Moreno Ortiz, Jaime Eduardo (Schlumberger) | Klemin, Denis (Schlumberger) | Savelyev, Oleg (Gazprom Neft Middle East B.V.) | Gossuin, Jean (Schlumberger) | Melnikov, Sergey (Gazpromneft STC) | Serebryanskaya, Assel (Gazprom Neft Middle East B.V.) | Liu, Yunlong (Schlumberger) | Gurpinar, Omer (Schlumberger) | Salazar, Melvin (Schlumberger) | Gheneim Herrera, Thaer (Schlumberger)
Use of numerical models to characterize and evaluate reservoir potential is an industry wide practice, with increasingly more development decisions being substantiated by finite difference models. Advances on hardware and software, along with the ability to effectively incorporate accurate process physics, makes simulation a robust tool for field development decisions, particularly on complex operations such as enhanced oil recovery and/or reservoirs with challenging heterogeneity and pore structures. Use of these models does not come without its challenges where data requirements (and use of special characterization both at lab and field level) increase as does the reservoir characterization granularity and thus model sizes. Unsurprisingly the increase of model precision and data requirements amplifies non-uniqueness of the numerical solutions obtained during any field evaluation including field development planning (FDP). Incomplete/inconsistent datasets pose a further challenge to the accuracy (and arguably risk) of the forecasts by introducing further uncertainty on the process characterization. Use of complementary technology such as digital rock, that would enable mitigate impact of such uncertainties in a timely manner -either at field or laboratory level, is thus highly desirable particularly when dealing with enhanced oil recovery. Compounding the non-linearity effect of the EOR agent characterization is the effect of the augmented numerical artifacts (dispersion, dilution, etc) of which complex chemical implementations are prone to, making the upscaling process from laboratory dimensions to field more complex.
Africa (Sub-Sahara) Sonangol's deepwater Orca-1 well encountered oil in the presalt layer of Block 20/11 in the Cuanza basin offshore Angola. The well reached a measured depth of 12,703 ft. Initial well tests saw flow rates of 16.3 MMcm/D of gas and 3,700 BOPD. Cobalt International Energy (40%) is the operator, with partners Sonangol Research and Production (30%) and BP Exploration Angola (30%). Asia Pacific Premier Oil's Kuda Laut-1 well in Indonesia's Tuna production sharing contract has encountered 183 net ft of oil-bearing reservoir and 327 net ft of gas-bearing reservoir. Following evaluation operations, the well will be sidetracked to drill the Singa Laut prospect in an adjacent fault block. Premier is the operator (65%), with partner Mitsui Oil Exploration Company (35%).
In this paper we present details of the approach utilized to optimize the well stimulation campaign in the continued development of a huge carbonate gas condensate field in the Offshore Iran. This study discusses what have been done differently, best practices, and learning. What is different in this campaign from previous ones?
Detailed well-by-well review Fundamental data collection for parameters analysis - operational, subsurface, treating fluid data Data management system allowing for quick access Design tool for detailed damage diagnosis, fluid system selection, pumping schedule design, and pressure matches. QA/QC and compatibility tests aiming to obtain high success rate. High contrasts in porosity, permeability and initial pressure Complex mineralogical & lithology composition Fissures and Vuggy porosity Long perforated intervals and well inclination effects Pre-acid nearwellbore reservoir initial condition High rate and ΔT effects on completion & cement integrity Optimum zonal coverage Keep completion integrity while high rate injection Use minimum volume of chemicals Reduce operation risks & costs
Detailed well-by-well review
Fundamental data collection for parameters analysis - operational, subsurface, treating fluid data
Data management system allowing for quick access
Design tool for detailed damage diagnosis, fluid system selection, pumping schedule design, and pressure matches.
QA/QC and compatibility tests aiming to obtain high success rate.
High contrasts in porosity, permeability and initial pressure
Complex mineralogical & lithology composition
Fissures and Vuggy porosity
Long perforated intervals and well inclination effects
Pre-acid nearwellbore reservoir initial condition
High rate and ΔT effects on completion & cement integrity
Optimum zonal coverage
Keep completion integrity while high rate injection
Use minimum volume of chemicals
Reduce operation risks & costs
Optimum acid placement in bullheading treatment in commingled mode is still the challenging issue in in Iran well stimulation jobs. We propose a comprehensive step-by-step workflow to get the best results using Nodal Analysis & Stimulation Software in a logical way described later in the text. Diversion techniques history in this field is: Mechanical diversion, Ball sealers, Selective perforation with polymer based diverter, Selective perforation with high injection rate and VDA technique. Our new diversion method that deployed along with a revised placement model, field calibrated to more accurately predict treatment pressure responses, to optimize acidizing design and to maximize diversion in this layered reservoir, studied in this paper.
