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Noufal, Abdelwahab (ADNOC - Upstream) | Obaid, Khalid (ADNOC - Upstream) | Al Blooshi, Abdulla (ADNOC - Upstream) | Nehaid, Hani (ADNOC - Upstream) | Basioni, Mahmoud (ADNOC - Upstream) | Alward, Wassem (Schlumberger) | Uruzula, Jaja (Schlumberger) | Shamsal, Sudipan (Schlumberger) | Dasgupta, Suvodip (Schlumberger) | Raina, Ishan (Schlumberger) | Schlicht, Peter (Schlumberger)
Carbonate reservoirs of the Middle East are known for exhibiting highly heterogenous nature in terms of reservoir properties within microscopic intervals of the reservoir, making it difficult to characterize and predict. An integrated approach involving detailed understanding of the fluids volumes porosity distributions, permeability systems, rock textures, reservoir rock types, and natural fracture distribution at different scales is needed. Accurate characterization for the flow networks, complicated by fracturing and diagenesis is fundamental to achieving realistic prediction, better production performance, and increased recovery. The rock texture in carbonate reservoirs is very unstable and continuously undergoing to multiple stages of dissolution, precipitation, and recrystallization, which obscures any relationships that might have existed between depositional attributes, porosity, and permeability. Fractures make it more complex with their different morphology, often further convoluted by leaching through them. Different measurements are needed to build a realistic model of the petrophysical properties of a carbonate formation. The standard resistivity and porosity measurements are often not sufficient to resolve changes in pore size and texture, so additional measurements are required. Workflows using borehole images can be used to extract information on different textural elements and porosity types. With the newly introduced workflow secondary porosity types are distinguished from matrix porosity and proxies for permeability are calculated.
This workflow integrates borehole images and other petrophysical data in sequential steps and provides important reservoir parameters. With the suggested analytical workflow, it is possible to classify the different types of pore space such as connected to vugs (vug to vug), isolated, connected to fractures, aligned at bed boundaries, or within the rock matrix. The contribution of these different pore types to the total porosity of the formation is quantified in addition to the geometric information of different types of heterogeneities. In addition, the connectedness of the different types of porosity is quantified. The connectedness log describes the quantity of connected spots detected from the electrical borehole image and is used as a predictive measure for identifying zones of higher or lower permeability. During operation it serves as an indicator for determining the perforation intervals, in static reservoir modeling it serves as a permeability driver to improve reservoir mapping. We demonstrate an example where the connectedness successfully predicted productive zones, proven by production logging.
Noufal, Abdelwahab (ADNOC Upstream) | Obaid, Khalid (ADNOC Upstream) | Al Blooshi, Abdulla (ADNOC Upstream) | Basioni, Mahmoud (ADNOC Upstream) | Nehaid, Hani (ADNOC Upstream) | Guerra, Julian (Schlumberger) | Liu, Yaxin (ADNOC Upstream)
The stress field is a complex variable that affects all drilling operations, completions and reservoir performance. From the three components of a non-rotated stress field, the maximum horizontal stress is the more difficult variable to model since cannot be directly measured and involves multiple unknowns. This study presents an advanced geomechanics modeling technique to estimate the most likely horizontal stresses by integrating advanced acoustic measurements, multi-well image interpretation and geomechanics back analysis.
The study was carried out in SR wells, a new development zone in the UAE, which targets the fractured and medium porosity reservoirs rocks of Late Permian formation. The estimation of the stress field is necessary not only for well planning but also to understand the occurrence of abundant drilling induced fractures that sometimes mask the natural ones. It will help also to propose location of possible fracture treatments while analyzing possible relationships between fluid flow and the presence of critically stressed fractures.
