This paper presents a multidomain integrated workflow that combines geophysics, borehole geology, fracture modeling, and petroleum systems analysis for characterization and resource assessment of basement plays. A 3D fracture model is developed by integrating image log interpretation and seismic data to assess the reservoir potential of fractured basement. The 3D fracture modeling is done using the discrete fracture network (DFN) approach with image log interpretation and other fracture drivers serving as the main input. The DFN is upscaled to generate fracture porosity and fracture permeability properties in a 3D grid. The upscaled fracture porosity is used to estimate the petroleum initially in place (PIIP) for the prospects. Multiple 2D petroleum system modeling is performed where large fault throws are identified from seismic interpretation. The petroleum system study helps in identification of areas with most prolific hydrocarbon generation and expulsion centers, which, coupled with the cross-fault juxtapositions, are the main locales of charging for basement reservoir. Further analysis of all the elements of basement play (i.e., source, reservoir, seal, trap, and migration) is done, and prospective areas within the basement play are delineated with high geological chance of success.
Ibrahim Mohamed, Mohamed (Colorado School of Mines) | Salah, Mohamed (Khalda Petroleum) | Coskuner, Yakup (Colorado School of Mines) | Ibrahim, Mazher (Apache Corp.) | Pieprzica, Chester (Apache Corp.) | Ozkan, Erdal (Colorado School of Mines)
A fracability model integrating the rock elastic properties, fracture toughness and confining pressure is presented in this paper. Tensile and compressive strength tests are conducted to define the rock-strength. Geomechanical rock properties derived from analysis of full-wave sonic logs and core samples are combined to develop models to verify the brittleness and fracability indices. An improved understanding of the brittleness and fracability indices and reservoir mechanical properties is offered and valuable insight into the optimization of completion and hydraulic fracturing design is provided. The process of screening hydraulic fracturing candidates, selecting desirable hydraulic fracturing intervals, and identifying sweet spots within each prospect reservoir are demonstrated.
Specic experiments have been designed and the experimental measurements obtained show that, not only the absolute permeability but also the gas relative permeability are sensitive to connement and that the residual gas saturation (through permeability "jail") increases with loading. This observation represents an additional source of complexity in the evaluation of low-permeability sandstone gas reservoirs. INTRODUCTION Low-permeability sandstone gas reservoirs, also called tight reservoirs, are generally considered stress-sensitive reservoirs. Numerous laboratory tests under single-phase ow have shown that the absolute permeability of these reservoir rocks decreases strongly with connement. This dependence on connement is attributed to the existence of joints and interfaces in tight rocks, which close when loading increases, as pointed out by Walsh and Brace (1984) and Warpinski and Teufel (1992).
Aranha, Pedro Esteves (Petrobras) | Colombo, Danilo (Petrobras) | Fernandes, André Alonso (Petrobras) | Vanni, Guilherme Siqueira (Petrobras) | Tomita, Reinaldo Akio (Petrobras) | Lima, Cláudio Benevenuto de Campos (Petrobras) | Lima, Gilson Brito Alves (Federal Fluminense University) | Wasserman, Júlio César de Faria Alvim (Federal Fluminense University)
The demand for ultradeepwater scenarios invoked the frequent application of managed pressure drilling (MPD) in the last few years. In an ultradeepwater scenario, oil companies face issues such as narrow pressure windows and severe loss zones. Many wells are considered undrillable without the aid of MPD technology. MPD operations need to be correctly evaluated with consideration given to increased time and cost/benefit analysis. In this paper, we propose a probabilistic model to evaluate MPD demand by estimating the optimal number of rigs equipped with MPD and a rotating control device (RCD), and we analyze which intervention strategy is the most cost- and time-effective. Reducing uncertainty is an important factor when making decisions about drilling. We adopted a Monte Carlo simulation using loss-zone estimation, probability of prediction error, the number of rigs equipped with MPD, and several strategies. Better MPD strategies were determined on the basis of available data and the optimal number of rigs equipped with an MPD system and RCD equipment, reducing subjectivity in the decision-making process. The originality of our paper lies in the new quantitative approach to dealing with uncertainty in the prediction of fluid losses and the cost and duration of different MPD strategies, numerically simulating the possible scenarios.
