Light Oil Field Research Articles

Characteristics and genesis of light oil in Tabei Area, Tarim Basin, Northwestern China

Light oil is a high-quality crude oil. The formation and chemical composition of light oil is a matter of great concern to petroleum geologists. Yakela Field and Shunbei Field, which are located in Yakela and Shunbei regions, respectively, are the two main light oil fields in the Tabei uplift of the Tarim Basin. In order to identify the causative mechanism of light oils in these two fields, 17 crude oil samples were selected and analyzed by gas chromatography (GC) for saturated hydrocarbons and gas chromatography–mass spectrometry (GCMS) for saturated and aromatic biomarkers. Then, the compounds were measured via the mass spectrometry detector after GC separation. The molecular geochemical characteristics showed that the light oils in the two fields are sourced from similar marine source rocks deposited under weak oxidative and reductive environments. The maturity of crude oil in the Shunbei Field is higher than that in the Yakela Field. Simulation results of hydrocarbon generation history of source rocks in two fields showed that the formation mechanism of the two light oils is different. The light oil in the Yakela Field is directly generated by the source rock in the late oil-generating window. The crude oil in the Shunbei Field is formed by the deep burial and maturation of the crude oil generated in the early stage of the source rock.

Development of rational method of water injection for production of light hydrocarbon fluid deposited in reservoir in the last exploitation phase

The complications in production of liquid hydrocarbons became immovable due to the retrograde phenomenon or degassing process in the last stage phase of exploitation of gascondensate, gascondensate-oil or light oil fields, operated in depletion mode have been researched and the impact of advanced method of water injection considered the most efficient for heterogeneous formation studied as well. For the efficiency increase of water injection process, a new polymer-disperse system injected into the reservoir in small dozes as a bank, therefore selectively closing the zones with high permeability and increasing the cover zone of injected reservoirs is proposed. Based on the polyacrylamide and taken bentonite clay samples from Dash Salahly field of Azerbaijan including the nanoparticles, a new composition of polymer-disperse system has been developed, as well as the efficiency of the system in laboratory investigations studied. To control the effectiveness of the new composition, a physical reservoir model based on similar conditions has been developed and the experiments carried out through a special procedure.

Determination of optimum CO2 water alternating gas (CO2-WAG) ratio in Sumatera Light Oilfield

The CO2 Water Alternating Gas (CO2-WAG) injection method, allows the oil to first expand and become better able to flow because of the CO2, and then the water increases the pressure in the reservoir to flush this newly freed oil to production wells. This study is in Sarolangun District, Jambi Province which is prospect of CO2 injection tertiary recovery project due to its abundant CO2 reserve. The success of CO2-WAG injection can be determined by investigating ratios between CO2 and water. The goal of this study is to determine optimum CO2-WAG injection ratio in Sumatera Light Oilfield. This study is done through a numerical simulation of immiscible CO2-WAG which is conducted under three scenarios of ratio using both CMG WINPROP and GEM simulator. The CO2/water ratios are varied from 1:1, 2:1 and 1:2. The study results show that the CO2/water 1:2 is the best CO2-WAG injection ratio that gives highest additional oil recovery factor of 35.24%. Additional recovery factor given by CO2/water ratio 2:1 and 1:1 is 1.49% and 19.52% respectively. Based on this study, the effect of CO2-WAG ratio to oil productivity is depending of amount of water injected. Lower initial oil viscosity lead to an insignificant effect of CO2. Proper CO2-WAG injection ratio will give an optimum oil recovery. This works will have a great use in the CO2-Enhanced Oil Recovery (EOR) application.

Influence of well management in the development of multiple reservoir sharing production facilities

