Alcantara, Ricardo (PEMEX E&P) | Santiago, Luis Humberto (PEMEX E&P) | Fuentes, Gorgonio (IMP) | Garcia, Hugo (IMP) | Romero, Pablo (IMP) | López, Pedro (IMP) | Angulo, Blanca (IMP) | Martinez, Maria Isabel (IMP)
The Naturally Fractured Reservoirs (NFR) constitute a challenge for the oil industry due to its importance in hydrocarbon production and the technical complexity they represent, because well's productivity in carbonated formations is influenced by fracture systems that govern the fluids motion within reservoirs. This approach is oriented to the analysis of a very complex NFR, where we show the results obtained through a dynamic characterization methodology focused on new opportunities in a High Pressure-High Temperature (HP-HT) coastal mature oilfield with high water cut production. The proposed methodology is based on a full analysis starting from the pressure-production historical data, fluids properties, dualporosity material balance, a detailed static model update (petrophysics, core analysis, petrography, fracture analysis, sedimentology-diagenesis and structural geology), flow units discretization, Water-Oil Contact (WOC) advance monitoring in each block, Pressure Transient Analysis (PTA) (determination of preferential flow direction and interference), and Rate Transient Analysis (RTA). This methodology allowed to determine the real Original Oil in Place (OOIP) and the proper recovery factor according to the type of NFR and its characteristics, to detect different WOC's for each block that were hydraulically connected to each other but with a different dynamic behavior among them, the detection of heterogeneities, facies changes and faults that originally were not mapped, sweet spots location, better distribution of the petrophysical properties, fracture analysis, static model reinterpretation based on the dynamic behavior, reservoir connectivity analysis (among blocks) and the generation of improved production forecasts based on an exploitation strategy especially designed for the current conditions and needs of the field; all of this contributed to have a better understanding of the reservoir and a good numerical simulation model.
Lin, Tengfei (Department of Middle East E&P, RIPED, PetroChina) | Wang, Nai (Department of Middle East E&P, RIPED, PetroChina) | Wang, Weijun (Department of Middle East E&P, RIPED, PetroChina) | Li, Nan (Department of Middle East E&P, RIPED, PetroChina) | Yang, Shuang (Department of Middle East E&P, RIPED, PetroChina) | Liu, Yumei (Department of Middle East E&P, RIPED, PetroChina) | Dong, Junchang (Department of Middle East E&P, RIPED, PetroChina) | Zhang, Qingchun (Department of Middle East E&P, RIPED, PetroChina) | Guo, Rui (Department of Middle East E&P, RIPED, PetroChina)
Bioclastic limestone reservoir is playing a dominant role in the petroleum industry of Middle East. The oilfield in this paper belongs to long-axis asymmetric anticline. The S formation of Cretaceous period universally developed bioclastic limestone of carbonate platform system. It is the reservoir heterogeneity that severely limits the oilfield development.
We firstly analyze the lithofacies based on the core and thin section. Then the detailed well and seismic interpretation illustrate the sequence stratigraphy and facies analysis, and tectonic evolution are analyzed to restore sedimentary procedure from Palaeocene to late Pliocene stage. Ultimately, high quality reservoir of bioclastic limestone are depicted according to comprehensive analysis.
This paper offers reference and inspiration for bioclastic limestone reservoir: reef-beach complex and sweet spots in tidal-channel are dominant reservoirs for bioclastic limestone of Middle East.
The Kenshen tight gas field, located on the northern margin of the Tarim basin, western China, has extreme reservoir conditions of an ultra_depth reservoir (6500 to 8000 m) with low porosity (2 to7%), low matrix permeability (0.001 to 0.5 md), high temperature (170 to 190°C), and high pore pressure (110-120 MPa). Those conditions result in high completion costs and a significant difference in individual well production rates; with only one-third of wells drilled meets expectations. Previous studies focused on natural fracture(NF) and attempted to classify reservoir qualities based on the density of NF. Unfortunately, some NFs were closed or cemented by clay or calcite, and it is hard to distinguish open NF from closed NFs using well images in oil-based mud, which is widely used in this tight gas field for reservoir protection. Thereby, no positive correlation between NFs density and productions has been identified, even with the same stimulation treatment.
