Early Water Breakthrough Research Articles

Colloidal-Dispersion Gel in a Heterogeneous Reservoir in Argentina

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 174704, “CDG in a Heterogeneous Fluvial Reservoir in Argentina: Pilot and Field-Expansion Evaluation,” by D. Diaz and N. Saez, YPF; M. Cabrera, InLab; E. Manrique, Consultant; and J. Romero, M. Kazempour, and N. Aye, Tiorco, prepared for the 2015 SPE Enhanced Oil Recovery Conference, Kuala Lumpur, 11–13 August. The paper has not been peer reviewed. The Loma Alta Sur (LAS) field is a multilayer fluvial sandstone reservoir in the Neuquén basin of Argentina. Reservoir heterogeneities and an adverse mobility ratio (30-cp oil) led to an early water breakthrough soon after water injection started. Colloidal-dispersion- gel (CDG) injection was considered a viable strategy to improve oil recovery in the field. LAS-58 CDG Pilot Summary The CDG pilot was implemented in the LAS-58 injector located on the northeastern side of the field. LAS-58 is an irregular pattern that began water injection in 2002, showing an early water breakthrough. The operator estimates that after 3 years of water injection in the LAS-58 pattern, cumulative secondary oil recovery is only 5.48% of original oil in place (OOIP). The LAS-58 pattern includes 10 producers: six first-line producers with well spacing ranging from 138 to 164 m and four second-line producers. The first tracer-injection program was implemented in March of 2003, 3 months after initial water injection in the LAS-58 injector. The fastest tracer breakthrough was observed in offset producer LAS-18 (50 days). However, the amount of tracer recovered in LAS-18 and LAS-26 was below 1.5% of the total injected. Producer LAS-49 showed the second-fastest breakthrough but with a cumulative tracer recovery of 4%. Each of the CDG-injection phases was followed by water injection at similar injection rates. The total volume of CDG injected (62 179 m3) represented 3.06% of the pore volume of the LAS-58 pilot area. Phase I consisted of a small injection volume intended to test CDG injectivity and did not affect pilot oil-production response but definitively contributed to adjusting the polymer concentration used in the pilot through Phases II and III of CDG injection. The main observation after Phase II of CDG injection was a very distinctive change in the injection profile of the LAS-58 injector. The water-injection flow paths were diverted into the middle (Mandrel 2) and bottom (Mandrel 1) zones of the pay zone because of the reduction in injectivity in the thief zones located at the top (Mandrel 3) of the reservoir. In October 2007, the incremental oil production for the 10 offset producers was reported as 133,292 bbl, with a reduction in water production of 406,949 bbl.

Application and Study on Relationship Between Relative Permeability Ratio and Water Saturation Curve

In the process of oil field development, the law of water cut is usually described by exponent model, but during the early water breakthrough stage and ultra-high water cut stage, relative permeability ratio of oil to water (<i>K_ro/K_rw</i>) and water saturation (<i>S_w</i>) is no longer linear relations in semilog coordinate, so it has an important influence on water cut increasing rate, theoretical production index, oil displacement efficiency, relationship between recovery and water cut etc. Based on relation curve character of relative permeability ratio of oil to water (<i>K_ro/K_rw</i>) and water saturation (<i>S_w</i>), this paper proposes a new function model in order to reduce prediction error, such as production index and water cut increasing rate. According to nonlinear properties of the model, Newton algorithm is supposed to be used for optimization solution. Finally, take relative permeability data of P Oilfield as an example to testify, and results show that fitting precision of the model is quite high and it possess nicer applicability. On this basis, the relationship between water cut and recovery, relationship between water cut increasing rate and recovery are derived. By comparing water cut and water cut increasing rate with recovery degree, it can be used to guide the development as the foundation of geology and reservoir of P Oilfield.

