Abstract In today's competitive market it is increasingly important to improve production and increase reserves in the most efficient way possible. One alternative is to add new wells, but this can be an expensive and time-intensive endeavor. Another alternative is adding and optimizing production from the thousands of existing wellbores already in place. To do this, the ability to detect and evaluate bypassed hydrocarbons and track fluid movement in the reservoir is vital. Current methods of through-casing saturation determination using nuclear tools are limited because of their shallow depth of investigation. With the introduction of the CHFR* cased hole formation resistivity technology a new dimension has been added to cased hole evaluation. A deep-reading formation resistivity can now be obtained through steel casing. Although this measurement is analogous to exsisting techniques for saturation determination, it has two distinct advantages: In many cases there is a need to monitor saturation changes in a producing interval. In the past sigma-based interpretation methods were the only option. However, saturation determination in low-porosity reservoirs (<15 pu) using sigma requires a very detailed and accurate lithology description because small errors in the lithology answer have a significant effect on the saturation from sigma. Because many reservoirs in the Permian Basin combine complex lithology with low porosity, answers can be somewhat unreliable. This is often the case in shallow water-flooded carbonates, where the presence of gypsum, anhydrite and salt makes sigma measurements almost impossible to interpret. Cased hole saturation is also needed to detect bypassed pay and occasionally as the primary evaluation method. In these cases, sigma-based measurements fail because of their shallow depths of investigation. Because the zones have not been produced yet, the invading fluid (brine) still occupies the pores around the borehole. This is particularly true in the Permian Basin because no fluid control measures are used during drilling and deep invasion is normal. The CHFR tool reads deep enough to avoid this complication. In fact, it is commonly superior to openhole resistivity since it reads significantly deeper than openhole resistivity tools. When the CHFR tool is used in conjunction with porosity and lithology tools, run either in openhole or through casing, accurate hydrocarbon saturation can be determined. This methodology can be used to find bypassed pay or to determine the depletion level of producing pay intervals. It has also been used extensively in time-lapse surveys to evaluate the sweep efficiency of secondary recovery, ensuring that no producible hydrocarbons are left behind. This paper reviews the application of this technology in several U.S. basins, including the Permian Basin and California. Introduction Ever since Conrad and Marcel Schlumberger first began measuring formation resistivity in 1927, scientists have been working to evolve the measurement to work in all types of conditions. Arguably the most challenging has been adapting the measurement to operate in a cased hole environment. While the measurement principle is quite simple, making it through conductive steel pipe requires highly advanced instrumentation. Potential differences in the nanovolt range must be measured accurately to make the measurement of formation resistivity possible. The CHFR tool provides this technology. Porosity devices such as neutron and sonic tools have been characterized for cased holes for years. However, the ability to calculate water saturation that enables direct comparison to openhole evaluations using standard equations requires the formation resistivity. The CHFR tool can provide that missing piece of the puzzle. Sigma-based interpretation techniques have been tried but the shallow depth of investigation places the measurement in the highly invaded zone. This method of interpretation in cased holes is also hindered by lithology variations that are typical in the Permian Basin.

Abstract Incomplete or sparse information on types of data such as geologic or formation characteristics introduces a high level of risk for oil exploration and development projects. "Expert" systems developed and used in several disciplines and industries, including medical diagnostics, have demonstrated beneficial results. A state-of-the-art exploration "expert" tool, relying on a computerized data base and computer maps generated by neural networks, is proposed for development through the use of "fuzzy" logic, a relatively new mathematical treatment of imprecise or non-explicit parameters and values. Oil prospecting risk can be reduced with the use of a properly developed and validated "Fuzzy Expert Exploration (FEE) Tool." This tool will be beneficial in many regions of the US, enabling risk reduction in oil and gas prospecting and decreased prospecting and development costs. In the 1998–1999 oil industry environment, many smaller exploration companies lacked the resources of a pool of expert exploration personnel. Downsizing, low oil prices and scarcity of exploration funds have also affected larger companies, and will, with time, affect the end users of oil industry products in the US as reserves are depleted. The proposed expert exploration tool will benefit a diverse group in the US, leading to a more efficient use of scarce funds and lower product prices for consumers. Summary of Progress During this six-month period the majority of data acquisition for this project was completed with the compiling and analyzing of well logs, geophysical data, and production information needed to characterize production potential in the Delaware basin. A majority of this data now resides in several online databases on our servers and is in proper form to be accessed by external programs such as web applications. A new concept was developed and tested in well log analysis using neural networks. Bulk volume oil (BVO) was successfully predicted using wire line logs as inputs, providing another tool for estimating both the potential success of a well, and the interval to perforate. Regional attributes have been gridded to a 40-ac bin (gridblock) size and our fuzzy ranking procedures have been applied to determine which attributes are best able to predict production trends in the basin, using the average value of the first 12 months of oil production as the value to be predicted. A study to determine the ability of an artificial intelligence system to predict depth using seismic attributes in a Delaware field was completed and the results published. 1 Significant improvements over standard techniques were found particularly when test wells were on the dataset boundary where extrapolation is required. An initial step in programming the expert system was undertaken, and a decision tree program was coded in Java Expert System Shell (JESS) that allows development and tabulation of rules and relationships between rules that can be used by our expert system. This important program allows lists of rules to be entered and easily tested and verified. The design of the expert system itself was clarified and an expanded system was created where several distinct factors such as geologic/geophysical data, trap assessment, and formation assessment will be operated on in parallel to increase efficiency of the overall system. Coding of the Java interface, which users will utilize to access data in the online databases and run the expert system, has begun. Development of the interface will be an important ongoing project over the next year and will eventually tie together the data and the expert system programs coded in JESS while allowing user customization and informative reports of results to be returned.

Abstract Traditionally, operators have had limited options for conducting remedial work on lateral re-entries through milled-casing windows. This limitation is due to the necessity of using a "bent joint" of pipe to guide tools through the window. If a bent joint of pipe cannot be attached to the end of the assembly (e.g. a drilling assembly), a whipstock is required to deflect the assembly out the window. Setting a conventional whipstock requires the use of orienting tools that add significantly to the wellcost. This paper describes the world's first applications of unique technology that helps solve these problems by facilitating the exiting of milled-casing windows with service tool assemblies during remedial operations. The system uses the patent-pending "self-locating" lateral re-entry technology as an integral component of the Lateral Re-entry Whipstock to assure the proper orientation and elevation of the whipstock tool face with the casing exit window. The technology described in this paper has bearing on TAML Level II 1 junction re-entry operations for clean out, production enhancement, increased reservoir drainage, zonal isolation, and re-completion of lateral wellbores in multilateral completions. Introduction The Permian Basin is an area where re-entry style horizontal drilling from existing wellbores has been used extensively. Drilling horizontal laterals from existing wells is more economical than drilling new wells because the costs of drilling and running casing down to the producing formation is eliminated. Due to reservoir pressure depletion, many re-entry horizontals require the use of artificial lift. In order to maximize drawdown in a pressure-depleted reservoir, the downhole pump should be set below the lateral's window. Consequently, the whipstock used to mill the casing window and drill the horizontal lateral wellbore must be pulled before installing the pump. The Challenge. Any remedial work to be conducted inside these re-entry horizontals can be a challenge because the drilling whipstock is not in the well to guide the workover string out through the casing window. Therefore, other means of guiding the string out the window must be devised. The most commonly used method locates the window with a "bent sub" on the end of a workstring. While this is often sufficient, the "bent sub" limits the assemblies that can be passed through the window. Some assemblies (e.g. drilling) are too stiff or large to be deflected over to and out a casing window even with the aid of a bent sub. The operator of the North Indian Basin Unit wanted to sidetrack an open-hole horizontal lateral in order to reach an untapped area in the reservoir. This objective meant that they were faced with the challenge of passing a 4–3/4-in. directional drilling assembly through a 7-inch casing window.