In this study, a comprehensive geological study was conducted to find a new way of characterizing the effectiveness of NF. First, the initial and development stages of NFs were recontructed through a tectonic activity study. Two stages were detected and showed different strikes. Second, petroleum system modeling technology was applied to simulate source rock maturation and gas migration, which revealed that gas generated in the Jurassic source rock migrated to the Cretaceous reservoir formation through faults activated in the same period as the late stage of NFs development. NFs developed earlier were closed or cemented by calcite of later deposition; those at late stage were open and effective for gas charge. Also in this study, Advanced analyses of borehole images indicated an alternative way to delineate NFs developed at different stages using geometry (i.e, crossed NFs shall include those ones developed at later stage). Parallel NFs with its development unidentified can be classified through the intersection angle of fracture strike and maximum stress direction. The smaller the intersection angle is, the easier it is for stimulation and alos the higher for the well production. Based on this study, we have divided reservoirs in the study area into three classes: class 1, reservoir with crossed NFs; class 2, reservoir with fractures of small intersection angle; class 3, reservoir with fractures of large intersection angle. This innovative reservoir classification through NF geometry is currently used in the field to determine formation stimulation method. Class 1 reservoir can benefit from acidizing alone with low completion cost. Class 2 reservoir of should be hydraulically fractured with acid. Class 3 reservoir of should be fractured with sand and proppant sand to achieve economical production.
Reservoir classification with NFs geometry had been applied successfully to guide stimulation design in the Keshen tight gas reservoirs. It is a practical and feasible way to choose the most appropriate stimulation treatment method to optimize well performance and avoid restimulation to reduce costs for this extreme type of tight gas field in western China.
Adams, Adeniyi A. (Baker Hughes, a GE Company) | Soliman, Ahmed M. (Baker Hughes, a GE Company) | Deng, Lichuan (Baker Hughes, a GE Company) | Jurdi, Imad (Baker Hughes, a GE Company) | Al Hosani, Mohamed Salem (ADNOC Onshore) | Al Menhali, Adnan (ADNOC Onshore) | Ardila, Jose David (ADNOC Onshore)
The challenge was to achieve more reservoir contact in a cretaceous tight reservoir to improve production and maximize recovery. Multilateral well campaigns were performed to meet these objectives.
This case study describes an effective workflow for performing openhole sidetracks in this challenging medium-hard carbonate formation. The workflow maintained reservoir contact and achieved the desired production objectives.
Two 6-in. multilateral drain sections were successfully drilled by performing openhole sidetrack using the continuous proportional steering method (CPSM). This method is not new to the industry, but this case study describes the systematic, unique workflow that was designed and followed to ensure a successful sidetrack in this low-porosity, hard formation.
The sidetrack implementation started by creating humps at inclinations ranging from 88 to 91 degrees into the formation in the original 6-in. section. These humps were confirmed using near-bit inclination data (4.5 ft from the bit) and were identified as the sites for initiating a sidetrack. This paper discusses the best practices that were key to the successful execution of the project in one run on the first attempt.
After the sidetrack, use of appropriate combinations of shallow and deep logging-while-drilling (LWD) measurements in the same bottom hole assembly (BHA) enabled the direct geosteering of the well, exposing more reservoir surface area than planned.
A reduction of 10% from the planned well duration was achieved. Two 6-in. laterals, each approximately 4000 ft, were drilled in a single run and 100% reservoir contact was achieved.
This experience proved that planning and precise execution could enable drilling of openhole sidetracks, even through hard formations. These sidetracks can then achieve fishbone wells with desired reservoir contact and realize the field development objectives in a technically robust and cost-efficient manner.
CPSM does not rely on a pressure drop for steering. Although this proof of concept was performed in a relatively hard formation, similar workflows with appropriate drilling engineering may be applied to less-competent formations as well. The detailed procedure and flowchart created from the experience with the sample well can be adopted for use in similar applications.
The sandstone facies of Wara formation designated as Ac zone in the Bahrain Field belongs to the Wasia group of the Middle Cretaceous age.
The reservoir has been characterized in three distinct geographical areas of sand distribution based on varied depositional systems, resulting in sands with differing orientation, texture and thickness. The reservoir varies in thickness between 5 and 60 ft and is composed of a series of discontinuous high porosity, high permeability sandstone lenses, sealed above and below by thick competent marine shales.
This paper addresses the variability of the reservoir and the connectivity with the underlying Mauddud reservoir which consequently determined the drive mechanisms.
The original oil in place of Wara sandstone was calculated deterministically using a 3D geological model and incorporated both Geophysical and Petrophysical models. Initial water saturation was calculated from capillary pressure data with net sand cut offs applied. The discontinuity of the sands has resulted in individual sand bodies with variable oil water contacts. Thinner sand bars and channels in the northern area of the Bahrain Field produce by depletion drive. Juxtaposition with the underlying Mauddud reservoir occurring across the faults allows communication with Mauddud gas cap in the Central area which results in the gas drive. Water drive is the main mechanism in the South channel.
Recent log data acquired from new wells has improved our knowledge of this reservoir and explains the different oil-water contacts with the varying drive mechanisms. This improved understanding has resulted in a new development strategy to maximize recovery with infill drilling and possibly Enhanced Oil Recovery (EOR).