Sweep enhancers for oil recovery

The use of viscoelastic sweep improvers to overcome injected fluid diversion is assessed at the low pressure gradients associated with secondary oil production. The flow evolves from Newtonian to non-Newtonian behavior with increasing pressure gradient. Additive concentration determines this transition and controls the effectiveness of selective retardation. This is demonstrated in an experimental simulation of parallel flow in two core samples of different permeabilities. Even at pressure gradients lower than 1.0 bar/m channeling can effectively be reduced and early water breakthrough delayed. This has the potential to greatly increase ultimate oil recovery.

Assisted History Matching for Fractured Reservoirs by Use of Hough-Transform-Based Parameterization

Summary Successful production in fractured reservoirs is significantly dependent on knowledge of the location, orientation, and conductivity of the fractures. Early water breakthrough can be prevented and sweep efficiency can be improved with the help of comprehensive and accurate information of fracture distributions. However, it is a challenge to estimate fracture distributions by conventional-history-matching methods because of the complexity of such reservoirs. Although there has been great progress in assisted-history-matching techniques during the last 2 decades, estimating fracture distributions in fractured reservoirs is still inefficient because of the strong heterogeneity and spatial discontinuity of model parameters. The performance of assisted-history-matching methods, such as the ensemble Kalman filter, can be significantly degraded by the non-Gaussian distributions of the parameters, such as effective permeability and porosity. On the other hand, although the geometric shapes of fractures may be generated properly at the initial step, they are difficult to preserve after updating, which results in geologically unrealistic fracture-distribution maps. In this study, we develop an assisted-history-matching method for fractured reservoirs with a Hough-transform-based parameterization. The facies maps of fractured reservoirs are parameterized into Hough-function fields in a discrete Hough space, whereas each gridblock in the Hough domain represents a fracture defined by its two Cartesian coordinates: angle θ of its normal and ρ of its algebraic distance from the origin in the flow domain. The length and axial position of the fractures are defined by two additional parameters on the same grid. The Hough-function value of each gridblock in the Hough domain is used as the indicator of the existence of the fracture in the facies map. When this parameterization is implemented in assisted history matching, the parameter fields in the Hough space, instead of the facies maps, are updated conditional on the production history. An inverse transform is performed to generate facies maps for the reservoir simulator. Pointwise prior information, such as known fractures discovered from well-log data, as well as the statistics of fracture orientation, can be honored by the inverse transform throughout the history-matching process. Applications and the effectiveness of this method are demonstrated by 2D synthetic-waterflooding examples. The fracture distributions in reference fields are identified by this method, and updated models are capable of providing improved predictions for prolonged periods of production.

New Technologies Maximize Production in Viscous-Oil North Slope Field

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 171896, “The Use of New Technologies To Maximize Oil Production in a Viscous-Oil Field in Arctic Environment: The Nikaitchuq Experience,” by S. Raniolo, SPE, S. Mancini, and S. Vimercati, Eni E&amp;P; and P. Gentil, D. Simeone, SPE, and A. Buchanan, Eni Petroleum, prepared for the 2014 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 10–13 November. The paper has not been peer reviewed. Oil quality and drilling-pad constraints for a viscous-oil field defined a development scheme that consisted of a waterflood line drive with horizontal producers and water-injection (WINJ) wells side by side. Different well designs for producer wells were implemented: a single horizontal trajectory undulating between the two sand bodies in counterphase with the related water injectors, a fishbone design with the main borehole in the lower sand and multiple branches in the upper sand, and a multilateral (ML) counterphase design with extended-reach undulating dual laterals. As a result of the ML campaign, well productivity doubled. Introduction The field is located on the North Slope of Alaska in the Beaufort Sea in water depth less than 20 ft. The reservoir consists of four zones hydraulically communicating, named OA1, OA2, OA3, and OA4. The differentiation is mainly sedimentological; OA1 and OA3 are associated with a more-proximal depositional system, while OA2 and OA4 are characterized by a predominance of thin laminated silty sandstones because of a more-distal depositional system. The crude quality and drill-pad constraints (one offshore, one onshore) drove a development concept that consisted of a waterflood line drive with alternating horizontal producers and WINJ wells with a 1,200-ft spacing. The lateral sections are 6,000–10,000 ft long through the reservoir with undulating counterphase trajectories across the two main sand bodies. Challenging very-extended- reach wells with a stepout ratio higher than 6 have been achieved (Fig. 1). The undulating counterphase well trajectories were selected for producers and injectors to guarantee optimal pressure support and avoid early water breakthrough. The original design was based on predrilling assumptions; however, the reservoir was revealed to be more homogeneous than expected, with good petrophysical properties. These conditions led to the evaluation of ML concepts, with an expected low impact on water-cut trends and water breakthrough. With the goal of increasing reservoir contact, the ML concept consisting of undulating counterphase dual laterals was tested in August 2013. The producer was modified to an undulating counterphase dual lateral throughout the two main sands. The injector maintained the original well concept in counterphase with the original producer mainbore. As a result, well production doubled with respect to the average before the intervention. In parallel, key development wells were identified for data acquisition and appraisal activities that have resulted in derisking stepout opportunities as well as assessing the potential of challenging resources, such as the peripheral areas.

