Karachaganak field, brought on stream in 1985, is one of the largest accumulations of gas-condensate in the world. Located in the northern Pre-Caspian Basin (Kazakhstan), the field is a Permo-Carboniferous isolated carbonate platform, with a hydrocarbon column of about 1500 m.
The current development focuses the oil rim with gas injection in a confined area of the Platform Interior implemented since 2004. Among the future development scenarios under consideration, an increase of gas injection in different areas of the field was evaluated with the scope of maximizing liquid recovery and keeping the production plateau. The internal reservoir architecture is indeed very complex: an initial development of aggrading mounds is followed by prograding clinoforms passing to cyclic, grain-dominated platform interior sediments. The resulting reservoir quality is quite heterogeneous, with low porosity, but locally high productivity when affected by micro-fractures and vugs. The analysis was performed considering both incremental volumes of injected gas and the uncertainties affecting the reservoir to obtain a ranking which takes into account additional liquid recoveries and relevant risks. Eventually, the analysis led to a proxy function which, through a mean-variance optimization approach, was used to estimate the most favourable gas injection configurations, reaching the best compromise between recovery and uncertainty.
In conclusion, the analysis highlighted pros and cons for each reservoir area, offering a better view to optimize the future development. The depositional region where the injection was already implemented appears to be a good candidate; other areas, although affected by a certain degree of uncertainty, are also promising from the recovery point of view, while some other regions, characterized by high compartmentalization, seem to be less interesting.
The Western Desert in Egypt has multiple fields in which most wells are artificially lifted. Wells with ESPs represent the major percentage of oil production by volume in that area. ESP run life is a principal criteria that is typically evaluated before the initial design and throughout the well's life time. Most wells are remotely positioned from one another and from the main gathering stations (2 to 8 Km. approximately). This is one of the major challenges when trying to maximize uptime and reduce the production deferment.
Operational issues including power supply and capacity limitations as well as changing inflow conditions can have negative impact on the ESP run-life, predominantly caused by excessive trips and shutdowns. Also such trips will result in lengthy downtimes due to the remoteness of the wells. On the production side, these trips will ultimately have a major effect on production targets due to intermittent deferment.
ESP wells connected to real-time monitoring and surveillance systems incur less lifting costs because of proactive responses and early detection of incidents. Systematic alarms along with pro-active remedial actions can minimize such preventable trips while maintaining the integrity of the ESP, eventually extending its run life.
This paper discusses a number of case studies showing how the implementation of such system prevented trips in some situations and allowed making key decisions and recommending remedial actions to optimize the ESP operation.
OMV and ADNOC commissioned WesternGeco to acquire a high fold, high density seismic program in the Foreland of the Oman Mountains, west of the city Al Ain. The objective of the survey was to acquire high quality 3D seismic data for a proper delineation and reservoir characterisation of structural and stratigraphic trapping geometries in order to identify potential exploration drilling locations.
The acquisition commenced Mid-2014 and was completed by early 2015. The program included two separate 3D areas covering 1800km². In addition, 700km of infill 2D lines were recorded to connect the two 3D surveys with modern 2D seismic and to complement the existing vintage 2D seismic grid. The seismic surveys were recorded with a Single Source Single Sensor design (4S) using WesternGeco's UniQ seismic acquisition system with single sensor geophone accelerometers (GACs) and single 80,000lb DX-80 vibrators. A Maximum Displacement Sweep was designed to enhance especially low frequencies resulting in a broadened amplitude spectrum. Operating up to 15 vibrators simultaneously allowed a very efficient seismic data acquisition but needed the implementation of the correct separations and slip times to ensure the data was not contaminated. The 18sec custom designed broad bandwidth sweep (1–120Hz) enhanced the S/N ratio in general and improved the data quality of the deeper target levels due to the input of low frequencies (below 10 Hz).
Sufficient azimuth, high fold, long offsets, broad bandwidth as well as optimum random noise reduction and increased spatial resolution was required to improve data quality. Therefore gaining more value with advanced seismic attribute analysis and enhancing the illumination of deeper zones in order to meet the objectives of the seismic.
On the logistical side, high flexibility was needed to allow complex and dynamic fleet grouping to maximize productivity. Any cross-talk noise between two different sources was managed using Managed Source and Spread (MSS) time and distance rules, which were based on the target characteristics. Acquiring dense 4S seismic required detailed planning to ensure operational safety and to achieve the planned fold coverage, especially in areas of dense infrastructure. The processing sequence for the high fold, high density 4S pre-stack seismic totalling 160 TB of data – 16 billion traces, was designed to effectively remove noise and preserve signal fidelity in the pre-stack data to ensure an optimal imaging and resolution of the geological targets. Due to the dune environment in the area, the application of optimal static solutions was an essential processing step. The good sampling of the noise in the raw data by the high density and high fold acquisition enabled a successful noise suppression performance and resulted in improving the image of the geological signal.