Abstract A tremendous effort has been made by the oil industry and others over thepast seventy years to develop an understanding of multiphase fluid flow throughporous media. A vast literature of concepts, field and laboratory data, experimental techniques and mathematical expressions has beendeveloped. Many parameters believed to be pertinent have beeninvestigated, such as connate water saturation, relative permeabilitysaturation relations, sample wettability, and waterflood scaling (including theeffect of such variables as pore size, flow rate, viscosities and interfacialtension of the fluids, sample size, and the effect of a third phase such asfree gas). Other works investigated are the development of theBuckley-Leverett concept of fluid displacement, the laboratory determination ofrelative permeability, and the development of waterflood scaling theory aimeddirectly toward calculating reservoir performance from laboratory data. This paper reviews waterflood management practices in West Texas and providesways of implementing successful waterflood project. Introduction Theoretical and Laboratory Observations of Detriments to Waterflooding A tremendous effort has been made by the oil industry and others over thepast seventy years to develop an understanding Displacement Process. Relative perm effects and factorseffecting rel perm; interfacial tension between water and oil, Mobilityratio. Reservoir History. Initial water saturation, initial gassaturation. Viscous Fingers. Gravity Segregation. Water Compatibility. Different Water. Reaction between injected water and reservoirwater. Reaction between injected water from different sources. Different Formations. Reaction of water with some formationslike shaly sands (clay swelling) and carbonates (modest dissolution, finesmigration) Geology. High perm zones, dip of reservoir West Texas Waterfloods The dominant solution to improving oil recovery in West Texas waterfloodshas been through infill drilling. Other solutions include: cyclicwater injection, horizontal producer, horizontal injectors, automation ofproducing/injecting wells, reservoir management/surveillance, fracturestimulation of producers and injectors, and pattern realignment. Several West Texas waterfloods are prevalent in the literature: Means, Robertson, Seminole, Slaughter, Spraberry, and Wasson. Formations foundin the literature included: Clearfork, Glorieta, Grayburg, Queen, SanAndres, and Spraberry.

Abstract Barnhart Field was discovered in 1941 on the Ozona Uplift, southeastern Reagan County, Texas. The field produces from the Ellenburger Group on approximately 10,000 acres that can be divided into a southern part on University Lands and a northern part on private land. Two pilot waterfloods were attempted; neither was successful. The field was essentially abandoned in 1976 after producing more that 16 million BO. The structure of the field is an asymmetrical anticline trending northeast - southwest with the crest on the northern part of the field. Structure alone does not appear to control production because the southern part produced slightly more oil than the northern part. Insoluble residue analyses and lateral-log correlations indicate the Ellenburger in the northern part of the field was more deeply eroded than in the southern part. The Ellenburger Group, in this field, can be divided into three pay zones, the Upper Honeycut, the Lower Honeycut and the Gorman. The Upper Honeycut produces only in the southern part of the field and may have the best developed porosity in coarse crystalline dolomite. An isopach of the Honeycut pay zones shows fair agreement between thickness and production. The Gorman pay zone does not correlate well indicating that production cannot be explained by gross isopachs alone. Introduction The town of Barnhart was established in 1910 along the Kansas City, Mexico and Orient Railroad. The land agent for the railroad at the time was William F. Barnhart and the town was named in his honor 4 . On September 9, 1941, the Amerada Petroleum Corp., University RA #1 made an Ellenburger discovery. Located in southeast Reagan County, Texas, on the Ozona uplift of the Permian Basin about seven miles east of the town of Big Lake, Amerada initially wanted to name the field Big Lake, but a field already existed by that name. Eight miles to the east was the town of Barnhart and Amerada choose that name. Field History By early 1953, eighty-three producers and five dry holes (Figure 1) had been drilled to complete the initial development of the approximately 10,000-acre field. Field spacing was 160 acres but was later reduced to 80 acres in many parts of the field, most noticeably on University Lands. Approximately half the productive acreage was on University Lands and half on private lands. Although many Ellenburger fields have strong water-drive reservoirs, particularly those located on the Central Basin Platform, the Barnhart Field is solution-gas drive. A production curve from the University Lands portion of the field shows field volumes from 1941 through 1975 (Figure 2). The hyperbolic nature of the curve is one indication of solution-gas drive. Another indication is that water production remained low over the life of the field and the wells did not "water out." Finally, GORs increased as reservoir pressures declined. Although several wells were reclassified from oil to gas in the 1970s, the presence of a gas cap was not established. Two pilot waterfloods were conducted from 1960 through 1971. The first was a one-well dump-flood, in which San Andres water was allowed to gravity inject into the open Ellenburger perforations. Poor records were kept for this flood, but based on water levels in the dump-flood well, it appears to have reached hydrostatic equilibrium early in the flood and did not inject much water into the Ellenburger 1 . The second waterflood was a five-spot in Block 48, Sections 3 and 4, University Lands. Again, insufficient water was injected to achieve fillup. No response was observed from either flood 1 . The field was essentially abandoned in 1976 when most of the wells were plugged for the salvage value of the casing. In the late 1970s, several wells were drilled or recompleted in the field in an attempt to locate bypassed oil. Since none of these wells initially produced much more than 20 BOPD or cumulatively produced much oil, they are considered unsuccessful.

