Non-sealing Faults Research Articles

A New Approach To Evaluate Fault-Sliding Potential With Reservoir Depletion

Summary Fault reactivation caused by reservoir depletion has been an important issue faced by the oil and gas industry. Traditional views suggest that with reservoir depletion, only normal faults can be activated and fault stability either monotonically decreases or increases, which are not consistent with field observations. In this paper, a fault–sliding–potential (FSP) model was developed to analyze fault stability during reservoir depletion for different types of faults. The evolution trend of fault stability with reservoir depletion and the corresponding judging criteria were obtained by calculating the derivatives of FSP. The influences of reservoir depletion on nonsealing and sealing faults were investigated. Case studies were performed to analyze FSP for different types of nonsealing and sealing faults with different fault properties and attitudes. The results show that reverse and strike faults might also be reactivated with reservoir depletion. The fault stability might not monotonically decrease or increase; instead, four evolution patterns of fault stability might occur, with reservoir depletion dependent on the parameters of the faults. Reservoir depletion usually leads to a higher sliding risk for sealing faults than for nonsealing faults. The results also indicate that fault stability is a strong function of fault attitudes, including the dip and strike of the fault.

Potential CO2 and brine leakage through wellbore pathways for geologic CO2 sequestration using the National Risk Assessment Partnership tools: Application to the Big Sky Regional Partnership

Geologic CO2 sequestration (GCS) has received high-level attention from the global scientific community as a response to climate change due to higher concentrations of CO2 in the atmosphere. However, GCS in saline aquifers poses certain risks including CO2/brine leakage through wells or non-sealing faults into groundwater or to the earth’s surface. Understanding crucial reservoir parameters and other geologic features affecting the likelihood of these leakage occurrences will aid the decision-making process regarding GCS operations. In this study, we develop a science-based methodology for quantifying risk profiles at geologic CO2 sequestration sites as part of US DOE’s National Risk Assessment Partnership (NRAP). We apply NRAP tools to a field scale project in a fractured saline aquifer located at Kevin Dome, Montana, which is part of DOE’s Big Sky Carbon Sequestration Partnership project. Risks associated with GCS injection and monitoring are difficult to quantify due to a dearth of data and uncertainties. One solution is running a large number of numerical simulations of the primary CO2 injection reservoir, shallow reservoirs/aquifers, faults, and wells to address leakage risks and uncertainties. However, a full-physics simulation is not computationally feasible because the model is too large and requires fine spatial and temporal discretization to accurately reproduce complex multiphase flow processes. We employ the NRAP Integrated Assessment Model (NRAP-IAM), a hybrid system model developed by the US-DOE for use in performance and quantitative risk assessment of CO2 sequestration. The IAM model requires reduced order models (ROMs) developed from numerical reservoir simulations of a primary CO2 injection reservoir. The ROMs are linked with discrete components of the NRAP-IAM including shallow reservoirs/aquifers and the atmosphere through potential leakage pathways. A powerful stochastic framework allows NRAP-IAM to be used to explore complex interactions among a large number of uncertain variables and to help evaluate the likely performance of potential sequestration sites. Using the NRAP-IAM, we find that the potential amount of CO2 leakage is most sensitive to values of permeability, end-point CO2 relative permeability, hysteresis of CO2 relative permeability, capillary pressure, and permeability of confining rocks. In addition to demonstrating the application of the NRAP risk assessment tools, this work shows that GCS in the Kevin Dome has a higher probability of encountering injectivity limitations during injection of CO2 into the Middle Duperow formation than previous studies have calculated. Finally, we estimate very low risk of CO2 leakage to the atmosphere unless the quality of the legacy well completions is extremely poor.