The Cliff Head is one of the most significant discoveries in the offshore Northern Perth Basin. Hence, understanding the structure and geology of the field is essential to further evaluate the offshore region in the basin. Two structural models were developed with the objective to achieve a better understanding of this field. The first model is focused on the Permian and older strata, while the second model is for the overburden. In addition, reservoir properties models (e.g. porosity model and water saturation model) were developed to better understand the reservoir facies and hydrocarbon distribution. Examination of the structural models has shown that there are two main sets of faults within the Cliff Head area, which can be categorized into the following: the deep Permian faults that are truncated against the Late Permian unconformity, and younger Cretaceous faults that were developed during the Early Cretaceous rifting. It has also shown that the oil accumulation within the field is structurally trapped within Permian aged set of horsts and is mainly reservoired within the Irwin River Coal Measures. The secondary target (e.g. the underlying High Cliff Sandstone) is mostly beneath the regional oil-water contact of −1257.8 m TVDss, except in the highest structural point in the field, where Cliff Head-6 was drilled. The Irwin River Coal Measures in the study area contained four high resolution depositional sequences that displayed a finingupward pattern as depicted by the Gamma Ray log response and are interpreted to have mainly deposited in a fluvial depositional system. The High Cliff Sandstone, in contrast, contained two high resolution depositional sequences that displayed a coarsening upward sequences as supported by Gamma Ray log response and were interpreted to have mainly deposited in marginal marine settings. Reservoir properties modeling was also conducted utilizing the 3D models, where a 3D porosity model was calculated and shows that the Irwin River Coal Measures, in general, exhibit higher porosity distribution than the underlying High Cliff Sandstone, even though the later has coarser and more laterally extensive sand sheets. This is probably attributed to diagenetic porosity reduction within the High Cliff Sandstone caused by the formation waters. The calculated 3D water saturation model also confirms the presence of a single regional oil-water contact within the field and hence, reservoir heterogeneities and fault seal capacities did not affect the hydrocarbon distribution within the field. Finally, all the calculated models (e.g. lithofacies model, porosity model, and water saturation model) were integrated to estimate the recoverable hydrocarbons in place, where the Cliff Head is estimated to contain a total of 15.2 million barrels.
Al-Shuaib, Sarah (Kuwait Oil Company) | Al-Bader, Haifa (Kuwait Oil Company) | Al-Salali, Yousef (Kuwait Oil Company) | Abdel hameed, Waleed (Kuwait Oil Company) | Ahmad, Hanan (Kuwait Oil Company) | Al-Dousari, Sarah (Kuwait Oil Company)
Comprehensive and fully-integrated analyses were performed on the first discovery in Zubair formation of lower Cretaceous age at Bahrah field in North Kuwait with objective of assessing HC potential, well performance, reservoir characteristics and verify connectivity between reservoir flow units.
Based on petro-physical evaluation of OHL, bottom-hole samples, and RDT pressure points two flow units within Zubair reservoir were identified. The OHL showed that these two zones are separated by thin shale strikes additionally; the resistivity against the upper zone showed possibility of being water. Therefore, it was decided to test the two reservoir units separately.
Subsequently, after two successful production tests, analyses of well production performance including Nodal Analysis, PVT, RDT and PTA were carried out for both zones in order to assess reserve potential, obtain essential reservoir rock & fluid characteristics and verify vertical connectivity.
Remarkable oil discovery was made in Zubair reservoir of Bahrah field with substantial addition of proven reserves and commercial production potential, which will definitely support achieving the strategic production target. In order to verify long-term production sustainability, Extended Well Testing (EWT) was conducted. The results showed that this reservoir is capable to produce Hydrocarbon in a sustainable manner. Production Performance, PVT, RDT, PTA and Nodal analysis results showed that the two tested zones in Zubair reservoir are interconnected with same fluid characteristics and it can be considered as one reservoir even though the open-hole logs responses showing that they could be different reservoirs.
This paper will present detailed comprehensive engineering and geological analyses of first Zubair oil discovery in Bahrah Field at North Kuwait. All available structural, petrophysical, PVT and production information were used to develop static model by Petrel-RE and subsequently, detailed data acquisition, appraisal drilling and conceptual field development plans have been established.
The unexpected response of the Mauddud water flood project led to a detailed review of the petrophysical and geological aspects of this mature cretaceous carbonate reservoir. With almost 2,000 wells, more than 1,000 of which were recently drilled and three cored, the review assessed an extensive data base of openhole, production, saturation log, and historical geological data. The findings resulted in an improved understanding of this reservoir, which historically had been described both as homogenous - fractured and heterogeneous - layered. An understanding of Mauddud's key geological features, their formation, and a link to the observed petrophysics provided the key to developing an innovative permeability transform from resistivity logs, which explained the reservoirs response to the water flood project. With production permeability up to fifty times the measured matrix permeability from core, porosity log derived permeability had failed to reflect the fluid production observed. The adoption of a saturation and production based method provided a useable permeability profile that appeared to explain the observed well and pattern production behavior of the water flood. The new permeability profile also explained both historical fluid behavior and other Enhanced Oil Recovery (EOR) projects, and has since been universally adopted for the reservoir. The permeability estimation technique, which uses resistivity log data, was tested in another infield reservoir with success, and it is thought that the technique has general applicability across many Middle East carbonate reservoirs.