Well prioritization rules on integrated production models are required for the interaction between reservoirs and restricted production systems, thus predicting the behavior of multiple reservoir sharing facilities. This study verified the impact of well management with an economic evaluation based on the distinct prioritizations by reservoir with different fluids. We described the impact of the well management method in a field development project using a consolidated methodology for production strategy optimization. We used a benchmark case based on two offshore fields, a light oil carbonate and a black-oil sandstone, with gas production constraint in the platform. The independent reservoir models were tested on three different approaches for platform production sharing: (Approach 1) fixed apportionment of platform production and injection, (Approach 2) dynamic flow-based apportionment, and (Approach 3) dynamic flow-based apportionment, including economic differences using weights for each reservoir. Approach 1 provided the intermediate NPV compared with the other approaches. On the other hand, it provided the lowest oil recovery. We observed that the exclusion of several wells in the light oil field led to a good valuation of the project, despite these wells producing a fluid with higher value. Approach 2 provided the lower NPV performance and intermediate oil recovery. We found that the well prioritization based on flow failed to capture the effects related to the different valuation of the fluids produced by the two reservoirs. Approach 3, which handled the type of fluids similarly to Approach 1, provided a greater NPV and oil recovery than the other approaches. The weight for each reservoir applied to well prioritization better captured the gains related to different valuation of the fluids produced by the two reservoirs. Dynamic prioritization with weights performed better results than fixed apportionment to shared platform capacities. We obtained different improvements in the project development optimization due to the anticipation of financial returns and CAPEX changes, due mainly from adequate well apportionment by different management algorithm. Well management algorithms implemented in traditional simulators are not developed to prioritize different reservoir wells separately, especially if there are different economic conditions exemplified here by a different valuation of produced fluids. This valuation should be taken into account in the short term optimization for wells.

Weak Gel Flooding Research and Effect Assessment of Horizontal Injection-Production Well Groups in Light Level of Oilfields

Weak gel flooding has been tested and achieved good results in Bohai heavy oilfields. Based on the mechanism analysis and numerical simulation study, weak gel flooding technology is believed to be effect of increasing oil and decreasing water in light oilfields. BZ S oilfield is a low-viscosity oilfield based on horizontal wells development. Due to different production online time and production rate of the well groups of injection and production horizontal wells, it caused advantageous channels formed between injection and production wells in some groups, which reduce storage rate of injection water and affect the development effect. In order to suppress the injected water onrush along the high permeability layer and improve water-oil mobility ratio and sweep efficiency, we have selected two groups for the weak gel flooding test. After flooding test, we evaluate and analyze the recovery and injection characteristics. It shows the test did not achieve the expected result. Therefore, we sum up reasons for the defeat. First, for horizontal injection wells, weak gel plugged well section of relatively pool physical property around water injection wells, increase of wellhead pressure for injection wells make it difficult to meet the requirements of injection allocation. Second, weak gel is hard to work for the pattern of spacing greater than 400m. For these two reasons, weak gel is not displaced and injected to the deep reservoir, and superior channel is still existed, not present precipitation increased the effect of oil wells. Through the evaluation and failure analysis of this displacement test, we proposed technical requirements for weak gel flooding on the horizontal group of injection and production wells. It provided practical experience and references for the other oilfields EOR tertiary oil recovery programs.

The Effect of Surfactant Characteristics on IFT to Improve Oil Recovery in Tempino Light Oil Field Indonesia

Water injection has been employed in the Tempino oil field since 1996. The current oil recovery factor is 35% of OOIP. Even though the pressure is still high, the oil production rate has declined rapidly and the water cut is approaching 89%. In order to mobilize the oil from the reservoir more effectively, surfactant flooding is one of the solutions that can reduce residual oil saturation. Interaction between crude oil and compatible surfactant generates microemulsion, as an indication of low interfacial tension. Hence the oil is expected to move out of the pore throat easily. In this research, thirty types of surfactants were evaluated. The hydrophilic lipophilic balance (HLB) was calculated and the interfacial tension (IFT) with the reservoir fluid was measured. HLB criteria were established as an indicator of low IFT, which was then tested for Berea core flooding. The results indicate that an HLB between approximately 2.7 and 3.1 (on Davies’ Scale) or greater than 11.5 (on Griffin’s Scale) gives low IFT (~10-3 dynes/cm). This characteristic is possesed by surfactant ethoxy carboxylate with a linear hydrophobic structure. This surfactant produces a high incremental oil recovery according to Berea core flood tests. The AN2NS and AN3 surfactants recovered 90% and 86% of OOIP respectively.

Development features and affecting factors of natural depletion of sandstone reservoirs in Sudan

Abstract Most reservoirs in Sudan are medium to high porosity and permeability sandstone reservoirs, these reservoirs have been developed by natural depletion since put into production, and the development is characterized by sparse wells of high production, big pressure differential, delayed infill drilling and water flooding, and rapid investment recovery. H field, FN field and P field are bottom water drive light oil field, bottom water drive heavy oil field and stratified high pour point oil field respectively, and they are representative fields in Sudan. The production performance of the three oil fields features sparse well spacing and high plateau rate, short stable production period, rapid water cut increase and fast production decline. Commingled production results in poor inter-layer development and complicated residual oil distribution. On the basis of the above analysis, major affecting factors of Sudan sandstone reservoirs natural drive have been identified through lab experiments, field development plan and field monitoring. The high off-take rate is conducive to the increase of the contract period recovery and recovery factor; sparse well spacing based on crude mobility range and determining infill well production cutoff considering contract terms can be helpful for cost-effective development; barriers and inter-layers can be made use of to detain bottom water coning and to enhance the development effect of bottom water oilfields; and delayed water injection in stratified high pour point reservoirs has no effect on recovery factor during contract period.