Dynamic Fault-Seal Breakdown - Investigation in the North Sea Egret Field

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 170584, “Dynamic Fault-Seal-Breakdown Investigation - A Study of Egret Field in the North Sea,” by P.P. Obeahon, SPE, G. Ypma, and O.U. Onyeagoro, SPE, Shell, and A.C. Gringarten, SPE, Imperial College London, prepared for the 2014 SPE Annual Technical Conference and Exhibition, Amsterdam, 27–29 October. The paper has not been peer reviewed. The ability to predict the effect of faults on locating remaining hydrocarbon is critical to optimal well-placement, reservoir-management, and field development decisions. The tools and techniques available for realistic differentiation between sealing and nonsealing faults have presented a great challenge to the industry. This paper discusses the results of an integrated study that incorporated detailed geology and reservoir engineering to understand production behavior of a complexly faulted high-pressure/high-temperature field in the North Sea. Introduction Predicting fault-seal breakdown is a challenging task because it involves many interrelated factors and complex relationships. Knowledge of these factors is both nonunique and subjective. Most faulting processes have been studied in isolation, and the relationships among many of the processes are understood poorly. Reservoir depletion can, in principle, induce stress paths capable of reactivating intrareservoir faults and, hence, potentially cause breakdown of their sealing integrity. Fault-seal breakdown may also be invoked falsely where oil/ water contacts change across a fault (i.e., the fault is a capillary seal) but the fault does not compartmentalize pressures in production. This apparent seal failure can arise because of pressure communication in the water leg below the oil column. It is not clear why pressure depletion should cause capillary-seal failure. However, publications exist that attempt to attribute production behavior observed in fields to fault-seal breakdown in a production realm, because of pressure depletion on one side of a fault. The first attempts to incorporate geologically reasonable fault properties into production-simulation models involved the calculation of transmissibility multiplier on the basis of absolute permeability and thickness of fault rocks. These calculations do not capture the multiphase behaviors of fault rocks. A key problem with this approach is that a huge number of pseudofunctions needs to be calculated to take into account the large variation in fault properties (e.g., thickness, absolute permeability) and flow rates and whether the fault is going through drainage or imbibition during production. The second attempt involved calculating transmissibility multipliers (also known as seal factors) on the basis of fault permeability. The key problem with this approach is that fault permeability depends on shale gouge ratio and fault displacement alone. The calculation does not capture the impact of reservoir permeability on fault permeability.

Gas-Chimney Detection in 3D Seismic by Neural Network

Recognition of hydrocarbon migration is so vital for petroleum exploration. Developing intelligent systems (artificial neural network) enable experts to achieve more details from seismic data. Although detection of migration direction using seismic data is difficult, Chimney-cube analysis overcomes this problem. The authors used several filters, seismic attributes, neural network (supervised and unsupervised), and interpreters' viewpoints. In supervised method artificial and human intelligence cover their limitations and in unsupervised method the authors eliminate the experts' views. Chimney recognizes the migration direction and locates the spill points, mud volcanoes, gas seepages, sealing, and nonsealing faults and finally the origin of hydrocarbon.

Use of fault-seal analysis in understanding petroleum migration in a complexly faulted anticlinal trap, Columbus Basin, offshore Trinidad

In the Columbus Basin, offshore Trinidad, evaluating the controls on fault seal is a prerequisite for understanding how the petroleum fields were charged. In this paper, we present a case study from Mahogany field, where interbedded Pliocene–Pleistocene shales and reservoir sands occur in a broad four-way-closed anticline cut by numerous normal faults. Fault seals in this stratigraphic sequence can be successfully evaluated using shale gouge ratio (SGR), with a transition between sealing and nonsealing faults occurring in the SGR = 0.15–0.25 range. Because of the high net-to-gross ratio of individual sands, low SGR values typically correspond to areas of reservoir self-juxtaposition, whereas good seals (SGR 0.2) exist where different sands are juxtaposed against one another. The larger structural geometry, which changes significantly from the shallow reservoirs to the deeper ones, closely controls the distribution of stacked, fault-sealed petroleum accumulations in this field. Petroleum column heights in individual fault blocks within the structure are limited either by (1) a cross-fault spill point at a low-SGR window on the west side of a fault block or (2) a synclinal spill point within a fault block from which petroleum leaves the overall four-way closure. The pattern of hydrocarbon-water contacts in the field suggests that petroleum filled and spilled its way from northeast to southwest across the structure with individual sands acting as a separate flow systems. Despite juxtaposition against each other, communication between stratigraphically different sands is minimal. Vertical migration of petroleum along faults is not required to explain the distribution of charged sands, and this is consistent with both petrophysical data and the known sealing character of the faults. This petroleum migration model serves as a tool for evaluating charge risk and column heights in untested fault blocks in the area.