A challenge in oil-reservoir studies is evaluating the ability of geomechanical, statistical, and geophysical methods to predict discrete geological features. This problem arises frequently with fracture corridors, which are discrete, tabular subvertical fracture clusters. Fracture corridors can be inferred from well data such as horizontal-borehole-image logs. Unfortunately, well data, and especially borehole image logs, are sparse, and predictive methods are needed to fill in the gap between wells. One way to evaluate such methods is to compare predicted and inferred fracture corridors statistically, using chi-squared and contingency tables.
In this article, we propose a modified contingency table to validate fracture-corridor-prediction techniques. We introduce two important modifications to capture special aspects of fracture corridors. The first modification is the incorporation of exclusion zones where no fracture corridors can exist, and the second modification is taking into consideration the fuzzy nature of fracture-corridor indicators from wells such as circulation losses. An indicator is fuzzy when it has more than one possible interpretation. The reliability of an indicator is the probability that it correctly suggests a fracture corridor. The indicators with reliability of unity are hard indicators, and “soft” and “fuzzy” indicators are those with reliability that is less than unity.
A structural grid is overlaid on the reservoir top in an oil field. Each cell of the grid is examined for the presence and reliability of inferred fracture corridors and exclusion zones and the confidence level of predicted fracture corridors. The results are summarized in a contingency table and are used to calculate chi-squared and conditional probability of having an actual fracture corridor given a predicted fracture corridor.
Three actual case studies are included to demonstrate how single or joint predictive methods can be statistically evaluated and how conditional probabilities are calculated using the modified contingency tables. The first example tests seismic faults as indicators of fracture corridors. The other examples test fracture corridors predicted by a simple geomechanical method.
The variety and sophistication of upstream technologies have been growing fast for imaging the subsurface, modeling reservoir performance and monitoring oil and gas production. Yet there remains a fundamental need to thoroughly sample and analyze the produced reservoir fluids. Reservoir fluid analysis is critical for understanding the nature of produced hydrocarbons and is the key for production optimization. To gain the maximum value from this analysis, reservoir fluid sampling programs need to be well designed and integrated into well testing and reservoir surveillance programs, and not to be developed after. In one of Chevron's deep-water Gulf of Mexico (DWGOM) sub-salt fields, a robust geochemical sampling plan and production monitoring program has been in place since initial production to estimate the zonal contribution from individually stacked reservoirs. This surveillance work has been ongoing for 9 commingled wells over a period of 10 years.
Methods currently used to evaluate laboratory performance of asphaltenes inhibitors are non-optimal because the conditions used are so far from those prevailing in the field, leading to incorrect assessment of dose rates or even selection of chemicals that may not be beneficial at all. We present a dynamic flow test method for asphaltenes risk assessment and inhibitor qualification that uses field-representative temperature, pressure and fluid dynamics to enable successful correlation with field behaviour.
This paper discusses the most commonly used laboratory test methods for asphaltenes testing and proposes a new dynamic flow method that offers a significant improvement over other widely-used techniques. Reconditioned dead crude oil is co-injected with
We present a case study describing the use of the dynamic flow test equipment to assess asphaltenes deposition risk and to qualify asphaltenes inhibitors for field application. We demonstrate that the method is able to rank chemicals for performance at inhibiting deposition under flowing conditions and at more field-representative temperature and pressure, with much lower percentages of
We discuss the effect of critical parameters affecting the extent of asphaltenes deposition. Fluid dynamics are recognised to play a key role in asphaltenes deposition in the field, not least, because at higher wall velocities the erosive force acting on field deposits is high enough to limit further growth and steady state can be reached. Flowing tests were conducted under a number of fluid-dynamic regimes in which asphaltenic crude oil was destabilised by addition of
This paper presents the development of a new laboratory test method utilising dead crude both for asphaltenes risk assessment and inhibitor qualification that offers significantly improved correlation with field behaviour over conventional dispersancy testing, yet remains much more cost effective than labour-intensive autoclave testing utilising live fluids. When considering asphaltenes risk analysis the approach also allows for deposition
The impact of suspended solids and dynamic conditions on sulphate scale control is well-known. Previous work examined the effect of suspended solids, along with static and turbulent conditions, on one scale inhibitor (Vs-Co). This study has focused on the challenges experienced by an operator of a chalk reservoir field, with a significant amount of carbonate solids in the system, and a high sulphate scale risk due to high barium concentration, injection seawater breakthrough, and cool topside process conditions (20°C). The initial laboratory evaluation showed that the minimum inhibitor concentration (MIC) observed increased from 50ppm to 250ppm after 24 hours (>80% efficiency) under these conditions.