Potential for increasing oil Recovery from Polish oil-fields by applying EOR methods / Analiza Możliwości Zwiększenia Efektywności Wydobycia Ropy Naftowej Z Polskich Złóż W Oparciu Metody Eor

Streszczenie Jednym ze sposobów zwiększenia efektywności wydobycia ropy naftowej jest zastosowanie zaawansowanych metod wydobycia (EOR - Enhanced OilRecovery). W odróżnieniu od pierwotnych i wtórnych metod wydobycia, celem metod zaawansowanych jest dostarczenie do złoża dodatkowego źródła energii wspomagającego naturalne procesy lub je zastępującego, a także modyfikacja składu i właściwości fizycznych płynów złożowych w celu minimalizacji oporów przepływu w złożu. Metody te znajdują szczególnie zastosowanie w przypadku złóż w znacznym stopniu sczerpanych. Znaczenie tych metod w światowym wydobyciu rośnie, a dominującą rolę zaczynają odgrywać metody zatłaczania gazów w tym dwutlenku węgla. Polskie złoża ropy naftowej są obecnie eksploatowane z wykorzystaniem metod konwencjonalnych, co stwarza możliwości podniesienia efektywności wydobycia przez zastosowanie metod zaawansowanych. Proces doboru optymalnej metody do złoża jest złożony i wieloetapowy. W fazie wstępnej opiera się na podstawowych informacjach o złożu i stopniowo przechodzi do etapów zaawansowanych, kończących się opracowaniem szczegółowego projektu najefektywniejszej metody. W pracy przeanalizowano możliwości zastosowania tych metod na polskich złożach wykorzystując technikę opartą na podstawowych kryteriach ich stosowalności i logikę dwuwartościową. Przeanalizowano 49 złóż ropy naftowej z całego obszaru Polski występujących zarówno w skałach węglanowych jak i piaskowcowych. Z punktu widzenia kryteriów stosowania metod EOR, analizowane obiekty to złoża ropy o średniej gęstości i lepkości, niskiej przepuszczalności (w przypadku skał węglanowych podwójna porowatość), zalegające stosunkowo płytko lub na średniej głębokości. Uzyskane wyniki wskazują, że najszersze zastosowanie w warunkach polskich znaleźć mogą metody zatłaczania gazów, w tym dwutlenku węgla lub azotu. Wymaga to jednak przeprowadzenia szeregu badań i testów pilotażowych, gdyż doświadczenia amerykańskie nie mogą być bezpośrednio przenoszone ze względu na odmienne warunki złożowe, technologiczne i ekonomiczne.

Laboratory Studies of Producing Hydrogen and Incremental Oil From Light Oil Reservoirs Using Downhole Gasification

Abstract The idea of gasifying (reforming) a fraction of a light crude oil in the reservoir, was conceived originally by Davidson and Yule(1). This involved "stringing?? a series of downhole gasification (DHG) units along either a horizontal producer well or vertical producer well, or along some other suitable well arrangement. Although catalytic steam reforming of naphtha practiced on a large scale has been extensively researched, such understanding is largely restricted to much lower pressures than those investigated in the present study. We present results obtained using a small, "pilot-scale?? DHG unit, or reforming reactor, operated at up to 100 bar pressure. The feed to this unit was a light naphtha fraction cut from Statfjord crude oil. The effect of pressure, catalyst loading, steam to hydrocarbon ratio and gasifier temperature were investigated. Essentially, the conversion to inert gases, principally hydrogen and carbon dioxide, at high pressure was sufficiently high to make the process technically feasible in depleted light oil reservoirs. Furthermore, the economics of this novel enhanced oil recovery process, which also produces (and stores) hydrogen, appear to be very favourable. However, the experiments, which were conducted under pilot-scale conditions using a single-tube reactor unit, were not of sufficient duration time to test the long-term effects on catalyst activity owing to carbon fouling and sulphur poisoning. These factors (at least carbon deposition) can be controlled as demonstrated in the experiments by adjusting the steam-to-hydrocarbon ratio and the depth of naphtha-cut taken from the crude oil. These aspects of the process are to be further investigated in a Phase 2 project. Introduction Davidson and Yule(1) originally conceived the idea of a self-contained, downhole gasification (DHG) unit as a safer, "greener?? method for transporting oil out of environmentally sensitive areas, such as the Everglades, as gas. Subsequently, the focus was directed towards applying DHG in depleted light oil reservoirs. The inert gases generated by a downhole DHG unit(s) are directed into a gas cap, or used to create a gas cap (Figure 1). This would then allow gravity stabilized displacement (GSGI), WAG, or another assisted gas injection technique, to be implemented for the purpose of improved oil recovery. This is still a high priority, especially in such areas as the North Sea, and the many hundreds of depleted light oil fields in the US, where output continues to fall. The main IOR problem is the availability of a suitable gas to inject into the reservoir, especially offshore. Although the displacement dynamics are likely to be complex because of the hydrogen in the generated gas, it is estimated that valuable incremental oil can be gained using the DHG process.