Chimney detection and interpretation, revealing sealing qualityof faults, geohazards, charge of and leakage from reservoirs

Understanding the migration of hydrocarbons in the subsurface is of primary importance for oil and gas exploration. Fluid migration structures on reflection seismic data are difficult to map manually and subtle features that are related to hydrocarbon migration are often overlooked. ChimneyCube processing is a new technique in which fluid migration paths are detected in a semi-automated way, using an assemblage of directive, multi-trace seismic attributes, supervised neural networks and the interpreter's insight. Chimney detection results indicate where hydrocarbons originated, how they migrated into a prospect, and how they spilledor leaked from this prospect and created shallow gas pockets, mud volcanoes and pockmarks near and on the seabed. Integration with other geological information is a prerequisite for correct interpretation of the results. Examples show that it provides important information for prospect evaluation, distinguishes between charged and non-charged prospects, detects shallow gas hazards, distinguishes between sealing and non-sealing faults, determines seal quality and helps in the prediction of reservoir hydrocarbon phase in multi-phase basins.

Successful application of time-lapse seismic data in Shell Expro's Gannet Fields, Central North Sea, UKCS

The Central North Sea contains a large variety of oil and gas fields at different stages of maturity within the life cycle of an asset, at varying depths, in varied geology and at widely differing pressure and temperature conditions. Over the last three years Shell UK Exploration and Production (Shell Expro) has acquired new 3D surveys over many of these fields which, following careful attention to detail in acquisition and processing, have been quantitatively compared to pre-production surveys. Differences between these time-lapse seismic datasets have then been interpreted in terms of changes in reservoir fluid movement and changed pressure/temperature conditions. These interpretations have proven useful for reservoir management by identifying swept versus unswept zones, sealing versus non-sealing faults, efficiency of drive mechanisms and connected volumes to specific wells Four case studies from the Gannet Development illustrate how these observations have impacted reservoir management and show how application of this relatively new, yet rapidly maturing technology has had a positive impact on the remaining value of these fields. Importantly, the detectability of changes in the reservoir has been seen to be greater than predicted prior to data acquisition. Indeed, 4D seismic data have become an established part of the long-term plans for all of Shell Expro's subsurface assets. With these successes have come fresh challenges and future efforts will focus on reducing costs in proven 4D technology whilst pushing to introduce new techniques for data gathering and for interpretation of large volumes of new information.

Structure, stratigraphy, and hydrocarbon system of a Pennsylvanian pull-apart basin in north-central Texas

In 1989, a deep test in Cottle County, Texas, discovered an anomalously thick, gas-charged Pennsylvanian (lower Bend Group) clastic section along the Matador arch. Subsequent exploration and development provided data that support the concept that the natural gas fields in Cottle and King counties, north-central Texas, mark the extent of a hydrocarbon system related to the Broken Bone graben, an elongate 180 km2 pull-apart basin in southeastern Cottle County. The graben results from left-step overstepping of left-lateral fault zones and is a component of the Red River-Matador structural trend of the greater Ancestral Rocky Mountains. Arkosic detritus originating from the Amarillo-Wichita uplift was transported southward, over the region containing the graben, toward the Knox-Baylor trough. Episodic graben subsidence accommodated a part of this sediment load as syntectonic, cyclically stacked Bend Group (Atokan, lower Pennsylvanian) fluvial-deltaic to marine deposits. Organic facies within the graben fill are predominantly terrestrially derived (gas prone) and present in sufficient quantity for significant hydrocarbon generation. Lopatin method basin modeling, vitrinite reflectance (Ro) measurements, and Ro-calibrated pyrolysis-derived maturity measures demonstrate that the Bend Group organic facies in the graben have approached peak gas-generating maturation levels. Generated gas migrated within and outside of the basin following nonsealing faults and channelized fluvial pathways into several reservoir rock types in combination structural and stratigraphic traps. (Begin page 2)