Results presented include stimulation treatment plots alongside model post treatment pressure matches, pre and post stimulation production logs, clean up data and well test interpretations to validate the models. We describe high/low permeability, multi zone treatments with a bullheaded matrix acidizing technique. We observed in one well through tubing treatment pressures response and oscillate between 2000 and 3500 psi, far above what is typically observed in this field in which the pressure reduction happened quickly from 3000 to 1000-500 psi.
We conclude that due to enhanced diversion results in uniform zonal depletion which is due to uniform zonal acid coverage. We have also found operational benefits in deploying the system in that commingled zones, normally perforated and stimulated in several stages can now be easily and effectively stimulated using a one-stage technique.
Kundu, Ashish (Abu Dhabi Co For Onshore Petroleum Operations Ltd.) | Voleti, Deepak Kumar (Abu Dhabi Co For Onshore Petroleum Operations Ltd.) | Mokhri, Mohd Nazaruddin (Abu Dhabi Co For Onshore Petroleum Operations Ltd.) | Manseur, Saadi (Abu Dhabi Co For Onshore Petroleum Operations Ltd.)
When a reservoir undergoes gas cap production without proper pressure maintenance, the underlying oil rim development at a later stage of the field development is very critical and challenging. Adding to the complexity is the tilted Free Water Level. This paper presents a study that was performed to model a large tilted oil rim reservoir that had been massively depleted by the production of the overlaying gas cap.
The first part of the paper explains the development history of the oil rim and the low recovery factor that was obtained as a result of the massive gas cap depletion, and the results of previous attempts to revive dead oil wells through artificial means (ESP, booster pumps) which had limited success so far. The second part of the paper elaborates on the study which was carried out to build the concept of a tilted reservoir and later modelled it to get the proper initial water saturation distribution. The variable salinity concept was brought in to validate the proposed tilting scenario. The variable salinity was supported by produced water salinity data. The formation pressure test data also conforms to the tilting concept.
The tilting in Free Water level (FWL) was also observed while analyzing capillary pressure data. Model was prepared to map the tilted FWL by krigging FWL depths at individual wells. The challenges that were encountered and overcome during the feasibility study: (1) construction of a new reservoir model incorporating a large set of static and dynamic data showing significant complexity with tilted fluid contacts, variable formation water salinity and initial fluid saturation; (2) multi-scenarios history matching with complex fluid movements and tilted Free Water Level; (3) reservoir uncertainty analysis using learnings from history matching; (4) accurate remaining oil saturation in oil rim.
The originality of this study resides in the complex reservoir geology and field production history, in the integrated approach to address requirements of both oil rim and gas cap developments, and in the fact that proposed field revitalization calls for unusual static and dynamic reservoir property modelling which can conceptualize the fluid movement before and after production.
Pietraszsek-Mattner, Sarah (ExxonMobil Exploration Company) | Barron, James W. (ExxonMobil Upstream Research) | Myers, Rodrick D. (ExxonMobil Upstream Research) | Moreton, David J. (ExxonMobil Exploration Company) | Sempere, Jean-Christophe (ExxonMobil Upstream Research)
With the recent downward pressure on oil and gas prices, the oil and gas industry is operating in a reduced capital environment and is optimizing expenditures throughout the lifecycle of an oil and gas asset. In order to stay competitive, successful companies need to develop the next generation of technologies to enhance their abilities to be more selective in exploiting the reservoirs that underpin a project. In the past, the evolution of 3D and 4D seismic acquisition and enhanced seismic imaging techniques reduced exploration risk through the remote sensing of trap geometries, reservoir properties, and fluid presence, where favorable conditions existed. In higher-risk plays, such as those that depend on the existence of connected natural fracture networks to achieve economic flow rates, the ability to predict the presence, orientation, extent, and relative intensity of these fracture systems is necessary to improve the overall success in intersecting the highest natural fracture density and most productive reservoirs. Traditionally, the impact of natural fractures on reservoir performance has been analog-based and scaled to match production data. A new process-based numerical modeling technology has been developed that predicts the formation of natural fracture networks from structural history and geomechanics. This prediction is then calibrated to fracture data collected from image logs, core and dynamic wellbore performance data. Utilizing this field-wide spatial distribution of fracture connectivity can narrow investment uncertainty by optimizing the number and position of future appraisal, production and injection well locations.
