Reservoir Mapping Research Articles

The Importance of Initial Reservoir Pressure for Tight Gas Completions and Long-Term Production Forecasting

Abstract Flow and buildup testing of gas wells in Alberta is common practice for the determination of reservoir pressure, permeability and wellbore skin. Post-frac welltesting is still regarded as the preferred welltesting method, due in part to current government regulations for initial testing requirements. With the maturing of the Western Canadian Sedimentary Basin (WCSB) in recent years, the development of unconventional gas reservoirs has significantly increased. Deep tight gas reservoirs have become an important part of unconventional gas resources and this paper will address several issues and pitfalls related to the welltesting of tight gas. Initial reservoir pressure is probably one of the most important ‘data points’ for reservoir engineering and completion design and yet one of the most abused and assumed parameters. Field examples will highlight major errors that are likely to occur when post-frac flow and buildup tests are analyzed for tight gas reservoirs without precise knowledge of the initial reservoir pressure. This paper will demonstrate that errors of reservoir pressure as small as 2% can lead to significant overestimates of the well 's recoverable reserves. Introduction The strong commodity prices in the energy sector experienced in recent years have resulted in an increased activity level for the development of unconventional tight gas reservoirs. Natural gas price is the major factor that will determine the economic viability of tight gas reservoirs. However, there are additional factors that should be taken into consideration, such as original-gas-in-place, completion efficiency, well spacing and the ultimate recoverable reserves. Unlike conventional gas reservoirs where proven reservoir engineering techniques are easily applied, the predictability of deep tight gas reservoirs is much more difficult to achieve. Too often the post-frac welltest results from wells completed in tight gas reservoirs are used to establish initial pressure, completion effectiveness and reservoir permeability for production forecasting for economic decisions. The flow behaviour of hydraulically fractured tight gas reservoirs is very complex and significant errors in the determination of matrix permeability and fracture parameters often occur. These errors can have a significant impact on predicting gas production and total cumulative gas recovery. Discussion With the maturing of the WCSB and high natural gas prices, the activity levels in the oil and gas industry have increased to record levels. So has an increased number of tight gas well completions. Generally speaking, performance evaluation of tight gas wells reveals a trend where the production performance of the wells is much less than what was initially predicted. These errors are considered the result of overestimating reservoir parameters such as the reservoir flow capacity (kh). Short references will be made to some of the factors determining the success of developing a tight gas resource:Original-gas-in-place (OGIP) is usually determined by the volumetric method and requires knowledge of reservoir pressure, mapping and petrophysical parameters. One equation used for estimating OGIP is:Equation (1) (Available In Full Paper)Hydraulic fracturing is a necessary step in the completion process in tight gas reservoirs in order to achieve commercial production.

Reservoir mapping using the high frequency EM method: Taob oil field case study

This paper is an introduction to the high frequency electromagnetic (EM) method and its application. The method uses multiple sources (natural and artificial) and five electromagnetic tensors are recorded. After data processing, resistivity and phase anomalies can indicate reservoir boundaries and favourable areas for drilling. The method has been applied to the Taob oil field and the results are presented in the paper. In this case, the oil-bearing area was mapped accurately and another prospective area was discovered. Many successful cases in China have demonstrated that the high frequency EM technique can be widely used for reservoir mapping and indications of prospective areas. The setting The Taob oil field is located in the Songliao Basin, northeast China, where 2D seismic data have been acquired. The target formation K1 2 is shallow (300-400 m) and regionally eastward dipping (Fig. 1). It is especially worth mentioning that the recently discovered overthrust in the western blocks, which trends northeastwards, acted as a seal for the oil and gas migrating from the central depression, and that oil is present in several faulted structural noses associated with the eastern side of the overthrust. This has made commercial oil production possible on the regional slope. The traps delineated in the area are mainly structural. Study of this shallow reservoir shows that there might be many other lithological traps and overlap traps, which is a challenge for seismic prospecting. In order to probe the non-structural traps economically, the high frequency EM technique was adopted in this case and the results show its good effect.

Three-dimensional Bayesian inversion of audiomagnetotelluric data in the salinity zone of a coastal groundwater reservoir

The applicability of the Bayesian inversion of audiomagnetotelluric data to the electromagnetic mapping of groundwater reservoirs is examined. A model example is used to demonstrate that both the reservoirs and their salinity zones can be mapped using measurements of magnetotelluric fields in the audio frequency range.