Three-dimensional visualization of normal fault segmentation and its implication for fault growth

Segmentation is a fundamental feature for all kinds of faults at different scales. It has a significant impact on hydrocarbon migration and flow for nonsealing faults, and on resevoir fluid estimates and compartmentalization for sealing faults. In spite of these benefits, application of the knowledge of fault segmentation to hydrocarbon exploration and production is limited due to poor seismic data quality, resolution, and lack of understanding of how this knowledge can be applied. Here is a case study from the Niger Delta of a normal fault seen on 3-D where we apply a methodology to visualize fault segments and their slip distribution patterns using seismic and well data.

Fault seal analysis of SE Asian basins with examples from West Java

Abstract A regional fault seal analysis study of SE Asian basins was carried out in order to define trends for predicting sealing faults. Map and well data were analysed and relationships were obtained between fault and reservoir parameters and fault seal. The parameters found to be most useful for discriminating between sealing and non-sealing faults in the region were fault strike, fault mode (oblique slip faults are most likely to be sealing), fault throw (faults with high throws are most likely to be sealing), depth (shallow faults are most likely to be sealing) and thickness-throw. Other parameters measured, some of which are useful for fault seal prediction in some basins, are: fault type (bounding faults, within-field faults, across-field faults), net-to-gross ratio, average reservoir porosity, average reservoir permeability, differences in hydrocarbon contact elevation across faults, hydrocarbon column height held back by sealing faults, and reservoir pressure and temperature. Data from over 150 faults from fields within West Java are presented to illustrate the main results of the analysis.

Impact of Grid Selection on Reservoir Simulation

Summary This paper presents a field case study of a faulted, multilayer carbonate reservoir to quantify the impact of grid selection on the reservoir history match. Comparison of the history match using both orthogonal and nonorthogonal grids revealed that the simple five-point scheme can lead to significant error in the history match and in the different representations of the reservoir. Introduction A simulation study of the Thamama reservoir, a faulted carbonate reservoir in Abu Dhabi, investigated flow communication across faults and evaluated development options for the field. The field is an elongated anticline that covers 62 sq miles. Geophysical and geological data and early reservoir performance indicated that the field was separated into several fault blocks by partially sealing and nonsealing faults. Two full-field simulation models were constructed that used two different approaches to represent faults:an orthogonal (regular) grid model with faults defined at block boundaries anda nonorthogonal (irregular) grid model with block boundaries defined at fault traces. The first approach results in a greater number of cells and presents difficulties in representing the fault geometry properly. However, finite-difference techniques can be used for numerical calculations. The second approach uses fewer gridblocks and provides an accurate description of the fault pattern, but transmissibility calculations could lead to significant errors because the grid is locally distorted. To quantify the impact of grid selection on the reservoir history match, both models were used and the results compared in the simulation study. History matching was performed first with the orthogonal grid model. Then, a history match using the same matching parameters was conducted on the nonorthogonal grid model. Background The Thamama reservoir comprises three zones, Zones A, B, and C. Characterized by high faulting and low permeability, this carbonate reservoir contains about 3.6 billion STB of oil in place (OIP). Zones B and C, which contain about 80% of the total OIP, have been the focus of major development since the field discovery in 1967. Fig. 1 shows the general structural configuration of the reservoir, which consists of a large dome with faults oriented north-west/southeast. Faulting in the field, which partitions the reservoir into numerous small fault blocks, has caused some concern about implementation of the full-field development plan. Although lateral and vertical communication between upthrown and downthrown faulted blocks along major faults was suspected, it was never fully identified. Throughout the field's producing life, the extent of lateral and vertical communication within the reservoir, particularly between the oil zone and the underlying aquifer, has been questioned. This question became acritical operating consideration when a peripheral water injection plan was proposed in the late 1970's. Although an extensive reservoir study was undertaken to predict the field'sfuture producing performance under different waterflood operations, no waterinjection program was implemented. We decided that further detailed reservoir studies should be conducted to understand the communication and crossflow between fault blocks fully before a full-scale injection program could be designed. A preliminary 3D, coarse, full-field simulation study of the Thamama reservoir with an in-house simulator having a rectangular (orthogonal) grid system showed the significant effect of faulting on reservoir performance. Unfortunately, the crossflow and communication levels between the fault blocks could not be determined accurately because the model could not represent the faults properly owing to simulator limitations. Therefore, we decided to use a simulator capable of handling distorted (nonorthogonal) grids, or corner-point geometry, to fit the faults and reservoir boundaries better. Two approaches were considered for constructing the model grid. The first approach uses a rectangular (orthogonal) gridding system that represents faults at block boundaries. As a result, reservoir geology and geometry cannot be represented properly. However, finite-difference techniques can be used in a straight forward manner with good accuracy. The second approach uses a nonrectangular (nonorthogonal) gridding system that accommodates accurate description of the fault pattern by placing block boundaries along fault traces. However, the nonrectangular gridding systems could lead to serious calculation errors.1 We conducted full-field simulation studies using both orthogonal and nonorthogonal grid models. The results of the history match of both models with the same input data were compared to determine the magnitude of the calculation error and differences in model performance.

