Oil-bearing Zones Research Articles

Possible occurrences of transition zones and residual oil zones below oil-water contacts in mature oil fields, southeast Saskatchewan

A transition zone (TZ) from oil to water formed by capillary force beneath traditionally defined producing oil-water contact (OWC) has been well-known for years. Recent research and production activities in the Permian Basin and the Williston Basin in United States suggests that a residual oil zone (ROZ) may exist below traditionally defined OWC under certain geologic and hydrodynamic conditions. If this ROZ is sufficiently thick and extensive, it may be economically recoverable using tertiary recovery techniques. We have investigated possible occurrences of TZ/ROZ in the Williston Basin, southeast Saskatchewan, using well-log interpretation based on Archie’s equation. Out of 33 pools examined, we have evaluated three areas, the Bellegarde Tilston pool area, an unnamed Souris Valley pool, and the Rosebank Alida pool area, as possibly having thick (up to 47 m) low-oil-saturation TZ/ROZs below the OWCs. Evidence includes oil stains, core-based oil saturation, fluorescence on drill cuttings, and oil shows and sulfur water reported in drill stem tests. The oil in place within the possible TZ/ROZs is estimated to be approximately half the amount of the oil within their associated main pay zones. Tilted OWC and other findings may suggest that the identified oil-bearing zones are ROZs related to hydrodynamics. The hydrodynamic flows may also have created some other ROZs that still remain undiscovered.

A Full-Field Interwell Tracer Program on a Giant Carbonate Oil Field

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 177527, “The Design and Implementation of a Full-Field Interwell Tracer Program on a Giant UAE Carbonate Oil Field,” by D. Wang, A.B. Al-Katheeri, S.M. Al-Nuimi, and A. Dey, Abu Dhabi Company for Onshore Petroleum Operations, prepared for the 2015 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 9–12 November. The paper has not been peer reviewed. This paper reviews the design and implementation of a full-field interwell tracer program for a giant onshore oil field in Abu Dhabi. The field is under peripheral waterflooding in order to maintain reservoir pressure and provide a mechanism to sweep the oil. However, the existence of strikeslip fault planes juxtaposed across the reservoirs added a variable to the complexity of waterflood management. To improve the understanding of reservoir heterogeneity and reduce the uncertainties associated with major faults, a full-field water-tracer program has been designed. Introduction On the basis of the streamline model, unique chemical tracers have been injected in 21 water injectors covering all the peripheral areas; dozens of associated offset producers across the field were selected to monitor the tracer movement. The design of the program is explained in the complete paper in terms of tracer selection and capability tests, chemical-volume calculation, injection-well and monitoring-well selection (made on the basis of the streamline model), and design of the comprehensive monitoring plan. Ultimately, the results of this tracer program will be used in combination with other reservoir-surveillance tools to facilitate better management of the reservoir. Background The subject field is located approximately 110 km to the southeast of Abu Dhabi Island. The field was discovered in 1965, with first production in 1973 and first water injection in 1976. The main oil-bearing zones are X, Y, and Z. These zones are in communication through faults. Each zone is bounded at the top and base by a dense argillaceous limestone and further subdivided by the occurrence of stylolite-bearing dense intervals. Of these, Zone Y, the subject of this study, contains more than two-thirds of the field’s original oil in place. Zone Y is an undersaturated, heterogeneous, and highly stratified reservoir with an average porosity of 30%. It is divided into five subzones. The Upper Y contains the higher-permeability zones in excess of 700 md, while the Lower Y has a lower permeability of approximately 10 md. The current development scheme, with selective injection and production under peripheral water injection, was implemented in 1982. The existence of major faults in Zone Y resulted in splitting the reservoirs into 12 main sectors. Among the major monitoring tools and techniques, tracer injection is one of the most important for monitoring the effectiveness of a waterflood project because of the lack of direct information on flow from individual injection wells. Tracer injection can be used to determine early water breakthrough in different areas, crossflow between zones, and the degree of water slumping caused by reverse coning.

