This paper presents the result of a reservoir study where seismic data have been fully utilized to obtain a better rock-type based reservoir characterization model. The study was conducted for a highly faulted carbonate reservoir in the Middle East. The available 3D Seismic data have been used to determine the structure map, fault and fracture network, and porosity distribution. Additionally, two seismic attributes (Energy Half Time and Max. Peak Amplitude) had also been used to assist the determination of stationarity regions used for geostatistical simulation.
The reservoir characterization strategy for this study was started with the detailed development of a geological reservoir rock type (RRT) scheme. The RRT scheme was developed based on depositional facies, diagenetic overprints and petrophysical properties, including pore throat size distribution, porosity and permeability. The scheme was then used to constrain the property modeling inside a geological framework that was built based on the seismic interpretation.
Prior to the development of 3D porosity model, four porosity maps were generated based on the available interpreted Acoustic Impedance (AI) and well log data. Each map represents the difference of the influence of seismic data, from full seismic influence to no seismic influence. One map has been selected to represent the seismic derived porosity based on the degree of correlation between the AI data and well-log porosity.
The integration of seismic-derived porosity into the 3D simulation model was conducted using Bayessian Update principle inside a conditional simulation technique. In this technique, 3D porosity distribution honors the underlying RRT and at the same time its vertical-column average honors seismic-derived porosity. The comparison of the results between the simulation with seismic and simulation without seismic has clearly indicated the value added by seismic data, namely improving the simulation result in the areas of poor well-coverage. This is important in order to honor the diagenesis effect that is difficult to model due to a limited number of wells.
Rawnsley, K. (Shell) | Swaby, P. (SSL) | Bettembourg, S. (Shell) | Dhahab, S. (Shell) | Hillgartner, H. (Shell) | de Keijzer, M. (Shell) | Richard, P. (PDO) | Schoepfer, P. (PDO) | Stephenson, B. (Shell) | Wei, L. (Shell)
As part of an ongoing drive to enhance oil recovery from several fractured carbonate reservoirs in Oman, Shell's Carbonate Development Team and Petroleum Development Oman have applied a workflow and research software package aimed at better characterizing the complex subsurface. The workflow comprises several steps, each one supported by a multidisciplinary research program, and implemented in an integrated software environment for application to field development and enhanced oil recovery projects. The software tool, which interacts with the existing Static and Dynamic modeling packages, produces integrated reservoir models including fracture specific information. The capabilities include: (1) Data integration and visualization (2) Constraints definition (from subsurface, analogue outcrops, geomechanics, etc.) (3) 3D fracture modeling (4) Link to reservoir simulation.
The tool is flexible, such that any type of well data (Static and Dynamic), seismic data (attributes and interpretations), and constraints can be brought together in a single display. An analysis package allows rapid visual and interactive structural analysis to be made, with quantification of structural elements. Constraints are derived from outcrop and subsurface field examples, geomechanical data and sandbox analogue experiments. A key constraint includes mechanical layering as a control on fracture geometries. Fracture networks are generated following the defined constraints combining statistics and mechanical rules. The fracture network properties useful for the Dynamic simulation can be quickly extracted. Because emphasis is placed on characterization and maximum use of the relevant constraints, the tool helps ensuring that the fracture modeling time is spent on understanding and assessing the uncertainties.
To date this workflow has been applied to several fields worldwide, demonstrating its suitability to address problems related to Natural Depletion, Waterflooding or Assisted Steam Gas Oil Gravity Drainage.
The use of Back Allocation is crucial in the Oil and Gas industry to facilitate accurate allocation of actual production and injection volumes at every node of a production network. Production engineers frequently use back allocation to estimate actual production volumes from wells based on frequent well test data or theoretical calculations using well and reservoir characteristics.
ZADCO implemented an optimized back allocation system to cope with the growing business needs, after a thorough system study of the legacy back allocation system. This presentation will present the considerations that led to this implementation and the project success.
ZADCO is a major operating company in Abu Dhabi operating in offshore fields, and is one of the largest oil companies in the world. Being a highly productive operator, ZADCO needed a back allocation system for apportioning fluids among upstream sources within a production network.
The new system provides a means to visualize complex networks, verify the production streams, track gathering systems functionality through time and derive the allocation networks.
This project has proven to be a reliable and comprehensive back allocation system, capable of providing all the necessary features required for a robust and solid back allocation system.
After the new Back Allocation System became fully operational, ZADCO started to realize the following benefits from this successful implementation.
Ability to correctly apportion production, where accurate measurements are not possible or cost effective.