Petrophysical and seismic properties of lower Eocene clastic rocks in the central Maracaibo Basin

High-resolution, well-log cross sections are used to map the continuity of hydrocarbon-bearing sandstone reservoirs in the Centro Lago fields, central Maracaibo Basin, Venezuela. Because most sandstone reservoirs are below the limit of seismic resolution, reservoir mapping relies on detailed well-log correlations. Seismic data are used mainly to define the structural framework. A feasibility analysis based on the correlation of seismic data and petrophysical properties of Eocene clastic rocks was conducted to demonstrate that lithology and fluid content can be differentiated by acoustic impedance known from well-log data. However, low vertical resolution of the three-dimensional seismic data made available for this study (25 Hz dominant frequency) is not adequate to constrain the lateral and vertical continuity of the Eocene reservoirs. The main sandstone reservoirs in lower Eocene clastic rocks of the Centro Lago fields are found in distributary channels and tidal sand-bar facies. These reservoirs provide good-quality fluid-flow units. Channel complexes and sand bars are concentrated along the crest of a north-northeast–trending anticline bounded by parallel left-lateral strike-slip faults. Reservoirs are generally compartmentalized by transverse northwest-southeast–striking faults that intersect the main anticlinal axis. Detailed high-resolution well-log cross sections and mapping, integrated with the structural framework interpreted from the seismic data, indicate the presence of untested oil plays in the Centro Lago fields. These new plays are located along the flanks of the main anticline and are found in Eocene tidal bars in the central and northern areas of the Centro Lago fields.

Anatomical mapping of human herpesvirus reservoirs of infection

Following primary infection, all eight human herpesviruses persist lifelong in the human host. However, a mapping of all anatomic sites of human herpesvirus persistence is lacking. Fresh tissue specimens representing approximately 40 major anatomic sites from eight autopsies were screened using a recently developed real-time PCR method for detection of all eight human herpesviruses. Patients with evidence of active herpesvirus infection (herpes simplex 1 (HSV-1), herpes simplex 2 (HSV-2), varicella-zoster virus (VZV), Epstein–Barr virus (EBV), cytomegalovirus (CMV), herpesvirus 6 (HHV-6), herpesvirus 7 (HHV-7), and herpesvirus 8 (HHV-8)) at the time of death were excluded to avoid detection of widely disseminated infection. Despite this precaution, widespread HSV-1 positivity (with blood positivity) was detected in one case—an elderly male who died of cardiac arrest. In a middle-aged male with HIV-AIDS, HSV-1 was found in neural and pharyngeal tissues, skin, cartilage, bone, and urinary bladder, whereas in two other cases, HSV-1 was restricted to neural tissues. HSV-2 was detected in a single site, the anus, in the male with HIV-AIDS. VZV was detected only twice, once in the adrenal gland and once in the small intestine. CMV was detected in three cases, most commonly in nasal mucosa, trachea, thyroid, intestine, and liver. EBV was detected in all eight cases, especially in nasal mucosa, tonsil, spleen, lymph node, tongue, and intestine, but in only two of six whole-blood specimens. HHV-6, like EBV, was detected in all eight cases, most commonly in salivary glands, thyroid, stomach, intestines, liver, and pancreas. HHV-7, like EBV and HHV-6, was detected in all eight cases, most commonly in salivary glands, tonsil, lymph nodes, and bone marrow. HHV-8 was detected in only two sites (both lymph nodes) from two cases. Herpesviruses were detected in three of six whole-blood specimens, including HSV-1, EBV, HHV-6, and HHV-7. These results represent the most comprehensive mapping of herpesvirus tissue distribution in humans reported to date.