A pilot numerical simulation case study for chemical EOR feasibility evaluation

Because of high oil price and technology advancement in recent years, chemical EOR is becoming an important option for maintaining sustainable efficient development for mature reservoirs in the future. In this paper, an integrated numerical simulation approach is adopted for Palouge oilfield in South Sudan for chemical EOR feasibility evaluation. The chemical EOR methods are preliminarily screened for the main oil-bearing zones, and the advantages and disadvantages for chemical flooding are analyzed by comparing technical parameter limits with oilfield parameters. Specifically, the pilot oil zone and areal position selection was determined using a comprehensive method, which is based on zonal injection plan and application experiences. Chemical EOR simulation is performed for sensitivity analysis and different scenarios prediction. Three technical indicators are employed to evaluate the EOR efficiency. Some key physiochemical factors with uncertainty are also analyzed in detail, and this will provide unusual useful information for comprehensive feasibility evaluation. The proposed technical evaluation procedure provides a helpful guidance for chemical EOR feasibility assessment in other analogous reservoirs.

Sampling with new focused, oval, and conventional probe-type formation-tester in the presence of water- and oil-base mud-filtrate invasion for vertical and high-angle wells

Abstract Speculation about the potential of developing new fluid and pressure sampling methods with probe-type formation testers has existed since the introduction of formation pressure testing while drilling technology was introduced to the industry nearly a decade ago. To replace the existing wireline technology, a new pumping system is required to remove invasion fluids and then to fill single-phase sample chambers. To make this commercially possible, several technology enhancements are necessary in advance. Although wireline pumpout tools may require hours to retrieve representative fluid samples, it is not a practical alternative to spend hours obtaining samples in the drilling environment. Most simulations of wireline formation-tester measurements assumed that invasion ended at the time when fluid pumpout began. Additionally, previous studies assumed a time-constant rate of invasion that was the time average of invasion rate. Both of these assumptions are optimistic for a drilling tool. The objective of this study is to quantify the viability of sampling in the drilling environment by way of numerical simulations. The study considers the dynamic nature of invasion while drilling when using both new and conventional probe configurations to retrieve fluid samples. With the realistic mudcake model, there are higher rates of invasion soon after drilling. Therefore, to simulate the invasion during drilling, a mudcake model is used that continues to grow in thickness and sealing effectiveness during invasion and throughout the sampling process. Simulation results focus on scenarios in which water-base mud (WBM) and oil-base mud (OBM) invade an oil-bearing zone. Furthermore, it studied the accuracy of functions used to estimate contamination in an OBM environment. The base model consists of a typical probe-type tool in a vertical well wherein fluid samples are retrieved using a time-constant flow rate. Invasion time is varied from 1 to 48 h to compare drilling and wireline sampling tools. Simulations of fluid cleanup times for a variety of rock types and wellbore deviation angles indicate that the oval focused probe retrieves the cleanest fluid sample in the least amount of time. This study also quantifies mudcake sealing effectiveness, as well as the effect of borehole deviation. Oval (elongated) and focusing guard-style probes are compared to standard probe configurations in various petrophysical rock types.

Researches on Sequences Stratigraphy of Neogene in Huanghekou Sag, Bohai Bay Basin, China

The Huanghekou Sag, as an important oil-bearing zone, is located in the southeastern part of the Bohai Bay basin. It has higher values for petroleum exploration-especially in Neogene. The Neogene was a depressional lacustrine period and was characterized with both tectonically stable and gentle topography. Thus it is difficult to identify and subdivide sequences using the traditional method. Based on the practical geologic setting and current data of the Neogene of Huanghekou Sag, using the new method to set up the isochronous sequence stratigraphic framework. By analyzing climate cycle, drilling well and logging cycle, seismic cycle and the identification of unconformity of seismic and drilling well and logging data, the Neogene was divided into 5 third-order sequences and 10 systems tracts. In different sequence sets and systems tract, which was controlled by climate, ratio rate between sedimentary being supplied and accommodated, the sand body scale was different.

