues in the the US. These wells produce only a few barrels of oil daily, at most. Economics of these are extremely extremely sensitive to oil price. They contribute significantly to to US production, reducing balance of trade problems and reliance upon unreliable unreliable International sources. The stripper well aggregate also contributes greatly to their local economies, providing ad valorem tax base, local payrolls, specialty materials purchases, royalty contributions, and surface rentals. New Enhanced Oil Recovery (EOR) alternatives are needed to improve recovery and prolong production of crude oils from old fields with critically low reservoir pressures and/or advanced “deadening” of their original crude oil compositions. At least one of these is available for licensing and implementation today. The “Peak Oil” concept has recently emerged, describing a theory that the International oil production rate is now nearing its peak. The theory is that oil production rate will soon decline and continue its decline indefinitely. If this production rate peak occurs, occurs, huge waves of price increases and/or regional shortages are inevitable, with potentially dire economic and 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 in 2000. It is now proven, and new rig designs are ready for US oil fields, perhaps in combination with waterflooding waterflooding and/or EOR. Micro-holes will also be very helpful. helpful. Another anomaly of high oil prices will occur soon: Pricing in 2010 will average about $75/BO. Now is the time time to explore and develop the remaining very large large structures of Alaska, while existing field activities support healthy infrastructure, lending “critical mass” to moderate the huge costs of such geoscience and engineering projects under such challenging conditions. Residents of Kaktovik, the only people living on the Coastal Plain Plain of ANWR, support oil and gas development in in their 'back yard'. yard'. (Appendix 6.) Natural gas is a domestically strategic resource. Its use to generate electric power and even power motor vehicles could result result in premature depletion in North America. Future generations could have no recourse but to heat their homes with coal. Burning coal in power plants and biofuels biofue ls in vehicles are examples of available substitutes. Emissions from coal fired power plants can be scrubbed. Use of coal to generate electric power is perhaps the best way to conserve natural gas and assist transition to alternative energy sources like wind, solar, solar, and nuclear technologies. To mitigate pollution, 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 th eir economics. Emerging technologies: Prolonging stripper production, improving EOR processes, wind, solar and bio-fuel technologies, recycling, and especially for scrubbing the emissions from power plants fueled by high-sulfur coals, are technologies that will experience exploding demand in the coming generations, decades, and even immediately. US technological leadership: If the US is not a pre-eminent provider of at least the design of such technologies, our Nation will will have to procure them overseas. Such a circumstance would represent tragic loss of International prestige, National revenue, and a myriad of opportunities both tangible and intangible.

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References  Hubbert'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 - Matthew

R. Simmons, 448 pages, Wiley (June 10, 2005) Heavy Oil and Natural Bitumen -- Strategic Petroleum Resources, Richard F. Meyer and Emil D. Attanasi : USGS Fact Sheet 70-03, August 2003 - Online Version 1.0. http://pubs.usgs.gov/fs/fs070-03/fs070-03.html

The Properties of Petroleum Fluids, McCain, William D., Jr., 596 pages, Pennwell Books, 2 Sub edition (April 1990) ISBN-10: 0878143351 ISBN-13: 978-0878143351. “LNG Update”, Maslowski, Andy: Well Servicing Magazine, Nov./Dec. 2008, pages

43-46. Petroleum Reservoir Rock and Fluid Properties by Abhijit Y. Dandekar.

“Effect of Wettability Alteration on Relative Permeability Curves for Low Permeability Oil-Wet Reservoir Rocks,” 2004, L. Qingjie, L. Li, Manli, Research Institute of  Petroleum Exploration and Development, PetroChina. http://www.scaweb.org/assets/papers/2004_papers/1-SCA2004-39.pdf

S.E. Buckley and M.C. Leverett Leverett (1942). "Mechanism of fluid fluid displacements in sands.” sands.” Transactions of the AIME  (146): 107–116. http://stripperwells.com

Standard Handbook of Petroleum and Natural Gas Engineering, Second Edition

(Complementary (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.html SRI Instruments - GC, HPLC, Data Systems, Hydrogen Generators www.srigc.com/ www.americandirectionaldrill.com www.xtremecoildrilling.com www.offshore-technology.com/features/feature758/

www.rmotc.doe.gov/Pdfs/RSFFeb06.pdf  Radial Jet Enhancement (RJE) (www.encapgroup.com (www.encapgroup.com)

http://en.wikipedia.org/wiki?title=Talk:Tar_sands http://peswiki.com/index.php/Direct http://peswiki.com/ index.php/Directory:Microbial_Enha ory:Microbial_Enhanced_Oil_Recover nced_Oil_Recovery y

“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.