Attempts to detect open fractures and non-sealing faults with dipmeter logs

Abstract If enough stress-generated breakouts have been identified on four-arm dipmeter logs to map regional horizontal stress trajectories, it may be possible to use anomalous orientations to identify open fractures and non-sealing faults. These act as free surfaces and, if they were oriented obliquely to regional stresses, deflect them locally. This type of analysis is simple to apply and appears to offer a novel way to obtain key information required for optimizing the production of oil and gas. In offshore eastern Canada, the regional stress regime is well established and local deflections appear to be caused by near-by open fractures and non-sealing faults. In the Aquitaine Basin in France the regional stress signature is not homogeneous. Though some anomalous orientations appear to be caused by open fractures and faults, it is clear that many are not. Hence the method may not be applicable everywhere. Possible reasons include differences in the σ H :σ h ratios of the two areas and the geotectonic settings.

Sealing and Nonsealing Faults in Louisiana Gulf Coast Salt Basin

Fault-controlled accumulations in the hydropressured Tertiary section were studied in 10 Louisiana Gulf Coast salt basin fields located on low-relief structures. Investigations were limited to traps associated with faults which restrict vertical migration of hydrocarbons; that is, where an accumulation is in contact with the fault. The fault-lithology-accumulation relations observed are (1) fault sealing, with hydrocarbon-bearing sandstone in lateral juxtaposition with shale; (2) fault nonsealing to lateral migration, with parts of the same sandstone body juxtaposed within the hydrocarbon column; (3) fault nonsealing to lateral migration, with sandstone bodies of different ages juxtaposed within the hydrocarbon column; and (4) fault sealing, with sandstone bodies of diffe ent ages juxtaposed within the hydrocarbon column. In some places, these four relations are present at different levels along the same fault. In the examples studied, only faults nonsealing to lateral migration were observed where parts of the same sandstone body are juxtaposed across a fault. With sandstone bodies of different ages juxtaposed, some faults are sealing and others are nonsealing to lateral migration, but sealing faults are the most common. The fault seal apparently results from the presence of boundary fault-zone material emplaced along the fault by mechanical or chemical processes related directly or indirectly to faulting.