Determining the levels and parameters of thief zone based on automatic history matching and fuzzy method

Abstract Thief zone which evolves from long-term water flooding, has become a subject of concern for reservoir engineers, as they lead to early water breakthrough in oil producers and uneven sweep around water injectors, thus it is essential to select wells which need to be modified injection or production profiles. This article presents a methodology of determining the levels and parameters of thief zone in different areas of the reservoir on the concept of “based on the information from every grid of reservoir model” by using automatic history matching and fuzzy method. Since characterizing the reservoir uncertainty is crucial to the reservoir description and future performance predictions, automatic history matching using ensemble Kalman filter (EnKF) with covariance localization is first proposed. Then according to theory of logical analysis (TLA), fuzzy analytic hierarchy process (FAHP) and Fuzzy comprehensive evaluation (FCE) method, the system to quantitative evaluation of thief zone is presented, and the reservoir can be graded into three categories of severe thief zone, light thief zone and no thief zone. The methodology has been applied to X oilfield in western North China which has 17 layers from the top to the bottom in the stratigraphy, and the results show that 5 layers exist severe thief zones and the volume of severe thief zones is the largest in layer 32, and there are four wells in this layer that their injection or production profiles must be modified. In addition, the interwell tracer test result shows the proposed methodology is more accurate by comparing with other methods in the references which mainly rely on the properties of single well to determine the levels of thief zone. The proposed approach is more accurate and less manpower needs to identify thief zones, which also providing a strong basis for oilfield development adjustment in high water cut stage.

Potential applications of time-lapse CSEM to reservoir monitoring

Monitoring of changes in brine chemistry (salinity and temperature), during water-flooding is important for injector optimisation, understanding efficiency, detecting early water breakthrough, locating bypassed hydrocarbons or detecting scaling in the heterogeneous reservoir. It is already known that water injection into the oil-leg of a hydrocarbon reservoir can be monitored by both seismic acquisition and also CSEM methods. The problem of an interfering pressure signal for seismic impacts quantitative evaluation for time-lapse analysis, while with EM there are the counterbalancing effects of salinity and temperature. CSEM becomes favoured when the pressure effects on seismic are dominant, or heavy oil is present with similar acoustic properties as the formation and injected waters. The quality of measurement for both methods is influenced by reservoir facies variations, acquisition repeatability and overburden heterogeneity. Time-lapse seismic is unlikely to detect brine distributions injected into the water-leg or aquifer, although it may detect associated pressure up effects. However, our calculations show that it may be possible for time-lapse CSEM to distinguish the inter-mixing of different brines in the subsurface hydrocarbon reservoir. Specifically, low salinity injection or injection into a highly saline formation can clearly be detected with this technique.

