Distributed fiber-optic sensing, and specifically the introduction of intelligent distributed acoustic sensing (DAS), has gained the attention of production engineers with the promise of a versatile and cost-effective decision-support tool. These systems can either be permanently installed, or temporarily deployed using diverse types of intervention systems.
This article covers the principles of flow allocation using distributed sensing and show how these can be used and combined to identify fluid-entry points, quantify production and identify fluid phases. We will describe the methods used to improve quantitative interpretation from distributed sensing, especially the use of phase-coherent DAS for quantitative measurement of sound speed and its use in analysis of flow velocity and fluid phase.
While early DAS systems were previously limited in their flow-detection thresholds we have recently introduced a new sensing system, bringing a 20dB (100×) improvement in signal-to-noise. This offers a significant improvement in measurement and associated interpretation capability.
Distributed fiber-optic sensors were invented in the 1980s (Hartog, 1983) and introduced into the oilfield in the 1990s. The initial areas of interest, and commercially available technologies, were related to distributed temperature sensors (DTS) and distributed strain sensors (DSS). DTS was applied to leak detection, flow profiling and steamflood-monitoring applications (Smolen and van der Spek, 2003). DSS focused mainly on wellbore integrity, monitoring strain induced on wellbore casings (Li et a., 2004). Some research has also been carried out on the use of DSS systems for distributed pressure sensing, but to date, these have not delivered the required performance and reliability for commercial application.
Steam injection (including cyclic steam and SAGD) has long been recognized as the favored recovery method for heavy oil, with applications in many fields around the world in particular in California and Canada. More recently, polymer flooding has also become a relatively well accepted method to increase production and recovery in heavy oil fields. Numerous successful pilots have been reported these last few years and field expansions are currently ongoing in Canada, Oman, China and Albania for instance but surprisingly enough, there has been to the best of the author's knowledge no such application in the US. Both steam and polymer injection have their advantages and their limitations and simple screening criteria have been developed by several authors, however there has never been a detailed comparison of the two methods and this is what this paper proposes to do. The pros and cons of both steam injection and polymer flood are reviewed in light of fundamentals and field experience: reservoir depth, thickness, oil viscosity, expected recovery, water usage and economics of both processes (in particular capital requirements) are all addressed.
A large, strategically important unconventional (tight) gas project in the Sultanate of Oman advanced from the exploration stage with one discovery well to the pilot and development stages over 4 years. Project challenges in the first 2 years of exploration were poor initial success in both fracturing treatment placement and subsequent productivity and an ever-expanding scope of work in a demanding environment with limited resources. To address these challenges, the focus was shifted from routine delivery to an integrated approach and a strategy that included defined activity timelines, key performance indicators aligning with different stakeholders, and process reviews. Technology deployment and improved operations with allocated fracturing equipment spread gave flexibility to this new efficiency model. Integrated technology trials included cased and openhole completions; different well types; and several rock and core mechanical tests, such as reservoir coring, openhole stress testing, sonic measurements, and continuous unconfined compressive strength measurements. It also incorporated abrasive perforating, various fracturing treatment type designs, and advanced evaluation techniques such as microseismic monitoring, three-phase flow metering, tracers, and others. These technologies were implemented in a fast and efficient manner owing to strong collaboration between a dedicated Petroleum Development Oman (PDO) subsurface team and the service provider expertise. Personnel embedded in the exploration team greatly helped with linking to proper resources within the suppliers. An embedded engineer provided immediate technical and logistical support to the team. The improved process involved multiwell fracturing, a test campaign, and evaluation of individual zones. Finally, gaps and areas for improvement going forward were identified. Over the 4 years, with implementation of the new technology and strategy, the success rate of fracture placement and zonal evaluation increased from the low initial success of less than 50% to 100%; the improvement was particularly evident in the extremely tight lower intervals of the reservoir.
Wei, Chenji (Research Institute of Petroleum Exploration & Development, PetroChina) | Li, Yong (Research Institute of Petroleum Exploration & Development, PetroChina) | Li, Baozhu (Research Institute of Petroleum Exploration & Development, PetroChina) | Wang, Yinxi (China National Oil and gas Exploration & development, PetroChina) | cai, Kaiping (Subsurface Department, Rumaila Operating Organization(ROO)) | Zhang, Qi (Research Institute of Petroleum Exploration & Development, PetroChina) | Zhou, Jiasheng (China National Oil and gas Exploration & development, PetroChina)
Understanding the heterogeneity is critical for a successful water injection in a carbonate reservoir. Thief zone is one of the most obvious forms of heterogeneity, which indicates the thin layer with higher permeability compared with average reservoir permeability. The existence of thief zone results in earlier water breakthrough and faster water cut increase, which lead to smaller sweep efficiency and lower recovery factor. Therefore, determining the thief zone distribution and proposing corresponding development plan are very important.