Laboratory Screening for Air Injection-Based IOR in Two Waterf looded Light Oil Reservoirs

Abstract In the last two decades, air injection has proven to be an effective method for enhanced recovery from light oil reservoirs. This has led to a need for effective laboratory procedures for screening potential candidate reservoirs, many of which have been previously waterflooded. Experiments at the University of Calgary have shown the benefit of Accelerating Rate Calorimeter (ARC) tests in conjunction with traditional combustion tube testing at reservoir pressure for the planning of field scale implementations. In this study, four ARC tests and two combustion tube tests were performed on resaturated cores from each of the Avil? and Troncoso waterflooded light oil reservoirs of Argentina. The paper reviews the characteristics of the two reservoirs, describes the tests that were performed on the reservoir samples, and summarizes the results obtained. The ARC tests provided Arrhenius-type kinetic rate data for the ignition and combustion reactions. The combustion tube tests were used to evaluate the air requirements and overall burn stability. For each reservoir, one combustion tube test was performed at the original oil and water saturation while the second test was performed at the waterflooded saturation. The effect of initial oil saturation on the burning characteristics and liquid recoveries is of particular interests to operators considering air injection-based oil recovery projects. Background The application of air injection-based processes (or fireflooding) to deep, high pressure light oil reservoirs is a relatively new IOR process. While past applications of this process to low API oils have met with mixed success, many of the problems encountered in heavy oil reservoirs relating to mobility and unfavourable oxidation characteristics are not an issue in high API oils(1, 2, 3). The success of this process is evident from the recent start-up of a new project by Continental Resources, injecting 85 MMscfd of air into a field in the Williston Basin. Currently, several other companies are actively researching potential candidate reservoirs for air injection- based recovery processes. While air injection into light oil reservoirs is not a new process, more recent applications of air injection to light oil fields have targeted reserves that are deep and/or have had low permeability, rendering them poor candidates for waterflooding(4). However, the resulting successes and potential process benefits(5) have extended interest in this IOR process to all types of light oil reservoirs, including those that have undergone waterflooding as a secondary recovery mechanism. Air injection into previously waterflooded reservoirs entails additional considerations. From an operational viewpoint, extensive waterflooding can result in the lowering of the overall reservoir temperature, making the oil less reactive to the oxygen in the injected air. Air injection processes rely on combustion reactions between oxygen and a fraction of the oil in place to produce heat and carbon oxides, so it may be necessary to provide an artificial ignition source. The presence of large saturations of water in the reservoir constitutes a heat load to the combustion process, as it is vapourized by the advancing reaction front. Highly permeable flow channels may have very low residual oil saturations, particularly around water injection wells.