Residual oil distribution characteristic of fractured-cavity carbonate reservoir after water flooding and enhanced oil recovery by N2 flooding of fractured-cavity carbonate reservoir

The 4th block Ordovician fractured-cavity carbonate reservoir of Tahe oil-field consists of high-density fractures and large caves which are well developed. The oil is stored in fractures and caves, rather than carbonate rock matrix. In other words, the carbonate rock matrix has no oil storage capability and permeability is extremely low. The fractured-cavity carbonate reservoir possesses the features of severe heterogeneity, complex structure of reservoir space. During the development, many shortcomings such as short period of stable production, early water breakthrough, fast increasing of water cut, high natural decline rate and low degree of development are exposed gradually. The well which cannot achieve effectiveness by water injection was selected to carry out N2 flooding experiments in Tahe oil-field. By the end of September 2012, the total injection volume of high pressure N2 was 700 m3 and the incremental oil production was 2600 t. However the displacement mechanism was still poorly understood. In this paper, a two-dimensional visual fractured-cavity carbonate reservoir model was developed based on the distribution feature, space structure and connection type of fractures and caves in reservoir space. Four main types of residual oil i.e., attic oil, locked oil, bypassed oil and residual oil trapped in the filled area were determined from the water flooding experiments. Also, their formation mechanism was investigated. In addition, the recovering mechanism of residual oil was clarified on the basis of N2 flooding experiments. The results show that N2 flooding can significantly increase the oil recovery by more than 40% after water flooding, and it mainly mobilized attic oil and partial locked oil. The entire experiment process was recorded by video, therefore the displacing process of residual oil can be observed directly. These results in this study indicate that N2 flooding has a broad application prospect in fractured-cavity carbonate reservoir.

Sedimentological evolution of Sele Formation deep-marine depositional systems of the Central North Sea

Abstract The Paleocene–Eocene-aged Sele Formation is developed across the basinal region of the Central North Sea. The section comprises a number of deep-marine fan systems that expanded and contracted across the basin floor in response to relative sea-level changes on the basin margin and fluctuating sediment yield off the Scottish landmass modulated by climate and hinterland uplift. Persistent sediment entry points to the basin resulted in the development of discrete axial and transverse fan fairways with a geometry dictated by an irregular bathymetry sculpted by differential compaction across Mesozoic faults, halokinesis and antecedent fan systems. A high-resolution biostratigraphic framework has allowed the evolution of fan-dispersal systems in response to these effects to be tracked across the basin within four genetic sequences. The proximal parts of the fans comprised channel complexes of low sinuosity, high lateral offset, and low aggradation. The development of these systems in a bathymetrically confined corridor of the Central Graben ( c. 65 km wide), combined with high sediment supply, resulted in the eventual burial of any underlying relief. The behaviour of sand-rich reservoirs in this region is dominated by the permeability contrast between high-quality channel fairways and more heterolithic overbank regions, with the potential for early water breakthrough and aquifer coning in the channel fairways, and unswept volumes in overbank locations. Compartmentalization of compensationally stacked channel bodies occurs locally, with stratigraphic trapping caused by lateral channel pinch-outs, channel-base debrites, mud-rich drapes and abandonment fines. Towards the southern part of Quadrant 22, approximately 150 km down-palaeoflow, the systems became less confined and in this region are dominated by channel–lobe complexes, which continued to interact with an irregular bathymetry controlled by antecedent fans, mass-transport complexes and halokinesis in the form of rising salt diapirs. Reservoirs in this region are inherently stratigraphically compartmentalized by their heterolithic lithology and compensational stacking of lobes, and further complicated by structuration and instability induced by the diapiric or basement structures needed to generate a trapping structure in these settings.