The horizontal stress field was inverted from advanced geomechanics modeling including the elimination of the gas effect, inversion of Shmax from 3-Shear moduli analysis in stress sensitive intervals, image interpretation for stress related and intrinsic features, determination of stress regime Q-factor from Integrated Stress Analysis (ISA) and performing a failure analysis to validate the stress field and calibrating the overall geomechanical model. The calculated maximum horizontal stress from 3-Shear moduli, ISA and failure analysis proved to be consistent in both SR wells, where the Normal stress regime agreed with current structural framework and local geology. The stress direction was also consistent among measurements, although some local stress rotations were observed in specific zones. High angle features such as drilling induced and natural fractures were also consistent with the modeled stress field, where the vertical stress is the maximum principal stress. Mud losses were mainly attributed to the presence of vugs, conductive seams and fracture corridors rather than induced fracturing.
The inverted stress field was finally used as input in the Completion Advisor and Fracture Stability workflows and then compared against PLT data in. The results show a good correlation between critically stressed fractures and well productivity in SR wells. The last could lead to optimize the completion strategy in future wells by selecting best intervals for perforating and stimulation based in this integrated approach.
Barata, J. (Abu Dhabi Company for Onshore Petroleum Operations) | Vahrenkamp, V. (Abu Dhabi Company for Onshore Petroleum Operations) | Van Laer, P. J. (Abu Dhabi Company for Onshore Petroleum Operations) | Swart, P. (RSMAS University of Miami) | Murray, S. (RSMAS University of Miami)
Clumped isotope geochemistry of calcite minerals measures temperature independently of the isotopic composition of the precipitating water, allowing in combination with basin modeling to define the depth and timing of major diagenetic events. This technique has been applied to a regional selection of samples from the most prolific Thamama reservoir unit in Abu Dhabi in an attempt to further constrain the creation of the micro-porous system that volumetrically dominates the pore system of the reservoir.
A total of 38 samples from 8 crest wells in 8 different fields from onshore Abu Dhabi were analyzed, indicating precipitating temperatures of 47°C to 110°C, and diagenetic water isotopic composition of 0.2‰ to 5.6‰ d18O. Carbon and Oxygen stable isotope values are in line with existing values for this reservoir (-9.17 to -5.27 d18O; 2.99 to 4.10 for d13C).
From the same cores and at the same depth as the 38 samples, thin sections were created for a semi-quantitative petrographic analysis to provide further insight on ?47 temperature variations. Samples with a higher volume of intraclasts have lower temperature of precipitation while samples with higher volume of diagenetic cement show higher temperatures of precipitation. Cutoffs were applied to filter out these early and late diagenetic overprints.
Using the existing basin model, ?47 temperatures translate into a depth for diagenesis of between 610 and 1370 m and an Upper Cretaceous age. Both the range of temperatures and depths reflect differential transformation of the individual structures during the late Cretaceous caused by the emplacement of the Semail Ophiolite. This is in agreement with a recently proposed regional burial diagenetic model (
The results show that the effects of deep burial diagenesis are present throughout the Abu Dhabi region and that a strong regional burial flow system is controlling the evolution of the poro-perm system. An understanding of this large scale fluid-flow system is important in resolving issues related to the regional distribution of reservoir properties.
Drilling activity in the deepwater fold-thrust belt of Southeast Asia has expanded greatly and has quickly become recognized as one of the five proven deepwater oil regions in the world. Unfortunately, drilling hazards linked to pore pressure (PP)and wellbore stability problems are persistent, such that drilling costs as high as USD 100 million (as of 2014) are not uncommon. This study reviews the distinct geological nature of overpressure characteristics in the deepwater fold-thrust belt of Sundaland continental margin, SE Asia, and then subsequently presents a better PP prediction strategy that properly honors the regional characteristics.
Effective stress-based PP prediction is reviewed in depth to highlight its drawbacks. The drawbacks become especially prominent when the assumptions of the established method, particularly assumptions of the porosity-based normal compaction trend, are applied deliberately in the deepwater fold-thrust belt of Sundaland continental margin without sufficient adjustments.