Abstract The PTTC poster session's theme is to illustrate a new method of technology transfer that was developed as a joint venture between the PTTC and World Oil magazine. The Petroleum Digest , a supplement to World Oil , was the vehicle developed for technology transfer of case studies to independent operators. Independents, in particular, rely on field-oriented case studies when they consider applying new technologies. PTTC supplies the case study technology results and World Oil publishes the case studies. For illustration purposes of the newly developed technology transfer method between PTTC and World Oil magazine, the PTTC poster session will display four field case studies presented in the Petroleum Technology Digest, a supplement to World Oil Magazine. The Petroleum Technology Digest was first published in 1999, and it was distributed as a supplement to World Oil . Case studies are now being published directly in World Oil and distributed to more than 30,000 readers. PTTC is making periodic reprints available. There have been four publications to date. Case studies are authored by producers or, if a technology supplier is involved, both the producer and technology provider are co-authors. This enhances credibility of the published field performance. Unlike typical professional society papers, the case studies contain sufficient economic data to enable producers to make their own decision regarding the technology's applicability to their situation. These four case studies reflect technology used and/ or developed in the Permian Basin (Texas and New Mexico), and in the Four Corners area of New Mexico. The four case studies with an individual poster for each are: Reliable, low cost vapor recover system saves money while helping the environment. Co-authored by Troy Palmer, Devon Energy Corp, Bill Webb of Bill Webb Inc, and Dale Redman, Hy-bon Engineering Co., Inc. Reported in the September 2000 issue of the Petroleum Technology Digest Bottom Line : Since 1994, Devon Energy Corp. has employed the Vapor Jet system to capture hydrocarbon vapors from oil and water storage tanks in a West Texas waterflood operation. The system has proven to be a reliable, flexible, cost effective alternative for capturing hydrocarbon vapors to increase gas sales, while reducing hydrocarbon emissions.

Abstract The use of methanol in fracturing is not new technology. Its origin and application in hydraulic fracturing can be traced back to the 1960's. However, advances in fracturing fluid chemistry and breaker technology have improved dramatically creating new systems such as crosslinked methanol, the subject of this paper. Methanol has been utilized in the well stimulation industry for many years to take advantage of its low surface tension properties and miscibility with various formation fluids. This paper will discuss advances in crosslinked methanol system technology, system compatabilities, field application and practical safety precautions. The fluid system rheological properties and proper breaker application will be discussed as well. In recent years, the industry has become more aware of the challenges associated with formations recognized as "water sensitive". These issues can be associated with mobile and swelling clays, or undersaturation of the formation, otherwise known as aqueous phase trapping. The paper will discuss these issues as they pertain to proper fluid selection and more specifically, the selection of crosslinked methanol as a fracturing fluid. Formation properties of zones treated with crosslinked methanol will be presented as well as post fracture treatment results. Introduction Crosslinked anhydrous methanol is an excellent fracture fluid system comprised of approximately 96%-100% pure methanol developed to stimulate low permeability water sensitive formations. In the late 1960's, fracturing fluid systems incorporating carbon dioxide (CO 2 ) and methanol saw wide usage and some success in fracturing applications. These systems were used in an attempt to place proppant into a hydraulically induced fracture without the potential damage associated with water on "tight" formations displaying water sensitive tendencies. In the early 1970's, certain patents were awarded for a methanol fluid system termed "Vapor Frac," which consisted of transporting propping agents in gelled alcohol and CO 2 1 . This system was used for several years with varying degrees of success due to limited sand transport capabilities and poor fluid leak-off properties. In 1980, the first crosslinked methanol system was introduced to the industry. However, at this time the system incorporated 80% pure methanol and 20% water. While this system was compatible with CO 2 , it did not fully address the water sensitivity issue. By the late 1980's the first pure (96% methanol plus) methanol fluid system was developed and introduced to the industry, and saw wide use throughout Western Canada. In late 1992, additional opportunities to apply this technology presented themselves and research was undertaken to apply new fluid technology to crosslinked methanol. The system was introduced in Argentina; originally, to reduce treatment cost relative to CO 2 foam systems prevalent at that time. Since then, more than 200 jobs have been pumped 2 . The accumulated experience gained in Argentina further enhanced and expanded the original intended applications. In late 1998, depressed crude oil prices and a subsequent decline in drilling operations in the Permian Basin caused pumping service companies to seek applications for this improved crosslinked methanol fluid system in existing producing wells. The hope was to create a stimulation market in gas wells perceived as water sensitive, depleted or damaged to a point that conventional stimulation was not believed to be an option. It is in this application that crosslinked methanol has seen its greatest success in the Permian Basin.

Abstract Aimed for the need of oil displacement in high salinity formations where the normal nonionic and anionic surfactants are inefficient because of salting out or cloud point phenomena [1] , A novel structure surfactant(LF) with nonionic and anionic hydrophilic group is put forward and synthesized. The said surfactant is soluble in 30% NaCl brine, and shows good surface activity in brine with 100,000mg/L salinity concluding 5,000mg/L CaCl 2 . By analysizing the volume fraction-salt concentration phase graph, the salt tolerance property of LF, petroleum sulfonate and their combined system is comparatively studied, LF is excellent, the proportional increment of LF in combined system will improves salt tolerance property of the combined system. In any different brine, water/n-decane Interfacial tension is high if only LF or petroleum sulfonate is used, but Interfacial tension will reach super low if the combined system is appropriately used as long as water salinity is enough high(higher than 20,000mg/L). By adjusting the proportion of LF and petroleum sulfonate in combined system, water/oil Interfacial tension can always reach super low regardless of water salinity, so the system can be particularly used as oil displacement agent in high salinity formations. The paper presents three oil displacement and one chemical tuff and puff formulations consisted of LF and KPS, which were suitable for high salinity formations in Zhongyuan oil field. The temperatures of four test zone are 86.9°C, 65.0°C, 82.5°C and 82.5°C, the salinities are 88,540 mg/L, 55,028 mg/L, 14,9127mg/L and 195,000 mg/L, the room recovery improvement all exceed 19%. Now the four field tests get along favorably, verifying good result and indicating bright application prospect. Introduction Surfactants are widely used in oil field, and the interest in the use of nonionic and anionic surfactants has increased, For example, polyoxyethylenated alkyl alcohol and petroleum sulfonate(PS), but they cannot be used in high temperature and high salinity formations. Nonionic surfactants and anionic surfactants will salt out because of cloud point phenomena and high salinity respectively. Therefore, a novel structure surfactant (LF) with nonionic and anionic hydrophilic group is put forward, it will not only maintain the advantages of nonionic and anionic surfactant, but also overcome the inefficiency [1–4] . In the work, ether caxhoxylated surfactant, as a nonionic and anionic ampholytic surfactant, was industrially acquired, it revealed that the nonionic group is oxyethylene and the anionic group is carboxyl. The structural formula is as follows: C 9 H 19 -C 6 H 4 -O- (CH 2 CH 2 O) 8 -CH 2 COONa C 6 H 4 refer to arykyl. Experimental Method Surface tension is measured by vertical plate method. Interfacial tension is measured by the Texas-500 spinning drop interfacial tensiometer, and the value of water/oil interfacial tension is determined with 0.2% concentration of surfactant.