Old Field - New Life

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 94669, "New Life to an Old Field," by J.S. Swanson, SPE, and D.C. Swanson, SPE, Grail Quest Corp.; M. Jarvis, Penn Virginia Oil & Gas Corp.; and R. Hall, SPE, Grail Quest Corp., prepared for the 2005 SPE Hydrocarbon Economics and Evaluation Symposium, Dallas, 3-5 April. The East Tunstill field is a tight, undersaturated sandstone reservoir with a 9% recovery factor on primary depletion. Marginal production and a previous relatively unsuccessful waterflood did not show the potential value of the field. A detailed analysis revived the field. Challenge To increase the value of this field, within a limited budget, new procedures and methods were necessary. A project workflow had to be designed to analyze the field characteristics, taking into account the high number of wells and many years of production, which provided a large amount of useful data. The operator believed that an improved reservoir description applied with simulation methods could yield a better understanding of reservoir drainage, fluid movement, and the volume and location of the remaining oil. Additionally, the operator decided to use a volumetric-balancing technology that enabled quick analysis of various waterflood injection/producer patterns to determine the most economical and efficient flood pattern and, thereby, demonstrated the field's potential. Background The East Tunstill field is in the Delaware basin in Loving County, Texas. Discovered in 1959, cumulative production is estimated at 2.9 million bbl of oil, 8.2 Bcf of gas, and 5.8 million bbl of water. The field produces from the Delaware Olds formation, in the upper Bell Canyon sand series. An improved reservoir-description study with reservoir parameters yielded estimated original oil in place (OOIP) of 30 million bbl. Project Workflow and Methodology The operator initiated the project with two main goals as follows.Confirm existence and volume of remaining recoverable oil and its location.Design a development plan for the most efficient maximum economical oil recovery. Data Preparation The first major step in the workflow was the geologic study, including a detailed stratigraphic analysis as well as a review of the depositional facies on the basis of field-core information. The knowledge of the facies supported the biased mapping of the reservoir, which then determined the controlling characteristics and flow paths of the reservoir fluid. To complete the static reservoir description, basic reservoir parameters were applied to calculate the OOIP. Dynamic Analysis Once the OOIP was determined, the process determines how fluids were drained or produced over time. The fluid movement (involving both production and injection) was tracked in the reservoir over the life of the field by use of volumetric balancing. This method uses the following data sources.Base map with well locations and completion information.Net sand/facies map depicting the remaining reserves recovery.Original-hydrocarbon-in-place maps.Well-production history.Well-injection history.

Mapping and characterization of thin chalk reservoirs using data integration: the Kraka Field, Danish North Sea

The integration of 3D seismic data, well logs and synthetic seismic data has been used to identify an additional Intra Danian seismic horizon in the chalk reservoir of the Kraka Field, Danish North Sea. Mapping of this seismic horizon has allowed production of a separate thickness map for the main reservoir unit, the Danian Porous, in the greater Kraka area. The unit is less than 25 m thick in most areas and, to produce reliable reservoir maps, it has been necessary to use well data to guide the seismic interpretation. It is impossible, however, to resolve the reservoir stratigraphy properly in areas where the Danian Porous is thinner than c. 15 m due to tuning effects. The lateral porosity distribution has been mapped using a combination of well log data and seismic data inverted for acoustic impedance. The Danian Porous unit is characterized by average porosities over 28% and shows no evidence of depth-related porosity reduction. Rather, the impedance data indicate the presence of positive porosity anomalies both over the crest and downflank towards the southeast. Comparison of impedance-derived porosities with those derived from well data indicates that the seismic-based data reflect the variations in porosity but underestimate the highest porosity by 3–4%. Faults and fractures are important for production of the Kraka Field. Detailed mapping of seismic horizons, supplemented with seismic attribute mapping, has proved useful for outlining areas with high fault intensity in the northwestern part of the field but has been unsuccessful in identifying individual faults as recognized from log data.

Gulf of Mexico shelf framework interpretation using a bed-form attribute from spectral imaging

This article introduces a new attribute called SPICE (spectral imaging of correlative events) that calculates a bed-form boundary framework from the seismic data, and highlights detail from subtle changes in the seismic wavelet. The concept of spectral imaging is presented in the context of a well-log model and its relationship to impedance layering. Further validation of the method is provided by a detailed sequence stratigraphy analysis using well logs and seismic data from the northern Gulf of Mexico. The technique, based on wavelet transform decomposition and singularity analysis of migrated seismic data, uses the localization properties of the wavelet transform in time and frequency to produce a unique display that provides a boundary framework of the subsurface that is rich in structural and stratigraphic detail. This advances seismic interpretation closer to the goal of producing accurate geologic mapping of the subsurface. Additionally, this attribute offers a straightforward way to interpret a seismic section similar to a geologist in the field who maps beds and faults directly from the outcrop. Most seismic interpretation today is performed on variable area displays of the seismic amplitude of a wavelet that changes with depth. This has historically posed a number of significant problems for the interpreter. Reflections in seismic data are blurred representations of the actual stratigraphy. The interference of a changing pulse shape with a wide variety of impedance contrasts in the subsurface adds a significant element of uncertainty to the final mapping of reservoir, seal, and trap. The richness and nonstationary character of the seismic trace require a process that localizes rapidly changing features in the spectrum. The unique calculation reduces the uncertainty in picking subtle bed-form boundaries and brings out the full extent of the resolution of the seismic amplitude data. SPICE is computed in the continuous wavelet transform (CWT) domain …