Temizel, Cenk (Aera Energy) | Thanon, Diyar (Texas A&M University) | Inceisci, Turgay (Turkish Petroleum) | Balaji, Karthik (University of Southern California) | Suhag, Anuj (University of Southern California) | Ranjith, Rahul (University of Southern California) | Wijaya, Zein (HESS) | Raafat, Elsayed (University of Oklahoma)
Started in the late 1800s in the US, water being relatively inexpensive, readily available in large volumes and also being very effective at significantly increasing oil recovery, waterflooding has been the most common secondary recovery method applied throughout the world, contributing to pressure maintenance in the reservoir and displacing the oil phase. While there are several parameters that influence the performance of a waterflood, water quality is one of the most important factors as it may cause scaling in injection wells as well as some formation damage through chemical phenomena such as, cation exchange in the reservoir, resulting in decreased the recoveries.
As waterfloods continue over decades, prevention of scale formation becomes a more significant factor that needs to be properly treated. Precipitation of inorganic scale is a major issue in injecting brines with a high concentration of divalent ions. Scaling tendency of water is highly correlated with the hardness of injection water.
Following corrosion, insoluble iron precipitates can cause damage in injection wells since precipitates can lead to severe reductions in well injectivity. Water needs to be treated in a proper way, if the water contains high concentrations of calcium, magnesium or iron. In most waterflood applications, seawater needs to be used and this phenomenon is also an issue when injecting seawater into formations that contain brines with high salinity.
In this study, we provide a comprehensive analysis of this common problem by investigating the significance of parameters affecting the severity of scale formation through utilizing a seawater scale buildup model that will be simulated using a commercial simulator along with an in-depth review of previous studies.
This article exclusively relies on data from published literature.
The development of a foreland basin in the Mesopotamian Basin of South Iraq during the deposition of the Mishrif resulted in facies stacking patterns reflecting the development of a flexural bulge.
Paleogeographic reconstructions rely on carbonate facies as depth indicators, whereby rudist biostromes and coarser bioclastic debris define Shoal Complexes that separate restricted lagoonal deposits from open marine sediments. Ahmadi-Rumaila-Lower Mishrif sediments deposited into a N-S trending basin also showing evidence of precursory foreland basin tectonics: the increasing thickness of Lower Sequence deposits to E and NE reflects an increase of accommodation space in these areas. A disconformity separates the lower and upper Mishrif sequences, and represents the initiation of the flexural forebulge. The lower sequence (Mishrif mC, mB2) is characterised by a N-S oriented platform margin Shoal Complex, while during the upper sequence (Mishrif mB1, mA), a NW-SE orientation prevailed. The origin of the regionally deeper facies at the start of the Upper sequence reflects eustatic sea level rise, after which foreland basin tectonics significantly changed the paleogeography of the basin and enabled the rudist Shoal Complex to spread over a wider area. The Mishrif caprock at the top of the Upper Sequence represents a major regional exposure.
Alpine 1 tectonic activity, previously associated with the Khasib, Tanuma, Sadi and Hartha Formations in the region, actually initiated earlier, impacting the upper and to a lesser extent lower Mishrif sequences. The activity is interpreted in a foreland basin setting, with structural styles similar to but smaller scale than that seen later in the Alpine 2 Zagros emplacement.
Local structuration effects along pre-existing lineaments likely reactivated in different orientations due to the rotating stress fields. NW - directed push leading into Alpine 1 on N-S oriented structures may have resulted in transpressional strike slip related uplift. Such local uplift cannot however explain the observed facies stacking patterns, particularly in the Upper Mishrif.
This following case study details the methodology followed and challenges encountered while drilling in the Shakal Block of North Iraq. A narrow drilling window and geologically-associated problems in the first well, Shakal-1, were enough to demonstrate that non-conventional drilling techniques are needed to develop Shakal field potential. In case of Shakal-2 and Shakal-3 exploration wells, the 12-¼" and 8-½" hole sections applied Managed Pressure Drilling (MPD) technique and Microflux® control system technology to reach planned objectives and reduced a combined 15 days of drilling time, equating to associated cost savings of US$1.8MM.
The primary objective of drilling with these techniques in the Shakal field was to maintain the Equivalent Circulating Density (ECD) within the operative window and keep the downhole circulating pressure close to formation pore pressure in order to minimize nonproductive time, optimize drilling performance and minimize formation impairment.
In addition to the drilling objectives, MPD help was needed in order to safely facilitate trips to surface derived from normal scheduled operations as well as unprogrammed operations caused by tool failures or drilling problems; in some fields like Shakal, pulling out of hole can be equal or more difficult than the actual drilling operation.