A Non-Conventional Study for Determination of H2S in Production Gas

Abstract By mid-2000, the H2S content in gas from the Chihuido Lomitas field separator started to increase significantly up to an average of 2,000 ppm. A multidisciplinary team was formed to address the problem, which was deemed to be very likely due to bacterial activity in the reservoir. Therefore, the group focused on the issue of concern, which is generally known as reservoir souring. It was concluded that using sulphur isotope measurement techniques was one of the few tools available to effectively determine the cause of the souring. A group of specialists in isotope assessments from a local Research Institute was called in to join the team. Based on the team's findings, supported by a geochemical model, it was shown that H2S generation in the Troncoso and Avile formations was due to the activity of sulphate reducing bacteria living in the reservoir. The model developed relates increasing bleeding water injection to the phenomenon studied. A thermo-chemical reduction was proposed to explain the H2S content in El Filon Reservoir. Innovative H2S removal techniques are currently being applied. Introduction The Chihuido Lomitas light oil field is located in the Neuquen Basin, in Argentina. The main producer reservoirs (Agrio Formation and Avile Member) are in the Mendoza Group (Late Jurassic - Early Cretaceous). One non-conventional reservoir produces from an igneous rock (see Figure 1). The field started to produce in the early 1980s, and is currently Repsol YPF's main oil field in Latin America. Water injection started in 1996 and, by the end of 2001, nearly 100,000 m3/day were injected through 480 injection wells. Initially, just fresh water was injected, but it was gradually replaced by production water. When the H2S content in the separator gas started to increase, a team was formed including field staff from Engineering and researchers from Repsol-YPF's Applied Technology Centre (CTA) in order to address the problem by looking at different approaches. Measurements were thoroughly checked, and a sampling survey at key points was designed. Different gas treating alternatives were discussed. It was concluded that sulphur isotope measurement techniques were one of the few tools available to effectively determine the origin of the problem. Sampling H2S collection was accomplished with a sampling device developed at INGEIS, including a flow meter and two H2S traps, with two online flasks containing AgNO3 or NaOH. Sixty samples were taken from all batteries, including formation, production, and injection water, oxygen scavengers, and crude oil. Isotope analyses were performed at INGEIS using VG 602 and Finnigan Delta-S mass spectrometers. CTA performed a standard geochemical analysis, and determined the level of fatty acids in the formation waters. Results and Discussion The main data are shown in Tables 1 and 2. We carefully analysed the different possibilities for H2S generation in the reservoir, on the basis of the isotopes results, geology, temperature range, presence of sulphides in reservoir formations, and injection/production water characteristics. The analysis also took into account the exploitation history, and the absence of H2S in the early years.

Effect of Solution Gas in Oil on CO2 Minimum Miscibility Pressure

Abstract In this study, a rising bubble apparatus (RBA) was used to determine the CO2 MMP for various oils. RBA tests permit direct observation of changes in bubble behaviour and thus offered insight into the phase behaviour for the CO2-reservoir fluid system. The CO2 MMPs were estimated for two Steelman reservoir fluids with a high gas-oil ratio, the partially flashed reservoir fluids, and the dead oils. The composition of solution gas of each partially flashed reservoir fluid was determined and the effects of different gas components were analysed. The MMP was also determined and discussed for Weyburn reservoir fluids which had a low gas-oil ratio with pure and impure CO2. The results of this study demonstrated that the effect of solution gas in oil on CO2 MP could be significant. Furthermore, achieving a miscible CO2 flood (in a reservoir with a Steelman-like reservoir fluid) could be possible at a lower operating pressure than the measured CO2 MMP, by partially depleting the reservoir. This may be the only option for some reservoirs which cannot sustain the relatively high pressure required for achieving miscibility. Introduction Carbon dioxide flooding is a proven oil recovery process(1). Over the last decade, carbon dioxide injection has become the leading enhanced oil recovery (EOR) process for light oils(2). CO2 injection can prolong, by 15 to 20 years, the production life of light oil fields nearing depletion under waterflood, and may recover 15 to 25% of the original oil in place. More than 20 years of field experience of CO2 injection has advanced the CO2 technology. CO2 injection can be introduced gradually and use some of the same equipment currently in place for waterflooding. Saskatchewan's light and medium oil resource, representing nearly 45% of proven reserves, has been on waterflood for over 30 years and is fast approaching its economic limit of production(3). For the light and medium oil reservoirs in Saskatchewan, carbon dioxide or hydrocarbon injection is considered to be the most effective EOR process(4–6). These gases can be injected into the reservoir to develop miscible or immiscible conditions with the oil depending upon the operating pressure. Carbon dioxide is preferred over hydrocarbon gases (e.g., ethane, propane) because it is cheaper, has higher density, and offers environmental benefits by providing storage for CO2 in the reservoir. The Saskatchewan Research Council (SRC) is conducting a comprehensive research program to assess the suitability of miscible CO2 displacement for reservoirs in southeast Saskatchewan and to optimize the field operating procedures. The first step in determining if a field is a viable CO2 flood candidate is to conduct a screening study to provide a reasonable estimate of CO2 injection performance. The minimum miscibility pressure (MMP) is a key parameter used in the assessment. It has been recognized that the CO2 MMP for a reservoir oil depends on the reservoir temperature, oil composition, and the purity of injected CO2. The minimum miscibility pressure increases with increasing reservoir temperature.