Utilization of seismic attributes for reservoir mapping: A case study from the Cambay Basin, India

Multilayered Hazad sands of Middle Eocene age deposited in a deltaic environment are the main hydrocarbon producers in the south Cambay basin, India. These sands are broadly divided into 12 units (1 to 12) from bottom to top. These individual sand units are further subdivided into smaller subunits which are selectively charged and produce hydrocarbons in different parts of the south Cambay Basin. The study area covers a part of the Gandhar oilfield situated in the Broach-Jambusar block of the basin where subunits 3A and 12A have produced oil and gas in commercial quantities. Due to its widespread deposition and greater thickness, unit 3A was delineated and developed, based on conventional interpretation of 2D seismic data. The development strategy for unit 12A could not be completely resolved in the absence of a precise sand geometry map. A 3D seismic survey was carried out in the study area with one of the objectives being to map the lateral extent of thin pay sands exactly. According to the well data, the thickness of unit 12, consisting of subunits 12A, B and C, varies from 0 to 18 m, and wherever unit 12 is thicker, subunit 12A is present. Unit 12 is not resolved in the available seismic data but its seismic response is detectable. Synthetic seismic modelling has been carried out for a better understanding of the seismic response and for precise calibration. The seismic attributes extracted from the 3D data volume corresponding to unit 12 are utilized to generate a net thickness sand map of this unit using an artificial neural network technique. The sand geometry map of subunit 12A was prepared with the help of a net thickness map of unit 12 and well data. The thickness map of unit 12 helped in mapping the precise sand geometry of unit 12A and also an additional area for cost-effective exploration and development of this pay, which in turn improves the in-place reserves.

Soft computing-based computational intelligent for reservoir characterization

Abstract Reservoir characterization plays a crucial role in modern reservoir management. It helps to make sound reservoir decisions and improves the asset value of the oil and gas companies. It maximizes integration of multi-disciplinary data and knowledge and improves the reliability of the reservoir predictions. The ultimate product is a reservoir model with realistic tolerance for imprecision and uncertainty. Soft computing aims to exploit such a tolerance for solving practical problems. In reservoir characterization, these intelligent techniques can be used for uncertainty analysis, risk assessment, data fusion and data mining which are applicable to feature extraction from seismic attributes, well logging, reservoir mapping and engineering. The main goal is to integrate soft data such as geological data with hard data such as 3D seismic and production data to build a reservoir and stratigraphic model. While some individual methodologies (esp. neurocomputing) have gained much popularity during the past few years, the true benefit of soft computing lies on the integration of its constituent methodologies rather than use in isolation.

The Heather Field, Block 2/5, UK North Sea

abstract The Heather oil field is located in Block 2/5 in the Northern North Sea. Oil is produced from sandstones of the Middle Jurassic Brent Group. at depths between 9500ft and 11600 ft below sea level. The field has been in production for over 20 years, and to date 120 MMSTB of oil have been produced out of an oil-in-place volume of 464 MMSTB. Although approaching non-commercial flow rates, an ambitious programme of field re-evaluation has been conducted since 1997 to identify remaining infill potential, and to investigate the development potential of satellite accumulations. New 3D seismic surveys shot in 1995 and 1997 have been combined to produce a continuous top reservoir map of the main field and adjacent satellite structures. The new mapping and an updated reservoir description were integrated with reservoir simulation models to identify zones of unswept oil. Main field infill projects have been identified which target the unswept oil, allowing extension of field life to be planned in conjunction with satellite field development. An additional 57 MMSTB of recoverable oil are expected to be produced from Middle Jurassic reservoirs in the main field and in satellite areas.