Characteristics of the turbidite fan in the Wenchang Formation of the Enping Sag, Pearl River Mouth Basin, China and its hydrocarbon significance

A turbidite fan in the Eocene upper Wenchang Formation in the Enping Sag, Pearl River Mouth Basin (PRMB) has been studied using seismic, logging and borehole data. The fan is characterized by parallel progradation on the dip seismic profile and is mound-shaped or lenticular-shaped on the strike seismic profile. The study of the core and logging data from well EP17-3-1, which is located in the front side of the turbidite fan, shows that this fan is a set of normal grading sand beds, interbedded within thick dark grey mudstones of semi-deep to deep lake deposits in the Wenchang Formation. The fan is interpreted as a sand/mud-rich turbidite fan that has an area of over 140km2 and a maximum thickness of over 340 m. Combined with a study of the regional geological background and previous provenance analysis of the Eocene Wenchang Formation, the main potential provenances for the turbidite fan are considered to be the Panyu low-uplift and northern fault terrace zone. The Enping Sag is considered to be a half graben-like basin whose north side is faulted and whose south side is overlapped. Basement subsidence in the Eocene was mainly controlled by boundary faults which dip relatively steeply on the north side, causing the subsidence center of the Enping Sag in this stage to be close to the north boundary faults. Sustained faults developed in the Enping Sag during the Eocene caused an increase of the relative height difference between the north and the south uplift zone in the Enping Sag. Affected by the second episode of the Zhuqiong movement (39–36 Ma) in late Eocene, sediments which had accumulated on the Panyu low-uplift zone were triggered and moved toward the subsidence center of the Enping Sag and formed the turbidite fan. The second episode of the Zhuqiong movement is the most important triggering factor for the formation of the turbidite fan in the Wenchang Formation. Seismic attribute characterization shows that the low frequency energy is enhanced and high frequency energy is weakened when seismic waves propagate through the oil-bearing zone in this fan. Amplitude versus offset (AVO) anomalies are observed in the seismic data and abnormally high pressure is encountered. The turbidite fan in the Wenchang Formation has provided important information for sedimentary evolution in deep layers of the Enping Sag and pointed to a new direction for the hydrocarbon exploration in the study area.

Future Directions of Electromagnetic Methods for Hydrocarbon Applications

For hydrocarbon applications, seismic exploration is the workhorse of the industry. Only in the borehole, electromagnetic (EM) methods play a dominant role, as they are mostly used to determine oil reserves and to distinguish water from oil-bearing zones. Throughout the past 60 years, we had several periods with an increased interest in EM. This increased with the success of the marine EM industry and now electromagnetics in general is considered for many new applications. The classic electromagnetic methods are borehole, onshore and offshore, and airborne EM methods. Airborne is covered elsewhere (see Smith, this issue). Marine EM material is readily available from the service company Web sites, and here I will only mention some future technical directions that are visible. The marine EM success is being carried back to the onshore market, fueled by geothermal and unconventional hydrocarbon applications. Oil companies are listening to pro-EM arguments, but still are hesitant to go through the learning exercises as early adopters. In particular, the huge business drivers of shale hydrocarbons and reservoir monitoring will bring markets many times bigger than the entire marine EM market. Additional applications include support for seismic operations, sub-salt, and sub-basalt, all areas where seismic exploration is costly and inefficient. Integration with EM will allow novel seismic methods to be applied. In the borehole, anisotropy measurements, now possible, form the missing link between surface measurements and ground truth. Three-dimensional (3D) induction measurements are readily available from several logging contractors. The trend to logging-while-drilling measurements will continue with many more EM technologies, and the effort of controlling the drill bit while drilling including look-ahead-and-around the drill bit is going on. Overall, the market for electromagnetics is increasing, and a demand for EM capable professionals will continue. The emphasis will be more on application and data integration (bottom-line value increase) and less on EM technology and modeling exercises.

Application of seismic anisotropy fluid detection technology in the Ken 71 well block of Shengli Oilfield

On the basis of Chapman’s (2003) model, as the seismic wave incidences angles vary from 0° to 45° while propagating in anisotropic media (HTI), the slow S-wave will sufferred by serious attenuation and dispersion and is sensitive to fluid viscosity but the P- and fast S-waves don’t. For slow S waves propagating normal to fractures, the amplitudes are strongly affected by pore fluid. So, the slow S-wave can be used to detect fractured reservoir fluid information when the P-wave response is insensitive to the fluid. In this paper, 3D3C seismic data from the Ken 71 area of Shengli Oilfield are processed and analyzed. The travel time and amplitude anomalies of slow S-waves are detected and correlated with well log data. The S-wave splitting in a water-bearing zone is higher than in an oil-bearing zone. Thus, the slow S-wave amplitude change is more significant in water-bearing zones than in oil-bearing zones.