Sealing and Nonsealing Faults in Gulf Coast Salt Basin: ABSTRACT

This study was undertaken to investigate (1) the different End_Page 529------------------------------ situations of fault entrapment of hydrocarbons in Tertiary sediments of the Gulf Coast salt basin, and (2) the role of juxtaposed sediments in a sandstone-shale sequence in creating sealing and nonsealing faults. Fault-controlled accumulations in the hydropressured Tertiary section were studied in 10 Gulf Coast fields located on low relief structures. Investigations were limited to traps associated with faults which restrict vertical migration of hydrocarbons, that is, where an accumulation is in contact with the fault. The relations observed among fault, lithology, and accumulation are (1) fault sealing, with hydrocarbon-bearing sandstone in lateral juxtaposition with shale; (2) fault nonsealing to lateral migration, with parts of the same sandstone body juxtaposed within the hydrocarbon column; (3) fault nonsealing to lateral migration, with sandstone bodies of different ages juxtaposed within the hydrocarbon column; and (4) fault sealing, with sandstone bodies of different ages juxtaposed w thin the hydrocarbon column. In some places these four relations are present at different levels along the same fault. In the examples studied, faults nonsealing to lateral migration were observed only where parts of the same sandstone body are juxtaposed across a fault. With sandstone bodies of different ages juxtaposed, some faults are sealing and others are nonsealing to lateral migration, but sealing faults are the most common. The fault seal apparently results from the presence of boundary fault-zone material emplaced along the fault by mechanical or chemical processes related directly or indirectly to faulting. End_of_Article - Last_Page 530------------

Theoretical Considerations of Sealing and Non-Sealing Faults

Differentiating between sealing and non-sealing faults and their effects on the subsurface is a major problem in petroleum exploration, development, and production. The fault-seal problem has been investigated from a theoretical viewpoint in order to provide a basis for a better understanding of sealing and non-sealing faults. Some general theories of hydrocarbon entrapment are reviewed and related directly to hypothetical cases of faults as barriers to hydrocarbon migration and faults as paths for hydrocarbon migration. The phenomenon of fault entrapment reduces to a relation between (1) capillary pressure and (2) the displacement pressure of the reservoir rock and the boundary rock material along the fault. Capillary pressure is the differential pressure between the hyd ocarbons and the water at any level in the reservoir; displacement pressure is the pressure required to force hydrocarbons into the largest interconnected pores of a preferentially water-wet rock. Thus the sealing or non-sealing aspect of a fault can be characterized by pressure differentials and by rock capillary properties. Theoretical studies show that the fault seal in preferentially water-wet rock is related to the displacement pressure of the media in contact at the fault. Media of similar displacement pressure will result in a non-sealing fault to hydrocarbon migration. Media of different displacement pressure will result in a sealing fault, provided the capillary pressure is less than the boundary displacement pressure. The trapping capacity of a boundary, in terms of the thickness of hydrocarbon column, is related to the magnitude of the difference in displacement pressures of the reservoir and boundary rock. If the thickness of the hydrocarbon column exceeds the boundary trapping capacity, the excess hydrocarbons will be displaced into the boundary material. Dependent on the conditions, lateral m gration across faults or vertical migration along faults will occur when the boundary trapping capacity is exceeded. Application of the theoretical concepts to subsurface studies should prove useful in understanding and in evaluating subsurface fault seals.

Sealing and Non-Sealing Faults: ABSTRACT

Differentiating between sealing and non-sealing faults and their effects in the subsurface is a major problem in petroleum exploration, development, and production. The fault-seal problem has been investigated from a theoretical viewpoint in order to provide a basis for a better understanding of sealing and non-sealing faults. Some general theories of hydrocarbon entrapment are reviewed and directly related to hypothetical cases of faults as barriers to hydrocarbon migration and faults as paths for hydrocarbon migration. The phenomenon of fault entrapment reduces to a relationship between (1) the capillary pressure and (2) the displacement pressure of the reservoir rock and the boundary rock material along the fault. Capillary pressure is the differential pressure between the hydrocarbons and the water at any level in the reservoir; displacement pressure is the pressure required to force hydrocarbons into the largest interconnected pores of a preferentially water-wet rock. Thus the sealing or non-sealing aspect of a fault can be characterized by pressure differentials and by rock-capillary properties. Theoretical studies show that the fault seal in preferentially water-wet rock is related to the displacement pressure of the media in contact at the fault. Media of similar displacement pressure will result in a non-sealing fault to hydrocarbon migration. Media of different displacement pressure will result in a sealing fault, provided the capillary pressure in the reservoir rock is less than the opposing boundary displacement pressure. The trapping capacity of a boundary, in terms of the thickness of hydrocarbon column, is related to the magnitude of the difference in displacement pressures of the reservoir and boundary rock. If the thickness of the hydrocarbon column exceeds the boundary trapping capacity, the excess hydrocarbons will be displaced into the boundary material. Depende t on the conditions, lateral migration across faults or vertical migration along faults will occur when the boundary trapping capacity is exceeded. Application of the theoretical concepts to subsurface studies should prove useful in understanding and in evaluating subsurface fault seals. End_of_Article - Last_Page 1749------------