Factors controlling the destruction or preservation of giant light oilfields

Study of a database of 350 giant oilfields show these to be dynamic short-lived phenomena, with a median age of 35 Ma. A third show evidence for post-entrapment destructive processes, particularly erosion, fault leakage, gas flushing and biodegradation. Many cases of biodegradation may occur prior to complete filling of the oilfield. Re-entrapment of oil released from spilling or breached traps is common. The main controls on oilfield preservation are post-entrapment tectonism and seal type, with temperature and hydrodynamic regimes being secondary factors. Destructive processes are concentrated in shallow and deep zones and in seepage-prone traps such as compressional anticlines. Such factors strongly influence the distribution of preserved light oilfields, with preservation potential maximized in tectonically quiescent basins with evaporite seals, e.g. the Middle East and the Permian Basin. More attention is required, particularly in older petroleum systems, to models involving post-entrapment leakage and re-migration.

Unit Operation in the Rock River Field, Wyoming

The discovery well in the Rock River field, in Carbon County, Wyoming, camein May 1, 1918. The field is on a large anticline having more than 1500 ft. ofclosure and production is obtained from three sands of the Dakota group. At itspeak, production approximated 10,000 bbl. daily and is now averaging 2200 bbl.Total production to Jan. 1, 1930, exceeded 12,500,000 barrels. So far as known to the writer, Rock River was the first light oil field in theRocky Mountain region to be produced under what we now term unit operation.Though this type of operation was not popularly acclaimed by the oil industry, the Federal Government and the public until many years after the inception ofdevelopment at Rock River, the officials of the Ohio Oil Co. when acquiringthis property were fully cognizant of the economies to be effected by unitownership and the consequent elimination of competitive drilling and producingof wells, and had this in mind at the time. Thus unit management was introducedin this field at an early date by this company. Area and Management Fig. 1 shows the location of all wells drilled on the Rock River structure andthe outline of the productive area as now defined, which amounts to 1380 acres.The hachured line indicates the area now under unit ownership; originally amuch larger area was so owned but leases have been canceled as progressivedevelopment indicated their lack of oil. The management and operation of the entire productive area is handled by theOhio Oil Co., which owns the majority working interest. The Continental Oil Co.with a 20 to 35 per cent. interest in much of this acreage, and smallerinterests owned by others in some of the leases, constitute the remainder ofthe ownership.

Present Conditions in Mexican Oil Fields and an Outlook Into the Future

The various phases of the Mexican oil industry have received so muchpublicity that there is little to add to the discussion of present and futureproduction, extent and importance of prospective fields, and status ofpetroleum legislation, to mention but a few of the angles of the Mexican oilproblem. However, out of this wealth of information, which is generally ofcontradictory nature, the average petroleum man is at a loss to know somethingdefinite regarding the various questions involved; so, keeping the foregoing inmind, it has been the writer's aim to record in a concise form the mostreliable and up-to-date information regarding the salient features of theMexican oil situation. Present Status of Mexican Oil Industry Production During 1921 The Mexican oil fields, during 1921, produced in round numbers 203,000,000bbl. of which 176,000,000 bbl., or 86 per cent., were exported, the bulk ofthese exports, or about 73.3 per cent., going to the United States. The Mexicanexports were divided by grades as follows: Light crude, 47.0 per cent.; heavycrude, 22.0 per cent.; tops, 3.5 per cent.; fuel oil from light crude, 24.0 percent. The balance, or 3? per cent., includes the bunker fuel shipments and thecoastwise trade in Mexico, which is not classified as to grades. The figuresshow that, in importance, the light-oil fields form about 75 per cent. of theMexican petroleum industry. The production of the Panuco field has followed the general history of theAmerican fields, and its gradual decline, which is at present foreshadowed, maybe estimated as well as its ultimate economic life. On the other hand, thebehavior of the light-oil fields to the south is unlike any in the world so fardiscovered, and as a result we have concentrated overproductions followed bysudden droughts, both sometimes equally unexpected. The coming in of two orthree gushers within adequate pipe-line facilities will flood the market with100,000 bbl. or more a day, while the flooding by water of a particular poolwill, in a few weeks, remove from the market one-half the total production ofthe Mexican fields. AIME 068–68