Abstract San Andres carbonate reservoirs have long been known to have a high degree of reservoir heterogeneity and poor recovery efficiencies. Fractures are one of several causes of this heterogeneity. The heterogeneity causes unpredictability in water and CO 2 flooding. However, the correct placement of horizontal wells can take advantage of this problem. An integrated reservoir characterization study of the Mabee field incorporating oriented core, Formation Microscanner (FMS) wireline logs, seismic time slices, production character, curvature analysis, and interference testing was used to predict fracture orientation and areas of highest fracture density. These fracture characteristics were then applied to determine horizontal well loca-tion and orientation. Fracture orientation was evaluated through the analysis of oriented core, FMS logs, and interference testing, indicating a fracture orientation of N70W. Analysis of the induced fractures in the oriented core indicates that the direction of maxi-mum horizontal compressive stress is N45E. High fracture density was delineated by curvature analysis, relative seismic amplitude, and areas of higher production. Areas with high curvature corre-spond to areas of high relative seismic amplitude and higher production. The data integration indicates that four areas have high fracture density. The synthesis of fracture orientation and density, along with the production character, indicates the optimal location and orientation of horizontal wells. Introduction Low-permeability San Andres reservoirs of the Central Basin Platform contain significant volumes of remaining oil. The Mabee San Andres field lies on the northeastern edge of the Central Basin Platform (Fig. 1) and is part of the San Andres/Grayburg Platform Carbonate play. 1 Ref. 1 reported recovery efficiencies for secondary recovery of approximately 30% and an unrecovered resource of 2.6 billion stock-tank barrels of oil. The low recovery efficiency and still-remaining resource are due largely to the signif-icant amount of heterogeneity found in these reservoirs. San Andres Platform Carbonate reservoirs are highly hetero-geneous because of the depositional facies, diagenesis, and frac-turing. Ref. 2 described how grainstone bar depositional facies significantly affected the production character in Dune (Grayburg) reservoirs. Ref. 3 described how areas of postdepositional dia-genesis were the most highly productive in the Jordan (San Andres) reservoir. Additionally, fractures have been cited as contributing significant heterogeneity to San Andres/Grayburg reservoirs. Ref. 4 sited fractures in the Arrowhead (Grayburg) reservoir as the reason that tracers broke through in 2 days between a five-spot well pat-tern. Ref. 5 described the influence of fractures in the Keystone East (San Andres) reservoir. Ref. 6 described how fractures in the Chaveroo and Cato (San Andres) reservoirs influenced flow and storage volume. Ref. 7 depicted natural fractures as dominating the permeability character in zones of the Levelland (San Andres) reservoir. This heterogeneity causes preferential fluid flow and often-early breakthrough in waterfloods. It is also the likely cause of water loss previously unaccounted for in San Andres waterflood operations. Ref. 5 described a northeast preferential flow direction coincident with their interpreted direction of maximum horizontal compressive stress. Ref. 8 cited the Fullerton Clear Fork, Keystone Colby, and Means (San Andres/Grayburg) reservoirs as having east-west preferential flow directions. It is reasonable that this similar preferential flow direction in several fields and several formations is due to open fractures. Both the direction of open fractures and the location of densely spaced fractures influence how fractures affect production. In this study we combine geologic and engineering information including interference tests, oriented core, Formation Microscanner (FMS) logs, production data and curvature analysis to evaluate the direc-tion of open fractures and the areas where they may be more densely spaced.

Abstract Much recent attention has been recently given to depletion of U.S. natural gas reserves, particularly since many forecasts predict a 30 TCF annual gas market. A comprehensive look at the way initial production, decline rates, and reserves have changed over the last 30 years in Texas, the source of 1/3 of the country's natural gas, leads to concern about whether current drilling activity will be able to maintain the current supply, much less increase gas production 1 . The decline rates in new Texas gas wells have changed from about 20% in the first year for wells drilled in the 1970's and 1980's, to more than 55% for wells drilled in 1998 and 1999. At the same time, the contribution to the state's supply from new wells has sharply increased from 8% of the state's supply to more than 15%. Although the initial production rates from an average well have actually improved from a low of 15 MMCF per month in the early 1980's, to 44 MMCF per month in 1999 due to improved completion technology and horizontal drilling, the combined effects of fewer completions and high decline rates suggests that a decrease in Texa's production capacity may occur in the near future. Drilling above the current activity will be necessary to sustain the state's gas production. Normalized rate vs. time curves were developed for each year since 1970 to obtain initial rates and decline profiles. The curves were extrapolated to an estimated ultimate recovery, changing from 6 BCF per well in the early 1970's to 1 BCF per well in the late 1990's. Introduction Texas has been the source of 39% of the approximately 882 TCF marketed in the U.S. since 1945. The state currently supplies about 32% of the country's natural gas and holds 27% of the proved reserves 2 . By any measure its contribution to the U.S. supply is significant. Natural gas reserve-to-production ratios have been fairly constant in recent years for both the U.S. and Texas, and stand at 8.7 years and 7.4 years, respectively, for the year ending in 1999.

Abstract Production companies purchase natural gas compressor packages designed for specific operating conditions. When those conditions change, the operator may be uncertain about utilizing the compressor package on the same application or moving it to another location. By following a concise procedure, an operator can determine the fitness of equipment for a new assignment. He must take into account the performance parameters of the engine, the compressor frame and cylinders, and the heat exchanger. With full information on gas analysis, brake horsepower of the engine, compressor frame and cylinder sizes, and pressure pulsation control, the operator can make the most efficient use of equipment. Introduction Idle equipment is an operator's - and an accountant's - nightmare. A used compressor package whose original mission in life has been accomplished can get a second chance to perform if the operator can determine its full rae of capabilities. Evaluating the machine requires a knowledge of compressor sizing. With that knowledge, the operator can turn a nightmare into a pleasant and productive reality. Know your components Engine. It's important to consider real usable horsepower. You don't want an engine that can't handle the load, nor do you want to pay for more horsepower than you need. Many engines require de-rating for accurate appraisal of performance. Check fuel consumption ratings and exhaust emission levels. Ambient Temperature and Elevation. Since the established rating for a given engine is defined for a given ambient pressure and temperature, the engine's ability to pull rated load can be affected as altitude and temperature increase. Naturally aspirated engines are affected more by changes in these conditions than are turbocharged engines. The turbocharger compensates for low ambient pressures and the aftercooler's ability to maintain a constant air inlet temperature. To compensate for altitude and ambient temperature, find the altitude deration curve in the performance handbook for the engine in question. Next, determine the altitude and the maximum ambient temperature to the engine that can reasonably be expected. Use the information from the altitude deration chart to learn the engine's rating. 1 Fuel Gas Analysis. Many gases, including natural gas, digester gas, propane, etc., can be effectively used in gas engines. Different gas compositions require different compression ratios and ignition timings, or may require that the engine be derated. Some fuels may not be usable at all.