It is successfully demonstrated that the absence of a normally compacted section of DTFB-SCM is linked to rapid sedimentation of low permeability sediments; tectonic shearing is the central cause of the common underestimation of the popular effective-stress based pore pressure prediction method; and the dominance of compressional geological structures explains the high likelihood of the centroid effect. Best practices are proposed as guidance for PP practitioners to steer away from blindly following industrial assumptions and carefully apply a more geologically sound PP prediction approach.
Deepwater exploration and production in SE Asia has grown rapidly and has become a major component of the petroleum industry’s upstream budgets (Algar, 2012; Weimer and Pettingill, 2007). Furthermore, northwest and east Borneo is regarded as one of five proven deepwater oil regions in the world as a result of major discoveries that have taken place in the past 15 years (Weimer and Pettingill, 2007). However, many problems encountered while drilling into prospects have discouraged further development of deepwater plays despite the positive future outlook (Kirchner, 2005; Kaeng et al., 2014). In northwest Borneo in particular, operators have encountered many subsurface hazards related to PP and wellbore stability that have often led to the failure of some wells to reach geological targets and have increased drilling costs to as high as USD 100 million (as of 2014).
This paper illustrates an innovative field-scale application of injecting condensate gas and recycling gas in Jake field, Sudan. This field has two production series, namely AG condensate gas pools and Bentiu oil pool from bottom to up, with the former 3520 ft. below the Bentiu reservoir and 1695 psi of initial reservoir pressure difference. Bentiu pool of Jake field is a medium crude oil (29 API) pool with strong aquifer support. Well productivity was 500 BOPD. Operator intended to inject high-pressure condensate gas into Bentiu pool to increase field output, whereas was confronted with following challenges: 1) injection of condensate gas in an easy-to-operate wellbore configuration; 2) optimization of injection parameters to achieve highest output; 3) suppress aquifer water breakthrough.
Field scale application had been optimized and implemented since 2010:1) High-pressure condensate gas had been injected into two updip crest Bentiu wells in the same well bore, following a huff-and-puff process, well output amounted 4,000 to 13,800 BOPD under natural flow; 2) 1/4 recycling gas volume from compressors was re-injected into 12 downdip wells at controllable pressure to avoid early water breakthrough; 3) The remaining recycling gas was utilized to gas-lift other five updip wells.
Oil producers were reduced from 19 to 7 comparing to original field development plan, while oil rate ascended from 22,000 to 30,000 BOPD, with watercut dropping to 7% from 15%, achieving a high offtake rate of 6%. Reservoir simulation indicated ultimate recovery factor is expected to be over 50% with such full-field gas injection.
Conclusions drawn from field scale injection of condensate gas and recycling gas were as follows:1) condensate gas injection in the same well bore was technically innovative and operationally robust; 2) recycled gas injection into downdip wells helped detain water breakthrough; 3) field scale application had evidenced outstanding success with high output and high offtake rate.
An integrated reservoir study was initiated to look for new opportunities in East Zeit field. The working team managed to construct the full field static and dynamic models. The main challenge during the history match phase was the high complexity of the structure, range of uncertainties, and the model running time. The team managed to understand unconventional reservoir aspects such as:
(1) The reservoir pressure was sharply decreases as production increases. Then, when the reservoir was abandoned as a depletion drive reservoir the pressure started to increase up to initial reservoir pressure without any intervention.
(2) The performance of few wells completed in the above mentioned reservoir was similar to the performance of wells in active water drive reservoirs.
Comprehensive work in the history match has been done to calibrate the model and explain the different phenomena in the field. The team explained the pressure increase in the depleted reservoir that it was due to the reactivation of faults which became non-sealing. This resulted in communication with another active water drive reservoir and natural miscibility process. The study recommended adding new off take point in the reservoir to confirm the concept. So, a new well was drilled and confirmed the study conclusion and managed to add more reserves and production in the rejuvenated reservoir after 12 years of shut in. Currently, constructing complete field development plan is in progress to maximize the recovery factor. Reservoir monitoring even after abandonment, especially with unconventional reservoir aspects, is very important to discover new opportunities and maximize the recovery. These opportunities should be managed through the integrated reservoir simulation studies to minimize the risk and cover the uncertainties.