Le Calvez, J. (Schlumberger) | Zhang, J. (Schlumberger) | Harrasi, O. (Petroleum Development Oman) | El-Taha, Y-C. (Petroleum Development Oman) | Yarubi, S. (Petroleum Development Oman) | Busaidi, S. (Petroleum Development Oman) | Eltilib, M. (Schlumberger) | El Gihani, M. A. (Schlumberger) | Al-Wadhahi, T. (Schlumberger)
Microseismic monitoring has become a standard industry technique to monitor stimulation effectiveness as it provides information as to the length, height and orientation of the mapped hydraulically-stimulated fracture network and surrounding formations. In some cases, focal mechanisms may be extracted as well, providing additional insight into the geomechanical behavior of the reacting formation in relation to the spatial and temporal evolution of the hydraulically-stimulated fracture network.
Though there is much to learn from the interaction between sensor selection, survey design, operation, etc., in this work, we focus on the surface processing of a microseismic monitoring campaign performed in the Sultanate of Oman in 2015 ultimately comparing surface-derived results with downhole-derived results and the impact of joint inversion combining both surface and downhole data.
Given the operation parameters (e.g., wells to be monitored, formation velocities, spread limitations, completion schedule, and monitoring objectives) a pre-job modeling exercise took place to design the most effective surface and downhole monitoring array configuration. On site surveying was carried-out to ensure all health, safety and environment-related aspects were covered prior to and during the acquisition over a 67-day-long period. At the end of each stimulation, datasets acquired were processed in the office prior to results interpretation and integration with multi-domain data.
For the data acquired with the surface array, processing steps start with pre-processing including noise conditioning (e.g., filtering and spectral whitening) and grouping (i.e., stacking and beamforming). An iterative velocity model building and calibration exercise is performed using an initial model derived from well logs, surface surveys, check-shot data and, picking of accurate perforation shot timing (and large magnitude events). Events are detected and located using a source scanning approach prior to be manually inspected and relocated as needed during a quality check and editing phase. Additional refinement of the hypocenters takes place during the moment tensor inversion exercise prior to a final quality check and editing. Both a linear (detection) and an iterative (inversion) workflows are used to ensure optimal event location accuracy and moment tensor inversion.
Final results indicate that overall hypocentral locations derived from the surface array and the downhole array match relatively well. The integrated processing results show good agreement with the downhole-only results in the vertical dimension. Though some stages do not yield many events for reasons to be investigated (i.e., processing vs. rupture mechanism vs. completion scheme, etc.), overall mapped hypocenters highlight features aligning with the overall N50 maximum stress direction confirming the drilling pattern implemented and providing additional insight as to potential improvements. Some stages do not locate exactly where expected bringing additional value to the overall monitoring exercise and calling for in-depth understanding of the formation behavior. Moment tensor results come from the surface data only, highlighting predominantly strike-slip events with some elements showing large opening components.
Future monitoring campaigns are considered using improvements provided by recently gained information (e.g., spatical noise pattern, energy radiation, effectiveness of channel count and distribution, etc.)
Otevwemerhuere, J. (Addax Petroleum) | Nwosu, C. (Addax Petroleum) | Olare, J. (Addax Petroleum) | Jefford, Leigh (Addax Petroleum) | Parkins, Steve (Addax Petroleum) | Cavalleri, C. (Schlumberger) | Shrivastava, C. (Schlumberger) | Espinosa, H. (Schlumberger) | Mougang, M. (Schlumberger)
Low resistivity low contrast (LRLC) reservoirs have been successfully produced for many years; however detection and detailed description of their properties and potential would remain a challenge in absence of an exhaustive formation evaluation program. Proper understanding of the geological evolution of such reservoirs to explain their distribution and variations in petrophysical properties is also vital.
Low resistivity pay reservoirs encountered in West Africa are often characterized by variation in resistivity values in vertical and horizontal directions due to fine grains and conductive layers within the coarse grained sands and clearly marked sand-shale laminations. This is accurately solved by tri-axial induction resistivity measurement in combination with high resolution measurements able to define any contributing layer level-by-level through robust anisotropic interpretation methods. However, heterogeneity, mixed clays effect, and complexity in rock texture require new technology and innovative interpretation models in multi-domain approach.