Applying the Frontal Advance Equation to Vertical Segregation Reservoirs

Joslin, W.J., Member AIME, Creole Petroleum Corp., Caracas, Venezuela Abstract The frontal-advance equation can determine how the fluid withdrawal rate and subsurface operating pressure influence oil recovery from pressure-maintained reservoirs having characteristics favorable for efficient vertical segregation. For effective vertical segregation in formations having low dip angles, the requirements are: thick, massive sands, low viscosity oil and high vertical permeability with few discontinuous shale members. This approach has been successfully applied to the LL-370, which is a massive Eocene sandstone reservoir containing crude with an average gravity of 260 API, a dip of only 30 and vertical permeability of 1/2 darcy. The average gas cap saturation was calculated for various rates of vertical gas-oil contact movement corresponding to a wide range of reservoir producing rates. This method also evaluated the effect of different pressure maintenance levels on oil recovery. Applicability of this procedure for calculating the present oil saturation in the LL-370 gas cap has been substantiated from field performance, where the oil saturation was computed by comparing oil recovery with the gas cap volume vacated. Introduction During the natural depletion history of the LL-370 reservoir, located in Lake Maracaibo, Venezuela, excellent vertical segregation resulted in the formation of a thin gas zone over a substantial portion of the oil-productive area. Subsequently, gas injection forced this thin gas-saturated zone slowly downward, reducing the oil saturation in the gas cap to a low value. The oil recovery has been raised considerably above earlier predictions where vertical segregation effects were under-estimated. In order to determine the maximum efficient producing rate and optimum operating pressure for this reservoir, a vertical gas frontal-advance analysis has been made through application of the fractional flow equation. LL-370 RESERVOIR CHARACTERISTICS The reservoir consists of a truncated monocline of massive, highly-permeable Eocene sandstone, called the B-6 formation, covering an area of more than 13,500 acres. The original oil in place was 2.17 billion STB. Internal non-sealing faults subdivide the structure into four blocks called the B-6-x.6, 10, 11 and 13, which are effectively bounded by major faulting on the flanks, an unconformity updip to the west, and an immobile aquifer to the southeast. The producing formation occurs at an average depth of 5,250 ft subsea and has a closure of more than 1,500 ft. A typical producing section has a net oil sand thickness of 170 ft. Scattered throughout the section are a few randomly-positioned shale lenses which increase in thickness and areal extent downdip. The reservoir rock and fluid properties vary with depth. The permeability and produced oil gravity are 1600 md and 280 API at the top, compared to 300 md and 18 API at the water-oil contact. The productivity of updip wells is, therefore, much higher than the reservoir average. The reservoir oil was originally saturated at the crest, grading to a slight degree of undersaturation at the water-oil contact. There was no original gas cap; and material balance and the field performance indicate no water influx. Except for the northern B-6-x.6 block, the fluid and rock properties have already been published. Average LL-370 reservoir properties are shown in Table l. RESERVOIR PERFORMANCE UNDER NATURAL DEPLETION Fig. 1 shows production performance from 1939 to date. TABLE 1-LL-370 RESERVOIR PROPERTIES Permeability (air) from cores, horizontal 975 mdPorosity 20.4 per centGravity 26.1 APIFormation volume factor, original 1.278Connate water saturation 12.4 per centSolution GOR, original 492 cu ft/bblOil viscosity, original 1.8 cpFormation dip 3Original pressure (-5250 ft subsea) 2490 psicSection thickness 198 ftNet oil sand thickness 148 ft JPT P. 87ˆ