Abstract Rienecke field is one of a series of fields in the Horseshoe Atoll of the Midland Basin. This carbonate reservoir has fairly good lateral and vertical continuity and is confined in a dome-like structure. A gravity-stable crestal carbon-dioxide flood was begun in 1997 by injection into five wells at the high point of the structure. Pulsed-neutron logs run through casing provide a method to monitor reservoir dynamics and locate oil production targets. The first step in developing a cased-reservoir analysis model is to estimate the carbon dioxide content. This is done by correlation of the cased-hole neutron and density porosities from the pulsed-neutron system. In developing a three-phase saturation model (oil, water, carbon dioxide)the effects of the carbon dioxide on the oil and water saturation measurements must be determined.Computer simulations of tool response are utilized in conjunction with field data to develop the model and the uncertainties in the saturations. An example log and analysis demonstrate the capabilities of the reservoir analysis model. The analysis results are compared to production and historical data for the field. Introduction The Reinecke field is one of a series of fields along the Horseshoe Atoll of the Midland basin. The structure of the hydrocarbon entrapment is a dome shape created by phylloidal algal build-up 1 .Originally discovered in the 1950's, the field has produced over 82 million barrels of oil. Given the dome structure and the good permeability, the remaining oil is being produced by injecting carbon dioxide into the crest of the dome.Cased-hole logging is one of the available analysis tools to monitor the flood progress and select oil production targets 2 .During the initial production and water drive production, many of the wells were cased and completed after drilling only a few feet into the reef. Now with the crestal CO 2 flood, the wells are drilled or deepened into the reef structure so the oil below the gas cap is produced.Along with providing petrophysical analysis, pulsed-neutron logging can also provide geological correlation across the structure. Figure 1 shows the cased-hole neutron and density porosities set into a geological cross-section. Specific-purpose response models for the pulsed-neutron measurements are developed for monitoring the oil and CO 2 content. Along with determining the gas cap location, the effects of the moved oil are considered. The miscible oil is generally considered to be a mixture, approximately 80% oil and 20% carbon dioxide 3 .The response of the pulsed-neutron measurements for the oil-rich liquid phase and the CO 2 rich gas phase are described in the sections that follow. Quantifying the Carbon Dioxide Content The response of the neutron porosity can be used to quantify the amount of CO 2 in a reservoir section. As the CO 2 displaces water or oil, the drop in the hydrogen content is reflected in the neutron porosity. To quantify this effect a series of points were generated using the computer code POROSITY 4 .This code calculates the apparent neutron porosity for a given mixture of rock and fluid. Figure 2 is a graph of the pulsed neutron ratio for porosity and CO 2 content. The splines in the graph represent porosity values. The expected ratio response for various amounts of CO 2 and porosity can be read from the graph. To apply this linear relationship in time-lapse monitoring, the current neutron porosity is compared to the original fluid-filled base run of pulsed neutron or compensated neutron porosity. When no base logs exist, the cased-hole, density-neutron crossplot porosity can be used to estimate the original fluid filled porosity.

Abstract In the United States both state and federal government have provided incentives in recent years to maintain production, increase production, and discover new production. On the state level, the incentives involve mostly abatement or rebate of severance taxes. Oklahoma and Louisiana (and possibly other states) have had severance tax relief statutes in recent years that are producer helpful in maintaining production in times of low oil prices. All of the incentives are noted but the two discussed most require no investment by the operator. This paper gives a brief history of the statutes which might be considered relatively generous. In the case of Louisiana, the major statute could be considered farsighted in nature. Oklahoma's incentives history shows a rapid willingness to adjust to help maintain production. The paper also comments on the applicability of use of the statutes. Introduction History shows (as can be noted from Fig. 1) that oil prices above $20/bbl have not been sustainable since the oil price crash of 1986. Reference 1 notes that major producing states with a large number of stripper wells including Oklahoma, Texas and New Mexico showed large percentage declines in 1998 due in part to low oil price and stripper wells (wells producing 10 BOPD or less) with lifting costs approximating $15/barrel. Table 1 (taken from Reference 2) shows stripper well data including well count, production, and reserves for Louisiana, Oklahoma, New Mexico and Texas. Based on post 1985 oil price history, it is not surprising that states have provided incentives to maintan production. This study does not attempt a thorough review of incentives provided by all states. As will be discussed herein, Louisiana and Oklahoma have provided useful incentives which have undoubtedly helped in maintaining production. In some respects, their major incentive tied to oil price could be considered somewhat more generous than anything provided by other states. The incentive appears to relate to the State's type production in some respects. They also become effective at a relatively high oil price. Although the current prices do not permit use of the incentives, it is worthy of note that a recent survey of Houston banks predicts oil prices in the 18 $/bbl range from 2000 through 2002 (Reference 3). Based on the premise that the oil incentives are comparatively generous, it is interesting that on a per barrel basis the State's overall take from oil including all taxes is relatively low. That fact can be noted from Fig. 2 which is taken from Reference 4. A non detailed review of the States's production incentives follows. Oklahoma A look at oil price history (Table 2) and production history (Table 3 and Fig. 3) gives some indication as to not only why the incentives exist but why they have been improved since being put into law in 1994. Based on 1996 producing well count (Reference 2), average per well production for that year was approximately three BOPD. Depletion state of the fields is also reflected by an average annual GOR of 3184 which can be derived from Fig. 3. Production on Fig. 3 is a composite of 21,484 producing properties which reflects a wide diversity of ownership and little room for economics of scale. Low revenue coupled with moderate to high operating costs leaves little room for profit. Thus, any reduction in the seven percent gross production tax would help significantly.