A New Completion Methodology to Improve Oil Recovery for Horizontal Wells Completed in Highly Heterogeneous Reservoirs

The specific inflow distribution along the horizontal wellbore is significantly uneven in highly heterogeneous reservoirs. Such uneven influx is recognized as the cause of early water breakthrough, poor oil sweep efficiency and low ultimate recovery. Interval control valves (ICVs) are practical completion hardwares that can actively equalize the contributions from all controlled zones. However, the wellhead penetration limitation impedes ICVs’ application in highly heterogeneous reservoirs, which require many control intervals. This paper proposes a new completion methodology that combines ICVs and variable-density perforations (ICVs + VDP) to eliminate the limitation of ICVs applied in highly heterogeneous reservoirs. The ICVs + VDP completion can achieve more subtle controls because VDP is capable of reducing the inflow difference in each subzone. A steady-state modeling approach and a transient-state modeling approach are used to evaluate the effect of the ICVs + VDP completion on inflow equalization and well performance optimization. The observations from case study show that horizontal wells with the ICVs + VDP completion can considerably delay water breakthrough, improve oil recovery, and reduce water production in highly heterogeneous reservoirs.

Enhanced Sand-Control System Successfully Treats Six Zones in Offshore Indonesia Well

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 24879, ’Enhanced Multizone Single-Trip Sand-Control System Successfully Treats Six Zones in Offshore Indonesia Well,’ by Leon Zhou and Indra Gunawan, ConocoPhillips, and Ricki Jannise, Casey Suire, and Tyson Eiman, Halliburton, prepared for the 2014 Offshore Technology Conference Asia, Kuala Lumpur, 25-28 March. The paper has not been peer reviewed. Although multiple-zone, downhole sand-control-tool systems have been in use since the early 1990s, these systems have been designed for jobs that require only low pump rates with low pressure differentials. Multiple-zone systems capable of high fracturing pump rates and the associated differentials only recently have been introduced to the oil field, but most of these completions have been limited to four or five treated zones. This paper presents a case history from Indonesia in which six discrete zones in an offshore deployment were treated successfully in a single trip. Field History The Bawal field is located in Block B, 1000 km north of Jakarta, in the South China Sea. The average water depth across the field is 280 ft. The Bawal field was discovered in 1979; the field is approximately 5 km long and 2 km wide. The Bawal reservoirs consist of subangular-to- rounded, well-sorted silt to extremely fine quartz sand. The initial development concept was to drill and complete two to three subsea wells and tie them back to a nearby production facility, Hangtuah, 43 km away. The first-gas-production target was 2012. The reservoirs all require sand control, varying degrees of stimulation, high-rate water packing at rates of 8 to 20 bbl/min, and fracture treatments at rates of 22 to 35 bbl/min. The operator has completed multiple fields with two dominant completion methods: openhole standalone screen (OHSAS) and cased-hole frac pack (CHFP). The OHSAS completions typically are installed in horizontal wells or very-high-angle wells. The OHSAS requires special reservoir-drill-in fluid with calcium carbonate to drill the reservoir section, run the premium screen, wash the pipe, and conduct mudcake cleanout. Typically, a CHFP is conducted with tubing- conveyed perforation and alternative- flow-path sand screen being run in one trip; then, a frac pack is pumped with viscoelastic fracturing fluid. Historically, the operator has completed subsea wells with downhole sand control using the OHSAS method for single- zone completions and singletrip frac-pack/high-rate water packs for multizone commingled production. For frac-pack completions, the completion system used previously was capable of treating only up to three zones; therefore, the treatment rate per zone became lower, and there was always an issue with slurry distribution. If more than two to three zones were required per well, a stacked frac-pack completion was implemented. Completing these wells with conventional stacked sand-control methods meant spending many rig days tripping pipe in and out of each well. The single-trip multizone methods previously used in the area typically would provide only a limited pump rate of up to 10 bbl/min per zone and pressure ratings of 6,000 psi. For the new wells, the fracture treatments would require a more-robust system that would include a pressure rating of 10,000 psi because of sandout conditions. Another challenge was that commingling these zones into one well has historically resulted in 50% less recovery compared with single-zone completions. Early water breakthrough coming in from one of the zones would cause the well to load up and die. Therefore, the operator also wanted to include installation of an intelligent-completion system that would allow zonal isolation without intervention, to optimize reserves recovery. The multizone frac-pack completion not only would have to be capable of completing up to six zones in one run but also would have to be compatible with the planned intelligent-system equipment.