Resistivity correction for drilling fluid invasion using LWD and wire-line logging data: A case from high-porosity and low-permeability carbonate reservoirs, DLL Oilfield, Oman

Abstract The effect of drilling fluid invasion on the resistivity of oil-bearing zones during the period from penetrating the zone to completion well logging was studied using intergraded logging while drilling (LWD) and wire-line log data. The results indicate that resistivity change during invasion responds to some important factors such as porosity, oil saturation, pressure differential between drilling mud column and formation, mud filtrate salinity and invasion time. It increases as an exponential function of porosity, a logarithmic function of pressure differential, and a power function of invasion time and oil saturation. Based on the LWD and MDT data, the corrected resistivity equation subject to the drilling fluid invasion was acquired. With the equation, the oil saturation (So) increases by 6.3%–20.0%, averaging at 10.2%.

Experimental Design Reduces Risks of a Siberian Development Having Subsurface and Financial Uncertainties

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 115575, "Experimental Design Reduces Risks of a Siberian Development With Subsurface and Financial Uncertainties," by David E. Tipping, SPE, TNK-BP; Franz X. Deimbacher, SPE, and Dmitry Kovyazin, Schlumberger; Alexey Medvedev, SPE, Landmark; and Randy Valencia, TNK-BP, prepared for the 2006 SPE Russian Oil & Gas Technical Conference and Exhibition, Moscow, 28-30 October. The paper has not been peer reviewed. Experimental-design methodologies were used to evaluate development options in a Siberian field having major uncertainties in geological, reservoir, and financial parameters. The approach demonstrated that an inverted seven-spot injection pattern would yield 11% more oil than a conventional linedrive method. For decision making, the analysis predicted that the expected net present value (NPV) of the seven-spot pattern would be 46% more than that of the linedrive pattern. Introduction The primary reservoirs in this Russian field consist of stacked fluvial, delta-distributary-channel, and mouth-bar sands. Exploration tests confirmed oil rates exceeding 120 tonnes/d. Recognizing this risk to project success, an experimental-design technique was developed for quantifying the uncertainties in oil-rate predictions. The experimental-design techniques, integrated with advanced computer technology, reduced evaluation times from months to weeks. More importantly, they provided unbiased probabilities of production profiles and NPV so that downside risks can be quantified. Development Context The proposed development area encompasses two oil-bearing zones. The shallow zone consists of sand-stones with thicknesses varying from 0.5 to 3 m with numerous interbedded siltstones. The deep zone is in an underlying incised-valley-fill complex surrounded by impermeable siltstone. Although the 2D seismic could delineate the boundaries of the incised valley, its resolution did not permit differentiating the sand bodies from the surrounding siltstone within the valley fill. A subsequent sedimentological review of core data revealed promising reservoir sands. Well tests of the valley-fill sand bodies yielded promising initial oil rates that exceeded 120 tonnes/d. However, major uncertainties existed. Although the well tests confirmed the presence of an oil/water contact (OWC), given the thin nature of the sand bodies, the OWC response on the wireline logs was suppressed by surrounding siltstones. As a result, an OWC uncertainty of 4 m existed with potential adverse effect on the estimated oil initially in place. Seismic data also revealed anomalies, possibly indicating faults acting as flow barriers. The seismic did not have sufficient resolution within the incised valley to differentiate sand bodies from the surrounding siltstones.

Hydrocarbon Compositional Gradient Revealed by In-Situ Optical Spectroscopy

Summary This paper presents a case study of a North Sea appraisal well in which a vertical fluid-composition variation, missed by a conventional pressure-gradient-analysis method, was observed in situ in real time by a new fluid-composition analyzer using visible near-infrared (NIR) spectroscopy. For optimal oil production, assessing the spatial variation of fluid properties is as vital as assessing the spatial variation of formation properties. Conventional wireline triple-combination measurements showed that the interval of interest was uniform and free of noticeable impermeable layers. A resistivity log showed an approximate oil/water contact (OWC). Wireline pressure testing identified three different pressure gradients corresponding to gas, oil, and water, all in hydraulic communication. However, the pressure testing did not indicate a gradient in hydrocarbon composition. Fluid was sampled and analyzed in real time by a wireline fluid-sampling-analyzing tool string that included the fluid-composition analyzer. This tool analyzes petroleum fluid and gives concentrations for four group compositions (C1, C2–C5, C6+, and CO2), gas/oil ratio (GOR), and qualitative information regarding heavy-end content and stock-tank crude density. The analyzer showed that the hydrocarbon fluid in an oil-bearing zone was not vertically homogeneous but, instead, had a vertical variation. The samples captured by the wireline sampling tool were sent to a laboratory for compositional analysis that confirmed the variation determined by the downhole analysis. Both results identified the heterogeneity of hydrocarbon fluid in the interval. This paper also briefly covers the measurement principle of the analyzer and discusses the impacts and benefits brought about by the new technology. The concept of flexible fluid sampling is particularly important because it enables operators to make sampling decisions on the basis of real-time fluid-analysis results rather than a predetermined job plan.