Advances in logging technologies, interpretation software, and analytical methodologies enable better and more refined reservoir models to be fashioned and tweaked as needed on a case-by-case basis. The case study analyzes log responses, implication of heterogeneity and mixed clays content on the generation of LRLC pay reservoirs in deltaic environment offshore Nigeria.
Precise application of advanced log measurements and integration of core data in a common workflow, built around the concepts of evolution of LRLC reservoirs lead to accurate pay quantification. Borehole image interpretation suggests that the low resistivity contrast is attributed to dispersed clays coating around the sand grains in the toe part of a delta front in major coarsening up and feeble fining up sequences. This is also confirmed by variations of elastic properties of the matrix.
Petrophysical logs recorded at high resolution correlate inferring the main causes of LRLC pay are clay content and distribution, and small grain sizes intermingled to the reservoir rock, hence resulting in low resistivity values in all directions and drastically increased irreducible water. The logs based model is confirmed by calibration to core analysis results. The confident results of the study confirm the power of collaboration between petrophysics, rock mechanics and geology in innovative interpretation workflows for enhanced reserves estimate and Producibility prediction in heterogeneous media.
ADCO South East Asset has recently comissioned a major project called SAS Project, the project was part of ADCO plan of delivering 1.8 MMbd sustainable oil production capacity by end 2017.
The project has contributed in adding 115 Mbd from the three developed areas, Asab, Sahil and Shah.
In Asab 50 Mbd has been added and the project new facilities increased the oil production from 290 to 340 Mbd, in Sahil 45 Mbd has been added and Sahil production was increased from 55 to 100 and similarly Shah production was increased by 20 Mbd from 50 to 70 Mbd.
Project execution Level I schedule consist of Engineering, Procurement, Construction and Pre-Commissioning/ Commissioning and all of those stages are logically linked and the successful completion of each stage will affect other stages and will lead to project overall success.
Different successful strategies have been implemented throughout the EPC, in this paper we will review in details those strategies and will highlight how challenges were faced.
The purpose of this paper is to share ADCO's project experience, and to highlights the strategies which were adopted and resulted in the achievement of successful project execution in areas of engineering, procurement, construction and management.
This paper evaluates the effect of different proppant pack cleanup scenarios on welltest analysis results and long-term recovery in tight gas and unconventional reservoirs. Simulated buildups are created in a detailed reservoir simulation model. The simulated buildups are analyzed in a commercial welltest analysis package to obtain an apparent effective propped fracture length, as is common practice in the industry. Two different proppant pack cleanup scenarios are compared, both of which result in a short apparent effective fracture length based on welltest analysis. The effect on long-term recovery for the different cleanup scenarios is then simulated using detailed 3D reservoir simulations, showing that there is a significant difference in recovery, in spite of the comparable welltest analysis results.
In a previous publication (
This work supports field observations that have been made by Barree showing a correlation between ultimate drainage area and fracture size. This work suggests that trying to achieve maximum possible propped length is still important in tight and unconventional reservoirs to maximize long-term recovery and connected gas in place, even when well testing shows a short effective fracture length. Including the effect of effective fracture height, or using more realistic assumptions about proppant pack cleanup, would help to avoid underestimating the actual effective fracture length. Welltests showing short fracture lengths have led some people to reduce treatment volume and increase proppant concentration to achieve higher fracture conductivities. They hope to increase the effective length even while reducing the created propped length. Using more realistic proppant pack cleanup scenarios, we show that this approach may actually be counterproductive in tight gas and unconventional reservoirs, because it reduces ultimate recovery due to a reduced fracture extent.
Through-tubing (TT) drilling was used to drill Upper Permian Zechstein carbonates in Germany. The project was partially set up as an experimental performance comparison between a positive displacement motor (PDM) and a turbodrill bottomhole assembly (BHA) equipped with real-time logging tools. This would be a world-first drilling run for this size of turbodrill as well as the first turbodrill run on coiled tubing (CT) using this real-time data feedback.
Through-tubing coiled tubing (TT-CT) drilling incurs significantly lower cost per drilled footage than conventional rotary drilling methods. A dedicated candidate selection process emphasized the geometry and extent of the pay zone, borehole stability, tubing geometry, and well integrity, which are all crucial for the application of TT-CT drilling. As a result of this screening process, well Sh Z1a, a horizontal sour gas production well was selected. Dedicated BHA designs were used for both the PDM and the turbodrill to allow for a direct performance comparison whilst drilling the section.