Ability to determine fluid flow quantities through every strategic point in the network and determine the production quantities of each well and reservoir for production accounting.
Reduced time and effort to setup and execute fluid disposition allocations.
Better quality back allocated results
The new system optimizes the allocation system workflow, resulting in the routine monthly allocation work being greatly simplified.
Sluijterman, A.C. (Petroleum Development Oman) | Al-Lawati, Y. (Petroleum Development Oman) | Al-Asmi, S. (Petroleum Development Oman) | Verbeek, P.H.J. (Shell International Exploration and Production) | Schaapveld, M.A.S. (Shell International Exploration and Production) | Cramwinckel, J. (Shell International Exploration and Production)
The Greening the Desert initiative explores opportunities to re-use water produced from hydrocarbon fields in arid areas around desert oil fields. Where water does not serve any purpose for reservoir management, re-use is envisaged to be an enabler for new value creation by stimulating opportunities such as agriculture or forestry. An oil field in the south of Oman produces in excess of 200,000 m3/d of brackish water, the larger part of which is disposed of through re-injection into deep aquifers. As an alternative the operator has embarked on reed bed pilots later followed by pilots on bio-saline agriculture and forestry. Also a pilot has been executed for the purification of the effluent water from the reed beds by a Solar Dew® membrane system, allowing a.o. fresh water agriculture. Pilots for the different Greening the Desert schemes are aimed at developing a portfolio of technical solutions for produced water re-use in desert environments. The paper presents operating envelopes and limits of technical performance. The selection of technical solutions for a large-scale project may then be based on the best total lifecycle value balancing cost, benefits and risks, and meeting aspirations for sustainable development.
Permeability modeling and permeability prediction has always been a critical phase in building geological models. In a major Abu Dhabi offshore oil field, several reservoir characterization and evaluation studies have been conducted during the last five years. The estimation of permeability in each well is required to identify and model reservoir flow units in the field, Rock types are identified from cored wells using thin section and conventional core analysis (rock fabric, porosity, permeability,) in parallel with relating it to capillary pressure curves. In non-cored wells (90% of total wells), a backward model of rock type classification is achieved through the utilization of well logging data which is proved to provide (1) Porosity & (2) Lithology information using Neutron, litho-Density and Sonic tools, therefore, Permeability from logs is the missing information to make the log rock typing backward model working.
In these studies, several innovative approaches of permeability estimations have been developed in-house and used or declined in different stages. Two of these approaches will be thoroughly explained to explore the strengths and weaknesses of each one of them with the reasons of being working in some formations but not others, where different relations between Core permeability and Log responses in different formations is driven by rock properties.
In the first approach, the invasion profile permeability index from Electrical Resistivity logs has been used to honor the general relation between porosity and permeability, in which six different cases and conditions has been considered to correct for the universal equation developed in this approach from logging data of Electrical Resistivity, these consideration are: (1) gas zone, (2) oil & transition zone, (3) water zone, (4) fractured area (5) drilling fluids (6) facies quality. This permeability estimation approach is called Universal Rock Permeability (UROK).
In the second approach, the clay content distribution constructs the permeability alteration model that is reflected in Gamma-Ray (GR) response, where GR horizontal changes within a layer found to be different from another layer. Therefore, a statistical GR analysis that searches for the optimum GR-Permeability model is developed. This permeability estimation approach is called Permeability Active Searching (PASZ).
In this paper, we will first estimate the uncertainty on remaining oil saturation S oil during primary water flooding, since that is the maximum saturation that remains available for enhanced recovery through gas injection, and this number plays a critical role in the original decision on whether to even initiate a gas injection pilot project. We will then confirm the findings of reference 1, as to the final S oil after gas injection, but will also look at the variations in S oil uncertainty as the gas volume increases from initial breakthrough to final maximum saturation. The situations of gas displacing oil in an unswept reservoir, and gas replacing both oil and water in an already water-swept reservoir will be considered.
Planning and designing the gas injector and observer is a key for the gas pilot success. Results of two gas injection pilots is discussed.
The objective of pilots in both reservoirs A and B is to provide additional data to evaluate the benefits of full field gas injection to help define future full field development strategies. The Reservoir A pilot will account for 10 mmcfpd injection rate and Reservoir B pilot will account for 20 mmcfpd. Both rich and lean gas will be used for injection.
Additional (Reservoir A) gas injection well may be required by converting the existing water injection pilot well to gas injector. Compression gas supply sources were reviewed. The rich gas source will be the associated gas from the 1 st stage production separators. The lean gas source has been identified as the residue at the outlet of the Field Gas plant.