Slider, Ed 2, Worldwide practical petroleum reservoir engineering methods , H. C. "Slip" Slider, PennWell Books, 1983, 616. Regarding micellar micellar polymer polymer flooding, HK van Poollen &

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

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

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Appendix 1. Darcy’s Law Henri D’Arcy ( ′där·sēz ′lö) was the French civil engineer who discovered these valuable connections 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 rate through a porous medium, the viscosity of the fluid and the pressure drop over a given distance. http://www.answers.com/topic/darcy-s-law  fluid mechanics ) The law that the rate at which a fluid flows through a permeable ( fluid substance per unit area is equal to the permeability, permeability, which is a property only of the substance through which the fluid is flowing, times the pressure drop per unit length of  flow, divided by the viscosity of the fluid. http://www.answers.com/topic/darcy-s-law Darcy's law states that where the Reynolds number is very low, the velocity of flow of a fluid through a saturated porous medium is directly proportional to the hydraulic gradient. For example, the flow of groundwater from one site to another through a rock is proportional 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 point at which flow is being calculated (the hydraulic head ), ), V is the velocity of flow, P is the coefficient of permeability 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-jointed limestone, 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 the  permeability (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 negative sign is needed because because fluids flow from high pressure pressure to low pressure. So if the change change in pressure is negative (in the  x-direction) then the flow will be positive (in the  xdirection). Dividing both sides sides of the equation by the area and using more more general notation leads to where q is the flux (discharge per unit area, with units of length per time, m/s) and is the pressure gradient gradient vector. This value of flux, often often referred to as the Darcy Darcy flux, is not the velocity which the water traveling through the pores is experiencing[2]. experiencing[2]. The pore velocity ( v) is related to the Darcy flux ( q) by the the porosity (φ). (φ). The flux is is divided by porosity to account for the fact that only a fraction of the total formation volume is available for flow. The pore velocity would be the velocity velocity a conservative tracer would experience if carried by the fluid through the formation. http://en.wikipedia.org/wiki/Darcy's_law

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Appendix 2. Pitch (Asphalt) Lakes (of Trinidad, Venezuela, and California) http://www.semp.us/publications/biot_reader.php?BiotID=485

A pitch lake is a deposit of natural asphalt in a “great expanse of more or less mobile character, covering many acres, and resembling in many ways a similar expanse of  water”, said petroleum geologist Clifford Richardson Richardson in 1917. (1) The most classic of of all pitch lakes is Trinidad Lake in the Caribbean West Indies’ Island of Trinidad, but other pitch lakes exist throughout the world, including the Bermudez Lake in Venezuela, and the Rancho La Brea “Tar” Pits in Los Angeles, California. The meanings of the related terms  asphalt, petroleum, bitumen, pitch, tar and   hydrocarbons, are continuously evolving. evolving. Their meanings meanings emanate from certain certain times and 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 of  these often soggy, belching, smelly, weeping sores of the Earth’s crust. Appendix 3. Fairway James Lime Field, East Texas Still Developing After 48 Years Robert E. Webster, David Luttner, and Lawrence Liu  Hunt Oil Company, Dallas, TX 

Fairway (James Lime) Field, in Henderson and Anderson counties, Texas, trapped volatile 48° oil in the Aptian Aptian age James James Lime member of the Pearsall Pearsall Formation. The reservoir is a large patch reef complex of varied carbonate facies that grew on a paleobathometric paleobathometric high in the interior platform platform of the Lower Lower Cretaceous shelf. shelf. For reservoir management purposes, the James is divided into an upper “A” zone with reefderived 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 uniform fine grainstone. grainstone. Porosity and permeability permeability average 12.5% 12.5% and 33 mD in the “A” zone zone and 12.9% and