Optimization of Well Performance in a Selective Subsea Sand-Control Completion, Offshore Nigeria

Summary Developing the Okwori field (offshore Nigeria) required the combination of several recent technological advances. The subsea development targeted multiple oil-bearing zones in all wells with the requirement that each zone could be operated independently. Expandable sand-screen (ESS) strings were deployed within casing for up to four zones to prevent sand production from unconsolidated-sandstone reservoirs. Independent control of all zones was made possible by use of remotely operated surface-controlled sliding-sleeve units [(ROSS) trademark of Weatherford U.K.] Losses experienced after perforating required the use of loss-control material (LCM) for well control. Initial LCM formulation appeared to yield formation damage. A special effort ensued to design optimal LCM pills to meet project requirements. This paper presents the completion issues associated with the project, the optimization of the LCM pills, and the design and placement aspect of the remedial treatment associated with this type of completion. The evolution of the completion efficiency for each zone throughout the learning curve is presented and discussed.

MEOR in Northwest Peru

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 94934, "Biotechnology Application to EOR in Talara Offshore Oil Fields, Northwest Peru" by A. Maure, Microbes Inc., and A.A. Saldana, SPE, and A.R. Juarez, SPE, Petro-Tech Peruana S.A., prepared for the 2005 SPE Latin American and Caribbean Petroleum Engineering Conference, Rio de Janeiro, 20–23 June. Seven producing wells in the Providencia and Lobitos fields of Block Z-2 in the Talara basin were selected to evaluate a biotechnology approach for enhanced oil recovery (EOR). The microbial-EOR (MEOR) candidates produce from faulted reservoirs by intermittent gas lift methods. The oils are paraffinic and present good candidates for biotreatability. Because of operational reasons not directly related to MEOR, the complete inoculation program was concluded in only four of the original seven wells. Biotechnology Biotechnology methods are founded in the use of sophisticated enzyme biochemistry to accelerate redox reactions that involve different hydrocarbon compounds. MEOR technology in the upstream sector is based on the systematic inoculation of producers and/or injectors with specific microbial systems, biocatalyzers, and nutrients. The pulsing program pursues as its primary goal the colonizing of the porous medium of the oil-bearing zones. The second objective is to control enzymatic reactions at water/oil interfaces in the producing formation to modify oil mobility by producing low-molecular-weight solvents and biosurfactants. Organic geochemistry methods monitor the stability and efficiency of these bioreactions. Producer Wells. Producer wells are treated by periodically pumping microbial batches downhole to reach the near-wellbore porous space. The microbial effect in treated wells benefits production in two ways. It removes organic damage occurring near the wellbore of the perforated interval to open nonproductive zones containing oils with a heavier and pseudoplastic behavior. This effect produces a high peak oil rate for a limited time. These treatments can produce permanent rheological effects by the compositional alteration that occurs at a larger colonization radius. This effect is the most important MEOR objective because this improvement is sustainable for a long period if a proper microbial inoculation schedule is continued. Injector Wells. In injector wells, the treatment uses the injected water as a carrier to introduce microorganisms and passive substances into active streamtubes of flooded space for target layers. Compared to the producer treatments, the advantage of treating injectors is a larger size of colonized zones with longer residence times. Biocracking. Biocracking is based on a systematic way to alter n-alkane compositional profiles in oils. The use of enzyme biochemistry accelerates the redox reactions involving linear hydrocarbons. Heavy paraffinic compounds can be transformed into shorter ones by the enzymatic action of repetitive cycles, which are assisted by symbiotic microorganisms and specific nutrients. By alternating aerobic/facultative hemicycles with strictly anaerobic, the time-coordinated action of selected groups of microorganisms in oxidant and reductive environments results in a substantial shift in oil compositional profile.