TT-CT drilling was used to deepen the well. Initially, 410 ft [125 m] were drilled with a 2.283-in. [58.0-mm] impregnated bit and a 2.125-in. [54.0-mm] PDM using 1.750-in. [44.5-mm] CT suitable for sour service. An additional 148 ft [45 m] were drilled with a 2.283-in. [58.0-mm] impregnated diamond bit with polycrystalline diamond compact (PDC) cone cutters. This bit was run with a 2.125-in. [54.0-mm] turbodrill BHA equipped with real-time logging tools using a sour-service-suitable 1.750-in. [44.5-mm] CT with a fiber-optic cable. The section was drilled under total losses and through multiple natural fractures. While drilling with the real-time logging tool, internal and external downhole pressures, torque, and tension and compression forces were recorded to assist in the drilling process. Direct comparison of the PDM and the turbodrill BHA was made for rate of penetration (ROP), weights and pressures. The turbodrill BHA produced more than double the ROP than was possible with the conventional PDM BHA using less weight on bit and showed overall smoother drilling mechanics.
The well is currently on production. The project showed that TT-CT drilling is a viable technology for production enhancement in depleted gas reservoirs and that new turbodrill technology generates significant performance improvements over conventional drilling tools.
Cadours, Renaud (Abu Dhabi Gas Industry Ltd) | Al Katheeri, Sara (Abu Dhabi Gas Industry Ltd) | Al Matroushi, Mohamed Salem (Abu Dhabi Gas Industry Ltd) | Ghazaly, Ayman (Abu Dhabi Gas Industry Ltd) | Sayegh, Salem (Abu Dhabi Gas Industry Ltd)
The GASCO industrial complex is constructed to process Natural Gas Liquids (NGL) from associated and natural gas. The liquids collected from Asab, Bu-Hasa and Habshan plants is transfer by pipeline to the Ruwais plant for further fractionation before supply to local end-users or other customers. The sweetening processes are critical steps in the GASCO complex to guarantee plant and operators safety, to comply with customers’ specification and to minimize the industrial impact on the environment. In this way, GASCO is continuously considering improvement of the processing plants, especially to minimize the sulphur emissions in the environment.
A significant part of the sulphur emission from the Ruwais plant are resulting from the operation of the molecular sieves used for mercaptans removal from propane and butane products. During regeneration step of these molecular sieves, the adsorbed mercaptans are concentrated in the regeneration gas. Combustion of this gas without treatment is resulting in a significant part of the sulphur emission.
This papers presents a detailed review of the best available technologies for mercaptans removal. Two options are discussed: treatment of the molecular sieves regeneration gas and mercaptan removal at upstream NGL extraction plants. Molecular sieves and hybrid solvent technologies are considered. The paper presents pro and cons of all the alternatives, considering the constraints of the existing GASCO industrial complex: units’ configuration, disposal or recycle of the mercaptan.
This paper presents an independent review of technologies for mercaptans removal, from the GASCO operational point of view. It summarizes the benefit and the constraints of each technology, and their impact when implemented in an existing complex.
Alkasem, Abdulkader (Abu Dhabi Gas Industries Ltd - GASCO) | Al Zarouni, Y. A. (Abu Dhabi Gas Industries Ltd - GASCO) | Slagle, J. C. (Bryan Research & Engineering, Inc.) | Berrouk, A. S. (The Petroleum Institute) | Satyadileep, D. (The Petroleum Institute)
As part of its ongoing optimization effort, Abu Dhabi Gas Industries (GASCO) is working with the Petroleum Institute (PI) and Bryan Research and Engineering Inc. (BR&E) to identify opportunities for optimization of the Habshan II amine sweetening unit for a wide range of gas throughput.
In a previous study, ProMax®, a process simulation package, was first verified by comparing the model results to operating data for about 300 days and was then used to optimize the facility operating near maximum capacity. Recently, most of the gas has been diverted to another facility resulting in Habshan II operating in the 30-40% capacity range.
In the present study, ProMax, is used to re-optimize the facility at the current low throughput. The model results for the new optimum are implemented in the plant and compared to operating data to confirm the predictions. In addition, the plant plans to increase throughput in the coming months. Therefore, the plant has been optimized at various gas flowrates to provide operators with set points at any given gas flowrate. In addition to preparing operators for throughput fluctuations, the results show a reduction of operating costs that amount to roughly 800,000 USD/yr.