Abstract Acidizing is often applied in horizontal wells to improve well performance. Acidizing in horizontal wells differs significantly from the acidizing of vertical wells. The length of acid contact is much longer, the formation properties over the contact length likely vary in a larger range, and the cost is generally higher. To enhance the effectiveness of matrix stimulation, methods to evaluate and optimize acid treatments similar to those used for vertical wells can be adopted for horizontal wells. This paper introduces a simple approach to evaluate horizontal well response to acid treatments. Skin factor was calculated explicitly in the method from pressure and flow rate, which can be directly measured during a treatment. Skin factor is then used to identify the well response to acid injection, and therefore to understand and control the stimulation process. There have been several mathematical models published to simulate the pressure/flow rate behavior of horizontal wells. Most of them have complicated solutions and have to be solved numerically. We selected and modified analytical solutions for horizontal well performance that can be implemented for field evaluation of acid treatments. Field examples presented in the paper show how to apply the evaluation method for horizontal wells. The method can assess the effectiveness of acid treatments and can be used to optimize subsequent treatments. Introduction Acidizing in horizontal wells is significantly different than in vertical well. In a horizontal well, formation contact area is much longer, and acid distribution inside the wellbore is a greater issue 1 . The acid injection rate per length of formation treated is also generally much lower for horizontal wells than for vertical wells. This reduced injection rate can reduce the efficiency of the acidizing process, particularly in carbonate reservoirs, where the creation of wormholes is desired 2 . Simulating the acidizing process in horizontal wells involves more uncertainty, which directly affects the reliability of acidizing treatment design. In addition, acid treatment costs for horizontal wells are generally higher than for vertical wells because of higher injection volumes, the common use of coiled tubing, and more complicated injection procedures. For these reasons, it is important, but also very hard, to understand what has happened in horizontal well acidizing, and to identify the reasons resulting in success or failure. To enhance the effectiveness of acidizing treatments in horizontal wells, we introduce a skin analysis method similar to that used in vertical well acidizing. The method can be applied to matrix acidizing either during or after the treatment, to identify the well response to the acidizing treatment 3,4 . The method is based on transient flow theory for pressure behavior in horizontal wells. It calculates skin factor from pressure, flow rate, and other information about the well. In order to use the method during an acid treatment in real time, the model has to be simple and analytically solvable. This is a key criterion when selecting the mathematical models for acidizing evaluation.

Abstract At Dagger Draw it is difficult to arrive at reliable estimates of total pore volume in the vuggy dolomitic reservoir. Correlating wire-line logs to core porosity using a multi-layer perceptron neural network (MLP) generated a "ground truth" porosity estimator for the reservoir. Well logs in the field include CAL, DRHO, GR, LLD, LLS, MSFL, NPHI, PEF, RHOB, and values of DPHI, PHI-L (liquid phase porosity) and PHI-G (gas phase porosity) were calculated. Log values were aligned with the center point of laboratory analyzed core samples in five cored wells with a total of 21 cored sections. Neural network solutions generated using four of the five wells to blindly predict the fifth well validated results. Each well was excluded in this fashion, for a total of five tests. The resulting correlation tool, if applied at hundreds of wells within the field without core data, would provide the basis for geostatistically derived pore volume maps. Fuzzy ranking was used to evaluate the usefulness of individual logs for correlating with core porosity, and also indicated that the problem was complex, and guided architecture design for the MLP. The seven best logs were used as inputs for the MLP, and results show that the MLP can describe the complex relationships between the wire-line data and core porosity. Regression relationship were able to predict the excluded wells at up to CC=0.80. These results are a great improvement on the linear equations previously used for estimating porosity at the Dagger Draw and better predictions are expected, as the process is refined and neural network algorithms are improved. The use of artificial intelligence to generate core porosity data using only wire-line log data can provide data that could only be attained previously using expensive cores. Introduction The vuggy nature of the Upper Pennsylvanian Canyon formation at Dagger Draw contributes greatly to its success as a reservoir rock. However, early calculations of mass-balance relationships predicted that the reservoir had already produced more oil than the estimated original oil in place for the reservoir. The primary difficulty seems to be that porosity logs underestimate the porosity contributed by the vugs themselves. A number of FMI logs were recorded in the field and initially it was desired to predict the FMI response using common wire-line logs. The FMI logs were able to show the distribution of vuggy porosity, but the selection of threshold values 1 for vug identification (grayscale value of what was considered a vug) differed between wells, and would have led to scale problems in predicting at wells without FMI data. In addition, total porosity, that is matrix plus vuggy porosities, would still have been difficult to calculate, since some of the vuggy porosity was identified on standard porosity logs.Instead, a "ground truth" total porosity was calculated by correlating standard logs to porosity measured from whole cores taken in the field. The final predictive tool would then provide core porosity values at any well in the field that had standard wire-line logs. Since the field is densely populated with wells, standard geostatistical mapping could provide detailed porosity information, both horizontally and vertically, and overlooked pay zones in wells could be identified and exploited.

Abstract This paper presents a method to identify and calculate hydraulically connected gas reserves in compartmented gas reservoirs. The 3-D seismic amplitude analyses and edge detection indicate the possible compartmented sands in the same geological flow units identified in this study. Petrophysical properties of adjacent wells also change abruptly that indicate the deltaic nature of sand deposition in Frio Marine and Frio Non-Marine formations. The "material balance" method to calculate original gas in place (OGIP) and remaining gas reserves utilizes a plot of p/Z values versus cumulative gas production. The assumption is that all wells should drain from the hydraulically connected tank-type gas sand body. The isolation of wells draining from different sand bodies is important to determine the correct OGIP for each sand body. Therefore, measured shut-in reservoir pressures were plotted against time for each geological flow unit. Plotted pressure profiles for each well made it possible to identify wells draining from a common sand body. Wells draining from a single gas pool had a uniform pressure decline. However, the well that produced from a different gas pool had a distinct pressure decline trend. Several wells encountered initial reservoir pressures even though the corresponding formation that was completed in was put on production 20 years ago. This paper provides three examples of integrating 3-D seismic amplitudes, production bubble maps and pressure analyses to differentiate hydraulically connected sand bodies. The material balance calculations provide accurate OGIP and remaining gas reserves. This method identifies significant volumes of remaining gas reserves that lead to reopening of shut in gas wells utilizing minor workovers. Introduction An integrated study was conducted on an onshore gas field. The field has been producing from the Frio Non-Marine, Frio Marine, and Vicksburg formations. The field has a long production history with the number of development wells in excess of 200. Shut-in bottom hole pressures are recorded sporadically in wells. About one hundred pressure transient tests were made on several wells, out of which fifty tests data were analyzable. Several pressure-volume-temperature analyses were conducted on produced gases from the different sands. The 3-D seismic data was taken in the year 1997 to investigate the geologic complexity of the field. The aim of this paper is to demonstrate the degree of reservoir compartmentalization in reservoir sands and techniques used to identify compartments in a matured gas field. Smalley and Hale 1 discussed utilization of a range of conventional and novel data types to identify reservoir compartments in the early stage of the Ross oil field. They demonstrated the integration of oil compositional data (molecular maturity parameters, gas chromatography fingerprinting, pressure-volume-temperature (PVT) data), pressure, well test, and fault seal analyses. Depositional Environments The maximum well depth drilled in this field is 4500 meters. The depositional history begins at close of Jackson time (Eocene age, not recorded in any of the wells studied). The early Oligocene begins with Vicksburg sediments being deposited as a basin-filling wedge prograding to the East into the Gulf of Mexico. The Vicksburg facies are distal delta muds, encasing higher-energy discontinuous sand deposits resulting from storms or winnowing on-structure. The large growth fault, that divides the field in half, is actively subsiding at this time. The Vicksburg deposits upthrown to the growth fault are older, essentially a by-pass surface during the downthrown block accumulation. Water resistivities in these sediments are anomalously fresh, making porosity and pay determination from SP-Resistivity log suites (particularly older vintage logs) a challenge. The Early Oligocene sediments produced less than 10 percent of the total known production from the fields investigated in this study.