Optimizing production from water drive gas reservoirs based on desirability concept

There are various factors which determine the optimization and economic production from water drive gas reservoirs. These factors play an important role in designing an effective reservoir development plan. The present study, in the first step, investigates the relation between recovery factor, volumetric sweep efficiency and cumulative water production with six different engineering and geologic factors using design of experiments (DOE) and response surface methodology (RSM). Next, all derived response functions are optimized simultaneously based on the concept of desirability. In this manner, part of water drive gas reservoirs is simulated using Box–Behnken design. Important factors that have been studied include reservoir horizontal permeability (Kh), permeability anisotropy (Kv/Kh), aquifer size (Vaq), gas production rate (Qg), perforated thickness (Hp) and tubing head pressure (THP). The results indicate that by combining various levels of factors and considering relative importance of each response function, optimized conditions could be raised in order to maximizing recovery factor, volumetric sweep efficiency and minimizing cumulative water production. Also high rates of gas production result poor volumetric sweep efficiency and early water breakthrough, hence ultimate recovery factor decreases by 3.2–8.4%.

The Applicability of Inverse Water-in-oil Emulsion as a Selective Plugging Agent

The presence of homogeneous porous media allows a uniform sweep during a waterflooding process, but it is very rare to find homogeneous reservoirs. The typical heterogeneous character of most formations causes an uneven production from different permeability sands in the reservoir. The preferential movement of the injected water to zones with less resistance to flow causes earlier water breakthrough time than if the formation was homogeneous. This phenomenon will exacerbate at offshore reservoirs and the wells with water production potential. To suggest a solution to this problem, the use of emulsions as a mobility control and selective plugging agent has been studied here. Three different W/O emulsion formulations were injected into high-permeable heavy oil saturated waterflooded sandpacks and the one with the best recovery factor was injected to sandpacks with different permeabilities. The change in oil recovery pattern is considered as the main aim of this work. Experiment results revealed that invert W/O emulsions with high viscosities could act as a selective plugging agent and help the displacement process.

Enhancing volumetric sweep efficiency in waterfloods using in-situ non-conductive barrier fractures

Abstract For long, early water breakthrough has been a major concern for the operators during the life of a waterflood. Early breakthroughs can result in large quantities of produced water and consequently increase the overall cost per barrel of produced oil. In more severe cases, this can result in premature shut-in of wells. The oil and gas industry has developed a host of technologies to improve the sweep efficiency of waterfloods. These methods include the use of certain injection/production patterns, drilling horizontal and deviated wells, use of special chemicals as well as inflow control devices (ICDs). The purpose of the first two methods is to create an even movement of injection fluid across the reservoir. Special chemicals have been used to divert the injected fluid to eliminate channeling and to improve sweep efficiency. Inflow control devices have been used to delay water or gas breakthrough, making possible a more efficient drainage of the reservoir while maximizing recovery. The technique presented in this work involves creating a physical barrier to flow by introducing a fracture to the formation at a strategic location. his fracture is then filled with a conformance fluid and eventually becomes impermeable. The effectiveness of the proposed technique in increasing the recovery of waterfloods was investigated. A sensitivity analysis was then performed on the effects of various factors on the performance of the proposed technique. It is shown that implementing the proposed method can improve ultimate oil recovery mainly by delaying the breakthrough.