Improved identification of pay zones through integration of geochemical and log data: A case study from Upper Assam basin, India

The upper Paleocene-lower Eocene clastic reservoirs constitute one of the most important hydrocarbon-producing horizons in the Upper Assam basin of northeast India. These reservoirs are characterized by the presence of (1) normal gravity oil (23-31° API), (2) low to intermediate gravity oil (13-23° API), and (3) gas and light oil/condensate (> 31° API). The sandstone reservoirs show complex wire-line log signatures, which are commonly misleading. The main impediments to understanding the nature of reservoir fluid include (1) distinguishing low gravity, intermediate gravity, and normal gravity oil-bearing zones and (2) resolving the problem of density (RHOB)-neutron porosity (NPHI) crossover for gas-bearing, as well as oil-bearing, reservoirs. Geochemical analyses of sidewall core extracts by thin layer chromatography with flame ionization detection (TLC-FID) and gas chromatography (GC) provide valuable, cost-effective input for reservoir fluid characterization. The important parameters needed to identify the nature and composition of the reservoir fluid include (1) the bulk composition of the sidewall core extract (i.e., % saturated hydrocarbons, % aromatic hydrocarbons, and % resins + asphaltenes), (2) amount of extract in mg/g of rock, (3) GC fingerprint, and (4) the ratio of pristane to n-C17. These parameters, integrated with geological and geophysical (wire-line logs) evidence, yield more accurate and reliable formation evaluation criteria. The technique is simple and inexpensive and may find application as an additional formation evaluation tool in any geological setting.

Heavy Oil Production By In Situ Combustion-Distinguishing the Effects of the Steam And Fire Fronts

Abstract In heavy oil production by in situ combustion, information on the relative importance of the combustion and steam fronts is very useful in the development of good production strategies. To obtain this information for two reservoirs, one containing heavy oil and the other a bitumen, a novel series of combustion tube tests was conducted. Contrary to conventional belief, the results showed that, before steam breakthrough, the produced oil properties were influenced much more by steam distillation than by cracking reactions. While the combustion front mobilized substantial amounts of oil, almost all of it remained behind the steam front. This oil displayed significance differences in properties and composition compared with the original oil. Overall, the results helped to provide some guidelines for developing improved strategies for fireflood operation, and emphasize some requirements for the prediction of fireflood behaviour. Introduction As a thermal method of improved oil recovery, in situ combustion has the advantage of delivering heat to a formation very efficiently. Consequently, the prospect of using in situ combustion to produce heavy oils has continually attracted interest, particularly for thin formations where heat losses to non-productive horizons are large. The results of field trials(1–3) in such reservoirs have varied widely, suggesting that the method may be strongly affected by the approaches used to apply it. To help develop efficient strategies for in situ combustion it is important to understand its many mechanisms and their impact on oil recovery. Islam et al.(4) have demonstrated the importance of the gas flooding effect on oil recoveries during in situ combustion. Other phenomena, such as the combustion steam fronts, must also affect oil production. During dry combustion, the steam zone may be small, particularly in thin reservoirs. In this case, the combustion and steam fronts act almost as a unit. During wet combustion, however, when water is injected behind the combustion front to scavenge heat and deliver it, in the form of steam, to the oil-bearing zone, the steam front can advance well ahead of the combustion front. In this case, several important questions arise. Does the steam front dominate the oil displacement process leaving the combustion front to function only as the heat source that sustains the steam front, or does the combustion front also serve to displace oil? To what extent does each front affect the properties of the displaced oil? In an effort to answer these questions, a series of four combustion tube tests was carried out. These tests were designed to show the effects of each front in two reservoirs, one representative of a heavy oil, and one of a bitumen. Equipment The experiments were conducted in a heavy-walled Incolloy 800 combustion tube with an inside diameter of 5.37 cm, a total inside length of 162.3 cm, and a wall thickness of 0.49 cm. No pressure jacket was employed. The maximum working pressure was 4.2 MPa (610 psig). Pack temperatures at the centreline were measured with 25 thermocouples inserted through fittings welded in a helical pattern on the tube wall.