A further study investigated whether a reduction in MIC could be achieved with different chemistry. Various chemicals were screened in conventional static jar tests and in stirred tests to induce turbulence incorporating mixed solids. The results showed that many of the conventional scale inhibitor chemistries, working by nucleation inhibition and crystal growth retardation, could not cope with the severe scaling conditions and were less efficient than the incumbent. However, a "novel" scale inhibitor formulation was shown to work more effectively and resulted in a significantly lower MIC than the incumbent.
Under sulphate scaling conditions (80:20 FW:SW), VS-Co recorded an MIC of 250ppm which was reduced to ≤100ppm with the novel chemical. This resulted in the opportunity for the operator to reduce their chemical dose rate and logistical costs.
This novel chemical works by a combination of nucleation inhibition and crystal growth retardation. As a result of this inhibition mechanism, other operators experiencing similar harsh sulphate scaling conditions could achieve a lower treat rate in high suspended solid loaded systems.
Kashim, Muhammad Zuhaili (PETRONAS) | Giwelli, Ausama (CSIRO) | Clennell, Ben (CSIRO) | Esteban, Lionel (CSIRO) | Noble, Ryan (CSIRO) | Vialle, Stephanie (Curtin University) | Ghasemiziarani, Mohsen (Curtin University) | Saedi, Ali (Curtin University) | Md Shah, Sahriza Salwani (PETRONAS) | M Ibrahim, Jamal Mohamad (PETRONAS)
In line with PETRONAS commitment to monetize high CO2 content gas field in Malaysia, C Field which is a carbonate gas field located in East Malaysia's waters with approximately 70% of CO2 becomes main target for development because of its technical and economic feasibility. Injectivity has been determined as one of the key parameters that determine the success of CO2 storage in field operations. In order to characterize the CO2 injecitivity behavior in C Field, long duration coreflooding experiments has been conducted on two representative core samples under reservoir conditions. The first set of coreflooding test has been conducted on gas zone sample and another one is on aquifer sample. Two important approach has been applied in the experiment in which the first one is where the base rate is established after each incremental stage and the second one is the pre-equilibration of carbonated brine with standard minerals based on the percentage of core mineralogy before saturating the core with aquifer brine to mimic the insitu geochemical conditions of the reservoir. Pre- and post-flooding characterization was conducted using Routine Core Analysis (RCA), X-Ray CT-scan, Nuclear Magnetic Resonance (NMR) and Inductive Coupled Plasma (ICP) to examine the porosity-permeability changes, pore size alterations and the geochemical processes that might take place during CO2 flooding. Based on the differential pressure data, it showed no clear indication of formation damage even after injection of large CO2 pore volume. Pre and post-flooding characterization supported the findings where minor dissolution/precipitation is observed. Overall intrepretation indicates that the critical flowrate is not yet reached for both samples within the maximum rates applied.
Chen, Xin (BGP) | Wang, Guihai (CNODC) | Wang, Zhaofeng (CNODC) | Liu, Zundou (CNODC) | Liu, Zhaowei (CNODC) | Cui, Yi (CNODC) | Tian, Wenyuan (CNODC) | Wei, Xiaodong (BGP) | Hou, Liugen (BGP) | Yang, Ke (BGP) | Chen, Gang (BGP) | Xia, Yaliang (BGP) | Yan, Xiaohuan (BGP) | Zhang, Zeren (BGP) | Liu, Jingluan (BGP)
To improve the accuracy of permeability prediction, seismic constraint and sedimentary facies has often been adopted in conventional methods. However, it is porosity that both of them constrain, rather than permeability, and different pore structure with different permeability, the accuracy of permeability prediction cannot be radically improved. To address the problem of permeability prediction in carbonate reservoir, new permeability prediction technique workflow were summarized based on pore structure analysis and multi-parameters seismic inversion: division reservoir types based on the pore structure, construction of the rock types identification curve, carry out a rock type inversion and a porosity inversion constrained by seismic impedance respectively, and then get a final permeability prediction volume according to the porosity-permeability relationship and pore structure of core samples. It breaks the bottleneck that is difficult for seismic impedance (continuous variable) to constrain rock type (discrete variable), then constrains pore structure (continuous variable) related to rock type instead, and converts it into rock type using multi-parameters seismic inversion. According to the certification of new wells, this workflow have been applied successfully in carbonate reservoir of H oilfield in Middle East, it not only improves the prediction of rock type in space, but also permeability prediction accuracy.