Dynamic tracking model for the reservoir water flooding of a separated layer water injection based on a well temperature log

A dynamic tracking model for the reservoir water flooding of a separated layer water injection was established. Based on the basic principles of heat and mass transfer, the water profile was determined using a well temperature curve. The Poisson process analysis and stochastic process methods were applied to calculate the water saturation, water breakthrough time, and water cut of each layer in a water-flooded reservoir at any given time. When the oil reservoir was producing water, the water cut predicted by the models, with consideration of the micro-pore distribution, approximated the practical measurement, having an error of less than 5 %. The sample application clearly indicated that larger water injection intensity (water intake per unit thickness) could result in more drastic water saturation variation, earlier water breakthrough, and faster increase in the water cut for layers with numerous high-permeability channels, such as fractures.

Fundamental controls on flow in carbonates: an introduction

The challenges posed by carbonate reservoirs today have been recognized for decades. ‘Old’ problems include the prediction of heterogeneous carbonate rock properties in the subsurface, the variable wettability of carbonate rocks, and the uneven sweep and early water breakthrough that commonly result from the presence of fractures, karst and/or other heterogeneities providing high-permeability flow paths (Bulnes & Fitting 1945; Craze 1950). While recent shifts in the industry have diverted attention to unconventional resources, conventional carbonate reservoirs remain the largest class of oil resources for the planet. Their recoveries, however, remain relatively low overall (Montaron 2008; Burchette 2012). While new technologies offer a deeper understanding of near-wellbore properties and processes, there remain large uncertainties in the distributions of flow velocities and the nature of flow paths between wells. These uncertainties arise from our inability to delineate geological features over a wide range of length scales, to represent them appropriately in flow simulations, to quantify their impacts on flow, as well as their impacts on evolving multiphase fluid distributions. While we wrestle with suitable proxies for geological heterogeneities that cannot be deterministically resolved in subsurface data or explicitly represented in field-scale reservoir models, many in the industry are forced to rely on long-established simulation technologies that have not kept pace with developments in modelling. In the absence of fully deterministic characterization and representation of the reservoir in our flow-simulation models, we need to mitigate the risks associated with uncertainty. Experiments designed to improve our ability to predict in the subsurface and to explore the range of possible responses can help. Clearly, there is an opportunity to pursue carefully designed subsurface experiments to test hypotheses for flow behaviour. Shallow subsurface experiments have already shown that, even between very closely spaced wells, it can be extremely difficult to define precise flow paths …

The Simulation Study of Full Diameter Cores Depletion on Volcanic Condensate Gas Reservoirs

The depletion experiments about practical condensate gas samples were carried out with the three full diameter cores from X volcanic condensate gas reservoir in the laboratory. The depletion behavior of condensate gas in cores was studied under the circumstances of existing bottom water, and the results were compared with that of constant volume depletion in a pressure-volume-temperature (PVT) cell. The experimental results were simulated by the ECLIPSE software afterward. The results indicate that the condensate gas depletion performance is different from that of PVT test regardless of existing bottom water, and there is only a little difference for natural gas recovery in cores whether the bottom water is existing, but bottom water has significant effect on condensate oil recovery; the higher the permeability of cores is, the faster water influx rate is, the earlier water breakthrough in production outlet is; the variation laws of the recovery of gas and condensate oil and gas oil ratio obtained by numerical simulation fit well with the physical simulation results and the simulation effect is satisfactory.

Role of forced regression in controlling Brent Group reservoir architecture and prospectivity in the northern North Sea