ABSTRACT: New Exploration and Production Opportunities in Colombia: Lessons from Basin-Analyses Studies and a Look Forward

Renewed oil production in the Magdalena Basins, Eastern Cordillera and Llanos Basin of Colombia, largely through reinvigoration of abandoned areas, could result from recognition of untapped play concepts. The new play concepts are the result of integrated mechanical and thermal modeling, geohistory analyses, and palinspastic synthesis of sedimentary facies and thicknesses, which are based on apatite fission track analyses (AFTA), vitrinitereflectance data, and analyses of growth strata and structure displayed in seismic data. These studies show that maturity of Cretaceous source rocks was controlled by unsteady and spatially variable histories of Cretaceous extension and burial under Upper Cretaceous-Cenozoic strata. The Upper Cretaceous-Cenozoic megasequence contains the main sandy reservoirs of Colombia and accumulated during crustal shortening. High synrift-heat-flow persisted until the Coniacian in the deepest Cretaceous marine depocenters. Early phases of oil generation were contemporaneous with Late CretaceousPaleogene formation of compressional structural and stratigraphic traps. The subsurface configurations of these new exploration targets are constrained by Eastern Cordillera stratal growth geometries. Such geometries were produced by progressive rotation of foldlimbs and point to advantages in the application of trishear and inclined-shear theories to exploration of the Eastern Cordillera, an approach not taken in many failed prospects in neighboring basins. The widespread occurrence of growth strata also pertains to enhanced recovery through improved subsurface mapping of synorogenic reservoirs. Such advances mean that new frontiers of Colombian oil industry are also found in the reevaluation of existing oil fields in addition to continued exploration with constrained oilgeneration histories and alternative structural concepts.

Scale Effects on the Application of Saturation-Height Functions to Reservoir Petrofacies Units

Summary An internally self-consistent reservoir model has been constructed to investigate the effects of scale on the numerical form and application of four saturation-height functions and on the resulting predictions of reservoir fluid saturations. The treatment uses reservoir partitioning into strongly characterized, physically distinct lithounits, or petrofacies, for purposes of petrophysical interpretation, and a separate, correlative reservoir zonation for subsequent parameter mapping and volumetrics. The context is therefore that of a deterministic reservoir model. The numerical difference between apetrofacies-specific saturation-height function calibrated at the well-log scale (< 1 m) and the same type of function generated at the reservoir zonal scale (>10 m) varies with the function used and the physical character of the particular petrofacies unit. The application of saturation-height functions established separately at these two different scales has allowed the departures introduced through scale transgression to be assessed quantitatively. This has been done by comparing the predicted zonal hydrocarbon saturations generated for reservoir mapping with benchmark values of the same parameter. For this deterministic approach to reservoir description, an extended algorithm that uses bulk volume water as predictand provides the most accurate evaluation of water saturation at the reservoir zonal scale, which must be used in volumetrics applications. In contrast, an exponential form of the saturation-height function shows relatively large errors at both scales. The significance and variability of scale effects have required the formulation of a structured approach to the optimum application of saturation-height functions in deterministic reservoir description. Through this facility, it is possible to contain the uncertainty associated with the distribution of hydrocarbon saturation at the reservoir mapping and volumetrics stages.

Seismic reservoir mapping from 3‐D AVO in a North Sea turbidite system

We present a methodology for estimating uncertainties and mapping probabilities of occurrence of different lithofacies and pore fluids from seismic amplitudes, and apply it to a North Sea turbidite system. The methodology combines well log facies analysis, statistical rock physics, and prestack seismic inversion. The probability maps can be used as input data in exploration risk assessment and as constraints in reservoir modeling and performance forecasting. First, we define seismic‐scale sedimentary units which we refer to as seismic lithofacies. These facies represent populations of data (clusters) that have characteristic geologic and seismic properties. In the North Sea field presented in this paper, we find that unconsolidated thick‐bedded clean sands with water, plane laminated thick‐bedded sands with oil, and pure shales have very similar acoustic impedance distributions. However, the [Formula: see text] ratio helps resolve these ambiguities. We establish a statistically representative training database by identifying seismic lithofacies from thin sections, cores, and well log data for a type well. This procedure is guided by diagnostic rock physics modeling. Based on the training data, we perform multivariate classification of data from other wells in the area. From the classification results, we can create cumulative distribution functions of seismic properties for each facies. Pore fluid variations are accounted for by applying the Biot‐Gassmann theory. Next, we conduct amplitude‐variation‐with‐offset (AVO) analysis to predict seismic lithofacies from seismic data. We assess uncertainties in AVO responses related to the inherent natural variability of each seismic lithofacies using a Monte Carlo technique. Based on the Monte Carlo simulation, we generate bivariate probability density functions (pdfs) of zero‐offset reflectivity [R(0)] versus AVO gradient (G) for different facies combinations. By combining R(0) and G values estimated from 2‐D and 3‐D seismic data with the bivariate pdfs estimated from well logs, we use both discriminant analysis and Bayesian classification to predict lithofacies and pore fluids from seismic amplitudes. The final results are spatial maps of the most likely facies and pore fluids, and their occurrence probabilities. These maps show that the studied turbidite system is a point‐sourced submarine fan in which thick‐bedded clean sands are present in the feeder‐channel and in the lobe channels, interbedded sands and shales in marginal areas of the system, and shales outside the margins of the turbidite fan. Oil is most likely present in the central lobe channel and in parts of the feeder channel.