Simulation of the hydrocarbon structures using the P-SV wave solution

Numerical solution of the scalar and elastic wave equations has greatly aided geophysicists in modeling seismic wave fields in the complicated geologic structures containing hydrocarbons and hence increases the geologic interpretation. Finite-difference method offers a versatile approach to compute synthetic seismograms numerically for given subsurface complex geological structures. To avoid the spatial derivative of the elastic parameters and density, elastodynamic equation (first-order hyperbolic equation) has been solved using the Lax-Wendroff scheme. A numerical finite-difference modeling program has been developed for the P-SV wave using the above solution. A line source with a time delay of 0.015s and dominant frequency of 120 Hz has been utilized in the simulation. In order to avoid the large values of the displacement vector in the source region,Alterman andKaral's method (1968) has been utilized. Horizontal and vertical component synthetic seismograms have been computed for two different geological models with and without oil and gas bearing zones. It has been concluded from the response that a finite-difference technique not only yields the relative arrival times but also accounts for the variation in amplitude and phase according to the elastic impedance contrast across the interfaces. It should come as no surprise to learn that in spite of the limitation of this numerical method, the scheme has provided a valid response for the thin layer, high acoustic impedance contrast and the pinch out.

Application of Fluorescence Techniques for Mud-Logging Analysis of Oil Drilled With Oil-Based Muds

Summary The Texaco E&P Technology Div. has developed two fluorescence techniques to enhance the detection of crude oil extracted from formation samples and to improve mud logging as a formation evaluation tool. The quantitative fluorescence technique (QFT) is a portable field method that uses a single excitation wavelength and measures fluorescence at a narrow emission range. When plotted vs. depth, the intensity measurements generate an oil concentration profile of the well. The QFT has successfully located oil-bearing zones that were difficult to identify with conventional mud-logging techniques. The total scanning fluorescence (TSF) technique uses a more sophisticated ultraviolet (UV) spectroscopic instrument and generates a 3D fluorescence spectrum or "fingerprint." This spectrum results from the total fluorescence contribution of the fluorescing species present in the oil. The unique chemical makeups of different crude oils have spectral characteristics that can be used to predict oil composition or type. The TSF method gives more information than conventional fluorescence techniques. This paper discusses the effectiveness of the QFT and the TSF method for identifying crude oil in the presence of fluorescing drilling-mud additives (such as base oils or diesel) and includes a feasibility study that demonstrates the application of these methods in a North Sea well drilled with an oil-based mud. Examples in wells offshore the Mediterranean Sea and Gulf of Mexico are also cited.

The depositional characteristics and oil potential of paleo Pearl river delta systems in the Pearl river mouth basin, South China Sea

Delta systems in the Zhuhai, Zhujiang and Hanjiang formations are interpreted as having formed during periods of sea-level rise from the late Oligocene to mid-Miocene (30-10.5 My B.P.). Deltas in the Zhuhai Formation were developed in a shallow water environment on a sandy, wave- or fluvial-dominated coasts. Thick and blanket-like sandstones are common but mudstones are infrequent. Oil-bearing zones have been found only in the upper part of the systems, overlain by mudstone of the Zhujiang Formation. Deltas in the Zhujiang Formation are interpreted as having formed in a deeper water environment on sandy, wave- or fluvial-dominated coasts. Carbonate platforms started growing on the Dongsha massif as the sea-level slowly rose. The moderate sandstone/mudstone ratio in the delta systems and a zone of secondary porosity in the carbonate rocks provide an excellent reservoir rock and seal rock for the basin. Deltas in the Lower Hanjiang Formation are similar to those of the Zhujiang Formation, but the upper part of the Formation is interpreted as having formed in a shelf environment; the thick shelf mudstone, interbedded with offshore bar sandstones, would be one of the better regional seal rocks in the study area. No carbonate rock developed on the Dongsha massif due to the rapid rise in sea-level. All delta systems from the Zhuhai to the Zhujiang Formation are stacked in an onlap pattern indicating a more and more expanding marine transgression, which was caused by eustatic sea-level rise. This marine transgression is almost unique and contrasts to the progradational (offlap) pattern of Cenozoic delta systems in the Gulf of Mexico. It resulted in thick sandstone deposits, immature or poorly mature source rock and no ductile mudstones, with no growth faults or rollover structures. Hydrocarbons generated from Eocene-Oligocene lacustrine source rocks are trapped by drape structures related to local basement highs or by carbonate rock with secondary porosity. Most of the remaining undiscovered reserves in the basin will be found in non-structural, subtle traps, especially stratigraphic traps.