The East Zeit field (EZ) is situated in the southern Gulf of Suez (GoS) in about 240 ft of water (Fig.1). The oil accumulation in the field covers an approximately 27 km2 area. The field is composed laterally of two major fault blocks; the main fault block (MFB) and the east fault block (EFB). Moreover, each major fault block is sub-divided into smaller fault blocks which reflect the complexity of the highly faulted structure. Each major fault block is sub-divided vertically into three main reservoirs (Fig.2). The field was started production in 1985 through two platforms; the wells were flowing naturally in the past and currently some wells are producing by artificial lift and other wells are still flowing naturally.
Copyright 2010, Society of Petroleum Engineers This paper was prepared for presentation at the SPE Annual Technical Conference and Exhibition held in Florence, Italy, 19-22 September 2010. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright. Abstract This paper summarizes the application of data mining techniques and neural network multi-variable analysis to evaluate critical parameters impacting well performance and optimize hydraulic fracture treatment design for tight gas well completions in the Pinedale Anticline field in western Wyoming. Challenges and uncertainty associated with single variable analysis are discussed with consideration of the complexity of reservoir parameter variability and nonsequential coincident completion variable modifications. Neural network model development is summarized with emphasis on applications for well performance evaluation and hydraulic fracture treatment optimization.
Aloodari, S. (Mining Engineering Department, Science and Research Branch, Islamic Azad University) | Noorani, R. (Metra consulting engineers Co) | Ahangari, K. (Mining Engineering Department, Science and Research Branch, Islamic Azad University) | Naeimi, Y. (Mining Engineering Department, Science and Research Branch, Islamic Azad University)
Proppant fractures along the horizontal laterals in the Valhall Field have become a standard completion method for the last eight years with over 150 proppant fractures completed to date. The development of the flank regions of the Valhall Field began, with the first of 14 wells completions, in March 2003. Lateral lengths of up 2,000 meters will be drilled from two new platforms placed on the North and South edges of the field. The chalk formation in the flank regions is expected to be more competent then the crestal part of the field, so the question was raised as to whether fracturing should be done with acid or proppant. From a proppant fracturing perspective, each flank well will require between 10 to 14 prop fractures along its lateral requiring 2.5-3.7 Million pounds of proppant per well.
Three different methods have been used to determine whether the wells should be acid or proppant fractured. These consist of reviewing the historical well performance, analytical and numerical modeling. All three methods clearly showed proppant fracturing was the preferred stimulation for the Valhall Field regardless of it's location. Acid fracturing becomes the stimulation of choice only if the well does not come in contact with enough OOIP (e.g. 5 MMSTB) to justify the proppant fractures.
Proppant fracturing is expensive, so in conjunction with identifying the best stimulation method for the flank region, optimization with respect to fracture spacing along the horizontal lateral, fracture length and width have been numerically modeled for both the crestal and flank wells. This is an evolving process that should be considered an industry "Best Practice" as it enables real time optimization of ‘prop' fracturing along a horizontal lateral during the drilling and completion phase. Since the start of this "Best Practice" in 2002, the wells stimulated in the crestal part of the Valhall Field have had the highest productivity in the field's history.
This paper describes a team approach adopted on Valhall to limit the occurrence of wellbore instability, lost circulation and stuck pipe problems by the development and implementation of field-specific operational practices while drilling in the Overburden. It will highlight the benefits of an 11-3/4" application specific liner that has been upgraded from a contingency liner to a planned intermediate liner in the drilling programme. Details will be presented explaining the importance of planning for success and dedicated offshore engineering support. Knowledge management tools and processes were used to help refine these procedures and practices over a period of 24 months.
During this time one key performance indicator, Dry Hole Days /10000ft has been improved by approximately 40% in wells drilled at an inclination higher than 50 degrees through the overburden. More importantly, the primary goal of setting 9 5/8" casing in the reservoir has been achieved successfully in the last 6 wells when previously failure to accomplish this was common.