Both pilots will undergo a cyclic gas injection operation; a slug of rich gas injection will be followed by lean gas injection. The compression plant must therefore have the flexibility to compress both types of gas. Furthermore a potential implementation of water-alternative-gas (WAG) injection during the later stages of the pilot may be considered.
Pilot duration is planned for a minimum of three years , which will then enable the selection of a recovery mechanism for the next stage of development.
From the operating company's perspective , the most viable option is to use sweet associated rich gas that results in high oil recovery ; furthermore , there is also the potential to test rich / lean gas combinations to enhance the economics of gas injection projects.
The primary objectives of the two pilots schemes for Reservoirs A and B are as follows:
Provide data for improving the predictive capability of reservoir simulation models, such as lateral versus vertical movement of gas and residual oil saturation behind the flood front.
Determine the effective vertical permeability.
Monitor gas front movement across the reservoir.
Determine residual oil saturation and uncertainties from logs and cores.
Assist in validation of reservoir simulation models used to forecast recovery factors , as a base for potential full field implementation.
Insalaco, Enzo (Total Exploration Production, France) | Lescanne, Marc (Total Exploration Production, France) | Masse, Pierre (Total Exploration Production, France) | Walgenwitz, Frederic (Total Exploration Production, France) | Sudrie, Marina (Total Exploration Production, France) | Thiry-Bastien, Philippe (Total Exploration Production, France) | Roumagnac, Alain (Total Exploration Production, France) | Fraisse, Christian (Total Exploration Production, France) | Kamali, Mohammad (NIOC-RIPI, Tehran, Iran) | Moallemi, Ali (NIOC-RIPI, Tehran, Iran) | Lotfpour, Masoud (NIOC-RIPI, Tehran, Iran) | Monibi, Saeed (NIOC-RIPI, Tehran, Iran) | Gaillot, Jeremie (Univ. Lille 1, Lille, France)
The Dalan/Kangan (Khuff) Formation is a major reservoir in Iran and the restof the Middle East Gulf region, and contains some of the world's biggest gasreserves. The reservoir facies of this formation developed on a very largeregional carbonate platform which had a very low topographic relief. This largegeographic extent of the platform system is responsible for the development ofvery extensive facies tracts - in order to encounter major facies changes,large areas need to be investigated. This is often not possible in detailedreservoir-scale studies. In such cases, integrated models that extend fromproximal positions to more oceanward locations are difficult to apply.
In order to address these issues a large multidisciplinary and multiscalesubsurface study has been launched on a large database including fields fromonshore and offshore Iran. The aims to better understand the faciesdistributions, sequence stratigraphic architecture and the regional reservoirdevelopment.
Twenty-two principal facies have been recognized including massive tolaminated anhydrite, mudstone with anhydritic nodules, dolobreccias, greenshale, massive to bioturbated mudstone, laminated dolomudstone, coarselithoclastic and bioclastic grainstone, bioclastic grainstones, ooliticgrainstones, peloidal grainstones, dark mudstones, and thrombolitic limestone.These facies have been interpreted in terms of depositional environmentincluding: evaporitic flats or saltern (shelf supratidal/intertidal to subtidalsetting), tidal flats (intertidal to supratidal setting, with numeroussubenvironments such beach ridges, intertidal flats, tidal channels), subtidallagoon (subtidal setting), leeward shoals (subtidal to intertidal setting),oolitic to oobioclastic shoal belts (subtidal to intertidal setting), compositesandwave constructions (subtidal setting), and middle shelf deposits (subtidalsetting).
From the Dalan K4 through to the Kangan K1 significant changes in platformtype/geometry, facies organization and climate occurred. Consequently,different depositional models need to be created for each of the majorstratigraphic interval. Conceptual geological models have been constructed forthe large-scale stratigraphic architecture, sedimentological organization andthe palaeoecological systems. The correlations show significant changes insedimentological and reservoir facies across the study area, which are notevident at smaller scales. These large-scale geographic and stratigraphicfacies trends provide a regional framework which can then be used to helpconstrain reservoir-scale studies.
Residual Oil Saturation (Sorw) is a critical reservoir model parameter for evaluating reserves in the Greater Burgan Field. Past Sorw studies in Greater Burgan Field either looked only at core test data, or only looked at cased-hole log data. None of the past studies considered areal position, different rocktypes, or changes in remaining oil saturation with varying amounts of water sweep.