Mapping of a magma reservoir beneath Nikko‐Shirane volcano in northern Kanto, Japan, from travel time and seismogram shape anomalies

Since ray paths of direct P and S waves are largely distorted in a magma body, a seismic shadow zone is created. However, scattered or diffracted waves with very small amplitudes can arrive in the shadow zone because their ray paths are different from those of the direct waves. They become the first arrival in the shadow zone. More than 100 seismologists from many institutions in Japan joined together to perform an intensified seismic study in the Nikko‐Ashio area, northern Kanto, Japan. It was suggested that there is a magma body beneath Mount Nikko‐Shirane, an active volcano, that causes a seismic shadow zone, because P waves recorded by the joint observation are anomalously attenuated in cases when they propagate through a zone beneath the eastern part of the volcano. We developed a new method to estimate the shape of the anomalous attenuation zone by proposing the use of a new parameter, the energy ratio between directP or S waves and their coda waves, to discriminate whether or not each observation station is located inside or outside the shadow zone. We estimated the shape of the anomalous attenuation zone by dividing the study area into blocks with dimensions of 2 km × 2 km × 1 km and using the energy ratio data of P waves for local events. The obtained result shows the existence of an anomalous attenuation zone in the area east of Nikko‐Shirane volcano with a diameter of about 10 km at depths greater than 3 km. It was also found from plots of deep event seismograms recorded by the same observation that travel times are delayed by about 0.7 s for ray paths crossing the anomalous attenuation zone obtained by the energy ratio data. This value requires the P wave velocity in the anomalous zone to be less than that of the surrounding crustal material by at least about 30%, suggesting the existence of a huge magma reservoir in this area.

A NEURAL‐NETWORK APPROACH TO KNOWLEDGE‐BASED WELL INTERPOLATION: A CASE STUDY OF A FLUVIAL SANDSTONE RESERVOIR

This paper presents a new approach to well interpolation using interpolation neural networks (INETs). Traditional methods such as geostatistics have been applied to the spatial mapping of reservoirs. However, these methods are not able to make use of qualitative information, such as previously‐constructed “expert knowledge ” in the form of iso‐porosity contours or structural maps of sand body geometry, in a simple manner.This paper demonstrates the usefulness of INET via a case study of a fluvial sandstone reservoir at an oilfield in the Asia Pacific region. The proposed method is applied to porosity interpolation based on data from spatially‐dispersed wells and regional geological knowledge. The results from this study show that an INET is not only able to incorporate expert advice, but also that it is easy to implement in a desktop computer or workstation. This allows an effective transfer of geological knowledge to reservoir modelling.

The Integration of Geochemical, Geological and Engineering Data to Determine Reservoir Continuity in the Iagifu-Hedinia Field, Papua New Guinea  :ABSTRACT

A series of oil and gas fields, including Iagifu-Hedinia, occur along the leading edge of the Papuan fold and thrust belt. Formed during Pliocene to Recent compression, they are structurally complex, and typically broken into multiple reservoir compartments. The presence of the karstic Darai Limestone at the surface over most of the fold belt prevents acquisition of useful seismic data. Reservoir mapping, and establishment of reservoir continuity, is therefore based soley on (1) surface geologic data, (2) drilling data; initially dipmeter and RFT pressure data, and subsequently well production histories, and (3) geochemical correlation of reservoir fluids. During appraisal of the Iagifu-Hedinia discovery, these complimentary data sets demonstrated that (1) a single hydrocarbon column existed above a flowing aquifer in the main block of Iagifu-Hedinia field, (2) a separate acuumulation existed in the Usano area. Geochemical data have suggested the presence of reservoir compartments where other data were missing or inconclusive. Subsequently-acquired production history data have confirmed the geochemically-based interpretations. Geochemical data suggest that oils at Iagifu-Hedinia have a common source. The slight differences in oil composition between reservoirs are likely due to multiple phases of expulsion from the same source rock and/or migration-fractionation.