The Middle Jurassic Brent Group of the northern North Sea presents a mature and highly productive reservoir play fairway where a combination of effective facies analysis and depositional sequence stratigraphy offers real potential to optimize exploitation. The north of the Brent province differs from classically studied southern areas in being dominated by marginal-marine delta-front facies. A core- and log-based study of 37 wells around the Don fields was performed to establish a sequence stratigraphic framework, map facies and thereby describe facies architecture. The results demonstrate that reservoir quality and productivity are regionally and locally controlled by facies. Of particular interest are intervals of fluvio-estuarine channel to sharp-based shoreface sandstone that formed during sea-level lowstands, since it is these packages that boost well productivity but, conversely, also increase the risk of early water breakthrough on production. Analogy with the Saloum Delta of Senegal highlights the importance of rapid and continuous barrier migration and destruction in controlling the deflection and switching of fluvio-estuarine channels, explaining also the preferential preservation of channel-floor deposits over continuously eroded barrier and delta-top facies. Interpretations suggest that deposition in the study area was dominated by punctuated progradation of the Brent Delta, as periods of delta plain incision alternated with episodes of base-level rise and delta aggradation/progradation. A model of regression for the Brent Delta is presented, where the Rannoch, Etive and Ness formations are an amalgam of highstand, falling stage and lowstand systems tract deposits, and the Tarbert Formation is a transgressive systems tract deposit, with the delta responding to regional relative sea-level changes driven by uplift and deflation of the mid North Sea dome. The prograding Brent Delta is characterized as a succession of attached shorefaces formed by alternating periods of normal and forced regression. Significantly, this explains the long distance (&gt;200 km) build out of the Brent Delta and the continued presence of coarse-sandstone packages, as well as the potential for high-quality reservoirs even in the distal reaches of the system. It also suggests that there is limited potential for lowstand fan plays beyond the northernmost tip of the delta.

The Effects of Wettability on Gel Performance in Layered Heterogeneous Reservoirs

Regarding the application of enhanced oil recovery (EOR), reservoir heterogeneity leads to early water breakthrough and significant water production, so that substantial cost may be needed to treat the produced water. Gel treatments have been widely used to prevent early water breakthrough and great amount of water production by the modification of permeability. Reservoir wettability gives significant impact on gel treatment. This study is to assess the effect of wettability on the reservoir performance during gel treatment in layered heterogeneous reservoirs. Performances were compared in terms of water-oil ratio and cumulative oil recovery for different wettability conditions. With respect to oil recovery, there is no striking improvement by gel treatment. However, the results indicate that gel process presents 77% decrement of water-oil ratio over waterflood for oil-wet system and 51% for water-wet system. Gel is distributed in reservoir more widely for oil-wet conditions than water-wet conditions, which means the effect of gels is more dominant in oil-wet conditions rather than water-wet conditions.

Connectivity estimation between turbiditic channels and overbank deposits from the modelling of an outcrop analogue (Pab Formation, Maastrichtian, Pakistan)

Abstract The facies associations of the overflow deposits associated with turbidite channels were studied in the outcrops of the Maastrichtian Pab Sandstone, in SW Pakistan. In this area, a basin-floor fan was preserved from the platform to the deep basin setting. In the mid-fan setting, a channel complex crops out in three dimensions, and consists of a dozen channels and their overflow deposits, including levees, crevasse lobes and spill-over lobes. The overbank deposits can be directly in contact with the channel-fill, but, in many cases, matrix-supported debris-flow deposits made lenses close to the channel base. Heterolithic drapes of thin-bedded turbidite deposits were also preserved along the channel margins. A three-dimensional (3D) static model describing the heterogeneity distribution within the turbiditic channel complex was compiled using both stochastic and deterministic approaches in a site where two channels were laterally connected by overbank deposits. Petro-acoustic properties derived from a subsurface database were then assigned to the facies to perform seismic simulations. The synthetic seismic simulations showed that the channel base can easily be misinterpreted compared to the geological model. Dynamic modelling, such as well test and streamline simulations, was also performed using the model to assess the transition between the channel and overbank deposits from a dynamic point of view. As a result of the streamline simulations, the overbank deposits connecting the channel homogenized the pressure regime in the reservoir. However, the sweeping efficiency of water injection can be affected by the heterogeneity distribution along the channel margins. A significant volume of oil could also be by-passed because of the occurrence of early water breakthrough through the spill-over lobes, or because the flow slowed down when it reached the heterogeneity along the channel margin.