Abstract In highly fractured reservoirs, where gravity dominated recovery processes are employed, fluid contact measurements and isobaric mapping are useful tools for understanding operational and process changes. Monitoring fluid contacts accurately in highly fractured reservoirs has always posed a challenge due to limitations in the measurement tools. Gradio-manometer surveys and electronic fluid property surveys lack the depth resolution needed to locate contacts, and direct measurement methods are time consuming, messy and yield no secondary information for quality control. Fluid gradient measurement is the desired method; but historically, limitations in gauge precision or thermal response have made this method unattractive. An electronic pressure gauge using a silicon crystal sensor was shown to provide predictable response to strain under changing temperature and to provide the precision and accuracy needed for repeatable contact measurements and reliable pressure mapping. The pure silicon crystal has a small mass, a thin unbonded structure, and a temperature sensor for compensation placed in close proximity thereby decreasing the stabilization time required for true pressure recording.Rapid pressure measurement allows shorter, more frequent gradient stops; and consequently better data resolution for contact calculations. Replacing non-pressure based contact measurement techniques in a field where bottom hole pressure surveys were taken on staggered intervals saved real dollars. This was done by adding one to two days onto a pressure survey and eliminating the separate contact survey. Measuring both contacts and pressures concurrently reduced time-normalization problems and increased data confidence. Accurate, repeatable pressure measurements clarified details of operational changes on the reservoir management process, improved the data collection process, and reduced expenses to the operator. Introduction In highly fractured, gravity drainage reservoirs, much depends on the oil column movement throughout the reservoir. 1,2 In the past, several methods have been used to gather this information with varied success: fluid conductivity logs, gradiometer logs, fluid gradient analysis, and direct measurement "dipstick" methods. Conductivity logs located the water oil contact (WOC) by measuring the difference in electrical conductivity between water and oil; while marginally successful, they did not give suitable measurements of the Gas Oil Contact (GOC). Gradiometers were also tried but proved expensive to run and gave inaccurate results when run at reasonable speeds. First attempts at fluid gradient analysis were not accurate enough due to gauge precision limitations. Of the methods tried, the most consistent and simple was the bar or "dipstick" method. Quite simply, an angle iron was covered in talcum power and run in the well on slick line to an assumed GOC depth. The depth of the contact is calculated as depth run minus the talc free portion of the dipstick. A second run is made to find the WOC after painting the angle iron with a paste that changes color when it contacts water. Due to its direct measurement method and low cost, the dipstick method became the standard for years. Replacing the Dip Stick The dipstick method had three problems. It provided only contact information, therefore, a separate pressure survey was required to monitor bottom hole pressure across the field. The two surveys had to be time normalized in order to compare data. Dipstick operations are messy and require several entries into the wellbore (if the contacts had moved significantly, many entries were required). Fluid Gradient Contact Measurement. Monitoring contacts using fluid gradient measurements has been the method of choice due the secondary pressure information it provided and because it could be done with one trip into the wellbore. The procedure requires several stops to be made in the wellbore with at least one in each fluid phase. Fluid Gradient Contact Measurement. Monitoring contacts using fluid gradient measurements has been the method of choice due the secondary pressure information it provided and because it could be done with one trip into the wellbore. The procedure requires several stops to be made in the wellbore with at least one in each fluid phase.

Abstract Tubular restrictions from scale buildup can significantly reduce hydrocarbon production, and buildup must be removed to re-store the production capacity of a well. Although scale buildup is a global problem, the material composition and characteristics of scales can vary drastically, even within the same field, making most tools on location insufficient for scale removal. A custom-ized jet cleaning tool has recently been developed to address the problems associated with tubular cleaning operations. Traditional jet cleaning tools are insufficient for removing scale buildup because they do not reliably control jet dwell time. Jet dwell time is the relationship between the difficulty of tubular cleaning and the time required for scale removal. Jet dwell time increases with an increase in the hardness of the buildup material. Ability to control dwell time is a measure of cleaning efficiency. A new, slow-rotating jet cleaning tool can help optimize jet dwell time for cleaning operations without repetitive cyclic effects on a coiled tubing (CT) workstring. The slow-rotating jet cleaning tool can also be used for cutting tubulars. Previously, tubulars were cut by mechanical, explosive, or chemical methods, and CT was used to deploy positive-displacement motors (PDM's) and pressure-activated firing devices (used for rotating the mechanical cutters and initiating the firing sequence in explosive or chemical cutters, respectively). For many through-tubing applications, traditional cutting methods created significant safety risks and obstacles such as long bottomhole assemblies, increasing service costs. With its capability to control jet dwell time and pump abrasive fluids, the new jet cleaning tool can reduce the safety risks and the costs associated with traditional cutting methods. This paper discusses the design and application of the slow-rotating jet cutting tool, and provides case histories of the tool's use in removing scale and production buildup on tubing walls. The paper also discusses application of the tool for performing through-tubing cuts. Introduction Scale deposits on tubing walls and perforations can stop well production, inhibit the injection of well fluids, and plug downhole production equipment. Such problems are compounded if the buildup is left untreated. Early Use of CT for Cleaning. The choice of a scale-removal treatment is often affected by cost; treatment methods such as acidizing or milling with small-diameter tubing can be expensive. When CT was developed in the 1970's, it provided a low-cost option for scale removal because operations could be performed under live well conditions, reducing downtime. CT provided a washing action for removing buildup materi-als. Acids could be placed through the tubing where they chemically reacted with the scale, allowing waste material to be extracted from the tubing and the flow path of the fluid to be returned to the base pipe. However, removing scale buildup with CT was inefficient. Several factors affected the cleaning efficiency of CT. The fluid-pumping equipment delivered more hydraulic horsepower to the CT than it could withstand. Approximately 80% of the available horsepower was lost to the small string diameters and pressure ratings of the tubing. The tools that were placed on the end of the CT to assist with cleaning caused an additional 15% loss of available power. Consequently, only a small percentage of the hydraulic horsepower from surface-pumping equipment was available for removing buildup. Additionally, the scale's varied characteristics, inconsistent composition, and lack of uniform distribution increased ineffi-ciency because the cleaning energies required for removing the buildup of materials were not clearly understood. Some buildup materials (sludges, paraffins, wax complexes, etc.) are soft and easily removed from the tubing wall. Harder buildup materials (water scales, calcium sulfate, calcium carbonate, etc.) and mate-rials such as barium sulfate or strontium require more energy for removal. Early Use of CT for Cleaning. The choice of a scale-removal treatment is often affected by cost; treatment methods such as acidizing or milling with small-diameter tubing can be expensive. When CT was developed in the 1970's, it provided a low-cost option for scale removal because operations could be performed under live well conditions, reducing downtime. CT provided a washing action for removing buildup materi-als. Acids could be placed through the tubing where they chemically reacted with the scale, allowing waste material to be extracted from the tubing and the flow path of the fluid to be returned to the base pipe. However, removing scale buildup with CT was inefficient. Several factors affected the cleaning efficiency of CT. The fluid-pumping equipment delivered more hydraulic horsepower to the CT than it could withstand. Approximately 80% of the available horsepower was lost to the small string diameters and pressure ratings of the tubing. The tools that were placed on the end of the CT to assist with cleaning caused an additional 15% loss of available power. Consequently, only a small percentage of the hydraulic horsepower from surface-pumping equipment was available for removing buildup. Additionally, the scale's varied characteristics, inconsistent composition, and lack of uniform distribution increased ineffi-ciency because the cleaning energies required for removing the buildup of materials were not clearly understood. Some buildup materials (sludges, paraffins, wax complexes, etc.) are soft and easily removed from the tubing wall. Harder buildup materials (water scales, calcium sulfate, calcium carbonate, etc.) and mate-rials such as barium sulfate or strontium require more energy for removal.