Geology of the Reservoirs from Interval I of the Oficina Formation, Greater Oficina Area, Eastern Venezuela Basin: ABSTRACT

In order to determine the geologic features of the reservoirs and their areal statistical distribution and geometry, a study was made of a selected interval where the sands present less coalescence and the reservoirs are clearly defined. The study area comprises 1900 km{sup 2} of the Greater Oficina area; core samples, logs and reservoir maps were used. It was found that interval I consists of interbedded sandstones, shales, some siltstone, and occasionally lignites. Based upon lithologic mesoscopic features, eight (8) characteristic lithofacies could be defined. Rocks classified as sub-litharenites, sub-arkoses, arkoses lithic sandstones and graywackes could be inferred as belonging to a fluvio-deltaic system sourced on the Pre-Cambrian Guayana shield. The diagenetic level reached by the sequence corresponds to the intermediate stage, where significant processes of cementation by oxides, carbonates and silica are of equal intensity and magnitude to the lixiviation of feldspars and other detritic particles, giving these rooks good potential reservoir qualities. Descriptive statistical evaluation was performed on 140 reservoirs representing all lithofacies populations in this interval. Based on this analysis reservoirs were statistically grouped in classes which are a function of their geometry, spatial location and type of hydrocarbon content.

Claymore Field, North Sea: Integrated Seismic Stratigraphy, Depositional Models and Reservoir Mapping: ABSTRACT

Delineation and mapping of reservoir compartments within Northern Area Claymore (NAC) has proved difficult to reconcile with reservoir engineering data. An integrated seismic stratigraphy study was undertaken to solve this problem. Four seismic units (I to IV) were identified and mapped from a 3D seismic dataset over NAC within the Valhall Formation, between the Base Cretaceous Unconformity and the near top reservoir seismic event. Time-Isopach maps, seismic facies, log and core data were integrated to infer sediment fairways and depositional models. The latter, plus time isopachs and well data, were then used to provide a framework to generate reservoir maps (gross, net: gross, porosity) for input into the NAC reservoir simulation model and ultimately for optimizing future infill well locations. The successful application of a fully integrated sequence stratigraphy study has led to the following depositional models and produced results that are compatible with the production history of the field. The basal seismic unit (IV) forms a depositional/compactional mound, onto which succeeding seismic units onlap. Seismic facies of units III and II range from mainly mounded, discontinuous to strong, continuous reflections and reflect deposition by debris flows and sheet-gravity flows respectively. Seismic unit I corresponds to two reservoir units, themore » main producing unit over NAC, the F1 and the overlying F0. Seismic facies of unit I range from a weak, discontinuous, mounded peak within F0 sediment fairways to a strong, continuous, mounded peak within F1 depocenters. Multiple episodes of sheet, sediment-gravity flows of the F1 reservoir were followed by channelized sediment-gravity flows of the F0 unit.« less

SUMIC, a new strategic tool for exploration and reservoir mapping

We demonstrate that diffraction stack migration can be used to discover the distribution of near-surface faults. The methodology is based on the assumption that near-surface faults generate detectable back-scattered surface waves from impinging surface waves. We first isolate the back-scattered surface waves by muting or FK filtering, and then migrate them by diffraction migration using the surface wave velocity as the migration velocity. Instead of summing events along trial quasi-hyperbolas, surface wave migration sums events along trial quasi-linear trajectories that correspond to the moveout of back-scattered surface waves. We have also proposed a natural migration method that utilizes the intrinsic traveltime property of the direct and the back-scattered waves at faults. For the synthetic data sets and the land data collected in Aqaba, where surface wave velocity has unexpected perturbations, we migrate the back-scattered surface waves with both predicted velocity profiles and natural Green's function without velocity information. Because the latter approach avoids the need for an accurate velocity model in event summation, both the prestack and stacked migration images show competitive quality. Results with both synthetic data and field records validate the feasibility of this method. We believe applying this method to global or passive seismic data can open new opportunities in unveiling tectonic features.