All planned operating windows have some degree of uncertainty. In the cases of Shakal-2 and Shakal-3, Microflux control system technology detected early signs of influx and fluid loss when there was a deviation from the anticipated drilling window.
The flexibility of MPD technique during trips with Stripping Method showed high benefits on these holes sections along with accurate monitoring of well parameters for early detection of influx and losses.
The use of MPD contributed to significant time, cost savings and safety increment for the Shakal-2 and Shakal-3 in the 12-¼" & 8-½" hole sections.
Subsurface geological maps are perhaps the most important tool used to explore for undiscovered hydrocarbons and to develop proven hydrocarbon reserves. However, the subject of subsurface mapping is probably the least discussed in Abu Dhabi, yet most important, aspect of petroleum exploration and development. This paper presents the tectonic map for Abu Dhabi based on gravity, magnetic and seismic interpretations, along with describing the various elements, their controlling faults and their effect on basin development and also rationalizes previously published structural and tectonic elements to clarify the kinematic relations and naming of individual tectonic elements. The method, which combines geologic, geophysical data in a comprehensive way, incorporates these data to simulate the interrelated effects of deposition and erosion of sediments and compaction, pressure, petroleum generation and multiphase fluid flow. The tectonic map of Abu Dhabi distinguishes three principal tectonic cycles: (1) Precambrian cycles are interpreted using the magnetic data, as there are no wells that penetrated the basement in Abu Dhabi and the seismic is mostly covering up to Jurassic layers.
Mosola, Amanda B. (ExxonMobil Exploration Company Div. Exxon Mobil Corporation) | Braaksma, Kelley S. (ExxonMobil Exploration Company Div. Exxon Mobil Corporation) | Tai, Po C. (ExxonMobil Exploration Company Div. Exxon Mobil Corporation) | Volkmer, John E. (ExxonMobil Exploration Company Div. Exxon Mobil Corporation) | Grabowski, George J. (ExxonMobil Exploration Company Div. Exxon Mobil Corporation) | Kendall, Jerry (ExxonMobil Exploration Company Div. Exxon Mobil Corporation) | Liu, Chengjie (ExxonMobil Upstream Research Company Div. Exxon Mobil Corporation)
Evaluation of the depositional environments of Upper Cretaceous strata in the Balambo-Garau sub-basin of the Zagros Foldbelt in western Iran into eastern Iraq provides insight into the distribution of reservoir and seal units, as well as potential trapping configurations. Such mapping within the upper sequences of the Cretaceous suggests a larger impact of Proto-Zagros flexure and localized re-activation of deeper seated structural trends in Iraq and Iran. Environment of deposition and unit thicknesses have been mapped and evaluated across western Iran into eastern Iraq using well logs and biostratigraphic data. From the middle Turonian to Santonian, outer-shelf argillaceous limestones overlie proximal to middle- shelf limestones. The deepening of the sub-basin, part of a broader trend of platform carbonates and associated deeper shelf and basinal facies, is concurrent with eustatic sea-level rise, but may also be affected by large-scale Cenomanian-Turonian adjustment. Environmental belts narrow and deposits lap onto highs exposed by localized uplifts as a result of the reactivation of deep-seated structural trends originating in the Permian (or possibly basement?). Outer- to middle-neritic sediments of the Ilam Formation, which onlap local structural highs, are higher quality reservoir facies of Coniacian–Santonian age and, where sealed, may be potential traps.
Deposits of the latest Campanian to Maastrichtian also show deepening of lower-shelf and basinal environments within the study area. Non-deposition and onlap of deeper water carbonate wackestone to marls onto highs in the Dezful embayment may further reflect the localized reactivation of deeper seated structural trends. Siliciclastic sediments of the Tanjero Formation shed from highs to the northeast are associated with paleogeographic reversal of the Proto-Zagros, depositing turbidites within the proximal thrust-front basin. Despite time-equivalent prolific oil-producing reservoir intervals in Iraq, ongoing deepening due to the Proto-Zagros Foreland Thrust results in largely non-reservoir marl facies of the Gurpi Formation acting as a seal to the underlying units. The Tarbur Formation, present in the Fars region, consisting of shallow-water rudist grainstone and packstone suggests a lack of accommodation created in association with the Proto-Zagros subsidence event.
Tectonostratigraphic trends of the Upper Cretaceous of the Zagros region of western Iran and eastern Iraq show the transition of a relatively quiescent ramp increasingly affected by localized effects of the Cenomanian-Turonian adjustment along with the Maastrichtian inception of Proto-Zagros thrusting and elucidates their impact on reservoir, seal and potential trap distribution within proven and unproven hydrocarbon systems in Iraq and Iran.