Low enthalpy geothermal fluids from the Paris sedimentary basin—1. Characteristics and origin of gases

Fifty-seven wells tapping low enthalpy geothermal waters from the Dogger limestone reservoir of the Paris Basin have been sampled and analysed for their gas composition. Methane/ethane ratios indicate that hydrocarbons originate from both biogenesis and thermogenesis. Relatively high and variable H 2 concentrations are likely to result from fluid interaction with geothermal installations. Regional trends among main species (N 2, CO 2, CH 4) reflect large-scale heterogeneities which were already revealed by the geochemistry of the fluids (Criaud et al., 1986). Northern sites are generally nitrogen-rich and southern sites methane-rich, a characteristic which may be linked to the occurrence of oil-bearing zones in the south. N 2, Ar and He absolute contents show clear positive correlations. In particular, N 2—Ar trends are best explained by the occurrence of a paleocomponent, likely to be an evolved seawater. Helium model ages are consistent with the geological age of the host formation but are in contradiction with hydrologic ages. Assuming an exotic flux of helium into the aquifer this discrepancy may be overcome, but its computed rate apparently exceeds the current estimates for the continental degassing flux.

Performance Of South Swan Hills Tertiary Miscible Flood

Abstract A review of the performance of the tertiary hydrocarbon miscible flood which has been operating in the West Waterflood area of the South Swan Hills Unit since September 1982 is presented. The production trend clearly indicates that the tertiary flood has reversed the steady decline experienced under waterflood to the extent that the oil production has increased from 450 m3/day to as high as 1200 m3/day in 1986. The ultimate recovery factors for the project area are estimated at 38% original oil-in-place (OOIP) by waterflood and 59% OOIP by miscible flood. The projected 20% incremental recovery is based on a black oil model simulation and is in line with the incremental recovery predicted for the secondary miscible flood in the South Swan Hills Unit(1). The early performance of the tertiary flood is consistent with model simulation work and indicates that the projection in incremental recovery is achievable. Introduction The South Swan Hills Unit is located 190 km northwest of Edmonton, Alberta (Fig. I). Production is from the Swan Hills member of the Beaverhill Lake Formation which is a reef of Upper Devonian age. The unit is subdivided into three project areas (Fig. 2). The tertiary hydrocarbon miscible flood was installed in what was originally the West Waterflood Project area in September 1982. The project area encompasses approximately 4450 ha and contains 83 wells drilled on 64-ha spacing. Current plans are to inject a total hydrocarbon slug of 47.2% HCPV. This slug will comprise 15% HCPV solvent slug followed by a 32.2% HCPV dry gas slug. Both slugs are to be injected at an injection ratio with water conducive to optimum flood performance. Following hydrocarbon injection, the flood will revert to straight water injection. Geological Description The South Swan Hills reservoir is a Beaverhill Lake carbonate reef which comprises four oil-bearing geologic zones (Fig. 3). In the Tertiary Project area, only Zones 1 and 2 are of concern because, excluding the northern portion of the project area, Zone 3 (table reef zone) is predominately water-bearing. Zone 1 is a porous calcarenite which is characteristically of good porosity and high permeability. Zone 2 varies from a continuous reef front facies in the western part of the project area to a lagoonal facies in the eastern portion. Except for intermittent porous stringers, the lagoonal facies is characteristically poorer in quality. The reservoir rock averages 25 m in thickness and 8% in porosity. Waterflood Performance Waterflood operations began in 1963 at which time a semi-peripheral line drive was installed along the southwestern edge of the unit (Fig. 4). Additional voidage replacement capability was added as unit allowable were increased. Prior to start-up of the secondary miscible flood in the central portion of the unit in 1973, an estimated 5.0 × 106 m3 of oil migrated from the West Waterflood Project area into the Secondary Miscible Flood Project area due to a high pressure gradient which existed easterly across the unit(1). Waterflood operations continued in the West Waterflood area until September 1982. Figure 5 shows the production performance of the West Waterflood area since 1963.