In the current and future scenario of increasing demand for hydrocarbons, Multi-Disciplinary Integrated Reservoir Management team is the key to achieve maximum production rates and ultimate recovery. In Raudhatain Upper Burgan reservoir production started in 1959 with initial reservoir pressure of 3850 psi. Decline in reservoir pressure with sustained rate of production indicated weak aquifer support and initiated water injection during the year 2001 with three flank injectors. Production rate was sustained at 30 to 35 MBOPD for long time and it was decided that to go the next level of production and to meet KOC's strategic production target.
Various alternative pressures – production plans were scrutinized by the multi-disciplinary team consists of Geologists, Reservoir Engineers, Petrophysicists and Petroleum Engineers and identified bottlenecks, constraints and action plan to address the problems and to accelerate the production. Some of the bottlenecks to accelerate the production were decreasing pressure, unavailability of required volume of water for injection, delay in commissioning of effluent water injection facility and low productivity of flank wells with viscous oil. The integrated Reservoir management team initiated number of projects to increase the productivity like Paradigm shift in drilling practice by way of drilling Horizontal, Multilateral wells and completing with ICD's for better production and injection sweep efficiency. Liquidated the sick wells with no potential in any other Reservoirs (Multiple Reservoirs) are identified for Horizontal Sidetracking to sweet spot areas. Decreasing Reservoir pressure and Voidage Replacement Ratio has been addressed by changing the water injection strategy and aligning the injectors in right areas.
The results were rewarding as the production rate doubled from a sustained level of 35 MBOPD to more than 70 MBOPD in a span of 3 to 4 years. The initiatives taken to convert the producers to injectors resulted in increased water injection volume and doubled the Voidage Replacement Ratio.
This paper presents the details of Integrated Reservoir Management team efforts and what are the initiatives and strategic actions taken by overcoming the current constraints to double its production. It discusses the effective Reservoir Management of a mature oil field to enhance and accelerate production.
Padhy, Girija Shankar (Kuwait Oil Company) | Al-Rashidi, Tahani (Kuwait Oil Company) | Gezeeri, Taher Mohd (Kuwait Oil Company) | Shinde, Ashok (Baker Hughes, a GE Company) | Perumalla, Satya (Baker Hughes, a GE Company) | Zhou, Chong (Baker Hughes, a GE Company, presently with Petronas)
The subject upper Cretaceous carbonate formation has been characterized as a heterogeneous reservoir with varying facies and petrophysical properties. Distribution of facies strongly varied not only with depth, but also laterally across the field. Upper part of the reservoir is dominated by natural fractures whereas lower part is predominantly argillaceous with mud enrichment. In addition, presence of laminations and vugs enhanced the heterogeneity of the reservoir. Very few wells were drilled and some of them were fractured. This paper demonstrates how geomechanical and integrated reservoir characterization has shown value in well placement strategy.
Built number of well-based geomechanical models with data from all wells in order to capture reservoir heterogeneity in models. These models quantified the distribution of rock mechanical properties and pore-pressure as well as present day principle stresses. In addition, these models were integrated with geological model as well as seismic data to generate a 3D geomechanical model. After a thorough rock typing and petrophysical classification, some patterns were recognized in terms of presence of natural fractures in certain layers. However, the production contribution of these natural fractures was unclear. Upon combining all available sensitive fracture indicators, a DFN model was built and calibrated. Finally, the 3D geomechanical model combined present day in-situ stress and pore pressure magnitudes, mechanical properties of all rock facies and natural fracture occurrences at field scale. A thorough well production analysis was also performed to validate the role of natural fractures during production.
After systematic integration of diverse sub-surface data sets in 3D geomechanical model, some natural fracture subsets were identified that are optimally oriented to become critically stressed at present day stress regime. Upon further analysis, a new parameter "Index of Critically Stressed Fractures (iCSF)" was created that captured the spatial distribution of networked fracture sets in 3D model that are geomechanically favorable for fluid flow. Number of geomechanical sweetspots were identified at field scale and correlated these areas with other data. It was also recommended to stimulate wells with certain practices.
Integration of geomechanical models with production analysis and natural fracture indicators delivered value in identifying geomechanical sweetspots that have potential to flow. Distribution of these sweet spots provided a strategy for well placement as well as stimulation. In addition, this paper also exhibits logical integration of findings from geosciences and engineering disciplines to make informed decisions on well planning in order to maximize the production from challenging reservoirs.