This study includes analysis of Sorw from open-hole water saturation, Time-Lapse PNC data and Special Core Analysis water flood experiments.
The majority of the log data in Greater Burgan Field water - swept zones are concentrated in the 3rd sand middle, 3rd sand lower and 4th sand formations. The comparisons of the results from all three methods used in the study to measure remaining oil saturation (ROS) are limited to these reservoirs.
Results from these methods were remarkably consistent.
All reservoir sand with extensive PNC log data showed that zones encroached by water for 22+ years tend to be at or near residual oil conditions. Measurements in the zones with water encroachment for less than 22 years have about a 50% chance of being incompletely swept. Analysis of the 22+ year data allowed reasonable ranges of Sow were estimated from this data.
Investigations of ROS spatial variations in the Magwa, Ahmadi and Burgan sub-fields were made. 3rd sand middle was the only reservoir with both adequate PNC and open-hole coverage in ROS from these three areas in Greater Burgan Field.
ROS by rocktype was reviewed in three categories of reservoir rock (excellent, medium and poor quality reservoir) as currently defined by log analysis in Greater Burgan Field. The vast majority of log data occurs in rocktype 1, the highest quality reservoir rock. Only 3rd sand lower formation contained sufficient data in all three reservoir quality rocktype to make valid comparison. Both core flood Tests and PNC Time-Lapse methods also showed no difference in ROS based rocktype.
LNG production units located in Das Island have four (Boiler Nos. 1 to 4) high pressure/high capacity Boilers for steam generation (which supplies steam to LNG Trains 1&2). Each of the four massive Boilers have separate De-aeration unit, where the major portion of dissolved gases (mainly oxygen and carbon dioxide) present in the feed water are removed by scrubbing with steam. Followed by De-aeration, to get rid of the remaining oxygen present in the feed water, an oxygen scavenger is injected downstream of De-aerator. This product chemically scavenges the remaining dissolved oxygen by reaction. The oxygen present in the feed water is the chief culprit for boiler steam system corrosion and would cause accelerated oxygen pitting, especially at elevated temperatures. The oxygen scavenger quietly does its job and keeps up the boiler life; hence the use of this product is very vital in any boiler operation.
During all these years of operation, "hydrazine" was employed as the oxygen scavenger and found to be meeting the operational requirement. But continuing this product became an important issue, because it has been widely claimed as a carcinogen and toxic.
The issue started gaining importance as it directly concerned with "Health Effect". The necessity to evaluate a safer alternative turned out as a challenging task for ADGAS, because on one hand the proven product needed replacement due to the health hazard and on the other hand the Boiler performance/integrity had to be ensured.
The task was handled successfully; a better alternative oxygen scavenger was chosen (DEHA, Diethyl Hydroxyl amine) after detailed evaluation and is in satisfactory service since July 2002 in Boiler 1 to 4. Based on the experience from Boilers 1 to 4, ADGAS have very recently switched over to use of this safer alternative (DEHA) also in the remaining Boilders 5&6 also, which supply steam to Train-3.
The successful approach has helped ADGAS to contribute for the Occupational Health improvement to the working environment and thereby enhance its HSE STANDARDS. Through this paper ADGAS shares their experience in this regard.
Pressure build-up due to fluid thermal expansion in sealed annuli of HP/HT wells can have serious consequences such as casing failure or tubing collapse. To determine whether mitigation was required for a HP/HT development, annular pressures in an appraisal well were studied with a dedicated field test, which consisted of running a pressure/temperature memory gauge in a casing/casing annulus of a well and testing the well several times during a 3-month period, after which the gauge was retrieved and the data were read out.
First of all, comparison of the magnitude of the observed annular pressures with the burst and collapse ratings of the casings, shows that annular pressure build-up is a serious consideration in casing design. Such design is to be based on theoretical models for annular pressure build-up. The data acquired with the test serve to validate these models.
The data demonstrated that in the lower temperature range (20 to 40°C), on average, pressure development in the annulus agreed reasonably well with theoretical model predictions, based on thermal expansion of the annular fluids and casings, and ballooning and compression of the casing strings. The influence of these factors could be established by analyzing the transient pressure response of the annulus. At higher temperatures the theoretical models overestimate pressure build-up. This is probably to be attributed to the properties of the completion fluids differing from the properties of the base fluid, water. Estimates on the basis of pure water properties can be considered a worst-case estimate for pressure build-up. Leak-off of the annular fluids, which was seen to dominate pressure development during a previous test in a well with a cement shortfall between casings, did not play a significant role in this fully cemented and sealed annulus.