Abstract The work described in this paper has been conducted over several years under both laboratory and field conditions. Several field case histories and supporting laboratory observations are presented to substantiate the conclusions expressed. Asphaltenes are often invoked to describe the nature of organic damage and obstructions found when atypical forms of organic deposits appear. In fact a majority of problems studied by this laboratory have been misidentified as asphaltene when the true problem was due to paraffin wax deposition. Asphaltenes are poorly understood, consequently methods aimed at dealing with deposit mechanisms and chemical prevention present a doubly difficult challenge. Asphaltene deposition mechanisms and the chemical structures responsible are less well characterized than those of emulsion breaking, corrosion protection, and paraffin deposit control. Since most asphaltene deposits are associated with paraffin and there exists many proven methods of paraffin control, in many cases it makes better sense to attack organic deposit problems with paraffin control products than some unproven "asphaltene inhibitor". This paper suggests that adequate methods exist today for the removal and control of paraffin wax damage, and that methods for the control of asphaltenes are still in a relatively embryonic state of development. Until the day comes that asphaltenes are well understood chemically, as are waxes, emulsions, corrosion, and scale, the hope of economically treating them will remain a problem for research. Introduction Asphaltenes are basically defined as comprising an organic fraction of crude oil that is insoluble when that oil is placed in fifty times its volume in pentane. 1 This definition is extremely broad and non-informative, and very little information about the chemical structure of these pentane insoluble fractions is gained by this procedure. In fact if the crude oil is not properly pretreated to remove water and solids, confusion can arise about the true quantity of "asphaltenes" that are actually present. This operational definition of asphaltenes results from historical observations made by oil industry personnel, and was never intended to offer a rigorous description of these substances. One outstanding feature of this method of isolating asphaltenes is its clear tendency to exclude ionic and/or polar species possessing strong intermolecular interactions from solvation by pentane. Hidden within this feature is the fact that higher molecular weight normal paraffins tend to aggregate by inductive charge association through London dispersion forces (Fig.1). Unless the pentane solution is heated to disrupt these forces of aggregation the higher normal paraffins will also be included as part of the precipitated "asphaltenes". Many organic molecules can be classified as ionic and/or polar. Carboxylic acids and their salts are examples of naturally occurring organic molecules that can be and are often found in crude oil (Fig. 2). Additionally, many amines and anionic amine salts are known to be present in crude oils (Fig. 3). Although the concentration of these molecules is usually low in the majority of crude oils produced, they are often associated with problems in its production. "Asphaltenes", as they are operationally defined, can thus be thought of as including these molecules. Further, as mentioned above, normal paraffins can also be included as part of the isolated "asphaltenes" when no heat has been applied to the pentane oil mixture. Although researchers attempting to elucidate structural features of "asphaltenes" have expended considerable efforts, the basic lack of a clear definition of these materials hinders progress. 2 Vague descriptions of "resins and maltenes" are given to describe the components thought to be responsible for the suspension of "asphaltenes" (Fig. 4). Thus, confusion on confusion results and speculation replaces fact when dealing with the ill-defined nature of asphaltenes.

Abstract Seismic models enhanced with well logs help to locate sand concentrations. Many well log curves contain patterns with very high frequencies compared to seismic responses. Quantitative analysis of log patterns can create large numbers of sand vectors for plots that resemble and complement 3D seismic attribute maps. Complex log patterns and improved predictions about changes in log responses over distances have been integrated with broad geophysical coverage. Detailed and extensive reservoir models were created. Introduction Finding and modeling sandstone reservoirs can be difficult on any continent. However, Texas, Eastern New Mexico, and other mountain states extending to the north-northwest have areas with especially difficult to decipher variations in sandstone deposition. Even a single county may have distinctly different fields with geology that includes marine sediments, estuaries, several different types of deltas, and fluvial features. Other complications include major changes in sediment flow directions that occurred within a relatively small amount of geologic time. In addition, depths of burial can limit seismic detection of interbedded reservoirs. Furthermore, general shortages of well logs often mandate that as much useful geologic information as possible should be extracted from each log. Techniques were needed to quantitatively utilize sand patterns on logs to improve sand maps. Theory High-energy pulses associated with water movements often radiate dissipating forces capable of influencing fine-grained sedimentation patterns that often extend for several miles. Consequently, log wavelets in shales may retain signatures relatable to sandstone reservoirs in the area. For many years, faint, almost shaled out sand responses on logs have been observed and used for correlations and indicators of better developed sands at distant locations. Qualitative analysis of log signatures has been done for decades. Shapes on spontaneous potential (SP) curves may be related to bars, braided streams, channels, and other deposits. Quantitative analysis of log patterns has the capability to provide better reservoir geometry predictions. Directional variations in sediment transport equations can be determined from rates of change in log responses between wells. In other words, directions and magnitudes (vectors) can be extracted from common lithology log responses. Large numbers of vector solution points calculated from each well log can be plotted to model sediments within the surrounding area. In contrast, the conventional technique of averaging many log responses into a single sand thickness largely wastes huge amounts of detailed data. Standard sand mapping techniques are not being discouraged. Instead, log derived sediment vector plots can be created to compliment sand maps and reveal geologic details. Variations in seismic trace patterns, extracted pseudo-sonic logs, and depositional models also provide transport information. Generally consistent mathematics can be used to describe specific components of sediment transport mechanisms. Linear equations have been frequently derived for log response changes aligned with the flows of streams and channels. Logarithmic variations are common for sediments altered by long shore currents and some wave conditions. There are many fine statistical geology publications that can provide general geometries when only a few logs are available. However, when possible, one should develop local knowledge based on adequate quantities of actual log measurement changes.