This paper focuses on a super-giant carbonate reservoir, which is a Cretaceous carbonate reservoir in Middle East, with an OOIP of more than 20 billion barrels. Thief zones are widely distributed in this carbonate according to the production logging test (PLT). In this paper, we combined geological understanding and dynamic behavior to summarize different types of thief zone distribution, which means the different locations and scales of thief zone and barriers. Then, geological model is built, and reservoir simulation is conducted on the models corresponding to different types to optimize the development strategy.
The optimized parameters include well pattern and perforation strategy. Then, development strategies are proposed for different types of thief zone distribution. Results indicate that location of thief zone hasobvious impact on the production. In order to mitigate the impact of thief zone, line drive pattern is preferred when the permeability ratio is high. Most importantly, different types of thief zone distribution require specified perforation strategy, and optimizeddevelopment strategies could save more than 25% of injected water by mitigating the futile cycle of injected water.
This paper offers a case study that summarizes different types of thief zone distribution and optimizes the development strategy for different scenarios. It also provides a methodology and reference case for engineers and geologists to develop other similar fields.
Wang, Ruifeng (RIPED, PetroChina) | Wu, Xianghong (China Natl. Petroleum Corp.) | Yuan, Xintao (RIPED, PetroChina) | Wang, Li (RIPED, PetroChina) | Zhang, Xinzheng (RIPED, PetroChina) | Yi, Xiaoling (RIPED, PetroChina)
This paper demonstrates the first cyclic steam stimulation (CSS) pilot test in Sudan, which was applied in FNE shallow heavy oil reservoir. B reservoir of FNE field is a shallow, heavy oil reservoir with strong bottom water, burial depth is 520 m. Well tests have shown low oil rates under cold production, averaging at 50-150 BOPD. Denser well spacing will be required if under cold production, which will be quite cost consuming. CSS generally could yield enhanced oil for heavy oil reservoirs. Therefore CSS pilot test has been planned by approaches as follows: 1) investigation of global heavy oil fields with successful CSS histories to confirm applicability in FNE field; 2) Pilot well screening criteria establishment based on sedimentary and reservoir engineering analysis; 3) Perforation optimization to avoid rapid coning based on thermal simulation; 4) steam injection parameters optimization; 5) applicability of natural gas as cost-effective heating source.
CSS Pilot tests on two wells began in 2009. Convincible results have been monitored with well daily rates 3-4 times of cold production wells with low water cut. Another six CSS wells further came on stream from July. 2010, achieving similar positive results. Conclusions drawn from pilot test were as follows: 1) Optimized perforation contributed to low water cut; 2) steam injection density was optimized around 120 t/m; 3) Natural gas as heating source greatly reduce operating cost.
Heavy oil reserves are estimated to take 40% of Sudan's total reserves. Sudan is also abundant in natural gas reserves, therefore cost-effective CSS development strategy has wide applications for similar Sudanese and African fields.
Successful CSS pilot test in this paper highlighted CSS well screening criteria, perforation strategy, steam injection optimization and natural gas utilization, giving a cost-effective staircase for CSS pilot design and implementation.
One of the major fields in the South of the Sultanate of Oman produces oil at 94% average BSW. All produced water is disposed of without treatment into the same aquifer. The disposed water is injected under fracing conditions and takes place more than 200 m below the lower shale (cap rock) in the sandstone (Fig.1). However the failure of the field's cap rock could result in oil deferment and the contamination of the overlying aquifer; therefore rigorous risk management is strongly required.
Several in-situ stress testing (mini-frac) stations were conducted in the field focusing on lower shale and sandstone formations to evaluate the risk of breaking the cap rock and above formations associated with the water disposal. However this was very challenging using the normal ways of testing; hence the stress testing application was conducted with an oil based viscous fluid. The viscous fluid allowed accomplishing the objectives in higher permeability and shale zones. The oil based viscous fluid facilitates initiation of a fracture in highly permeable sandstone formations and reduces the osmosis and plastic behavior effects in shale zones.
The viscous fluid stress testing provides the results required to update the numerical models for each formation by obtaining minimum stress and fracture initiation, propagation, and closure pressures (frac gradients). Moreover the test results will help to build models that can predict fracture growth while injecting water.
This paper will discuss in detail the viscous fluid stress test and how the results can be used to understand the reservoir behavior. Realistic injection forecasts were made possible using commercial fracture simulation software and some analytical and diagnostic methods based on pressure survey and injection volumes history.
A wetland based water treatment plant is being constructed combining a three stage treatment process starting with an Oil/Water Separator followed by a Constructed Wetland and a Water Evaporation and Salt Crystallization Facility to receive initially 45,000 m³ produced water per day.
For such a natural system climate data and local soil conditions are essential design parameters. Initial given data had to be verified during the construction phase to prove all used design parameters by recording and determine temperature, evaporation and evapotranspiration data as well as soil characteristics and infiltration data of the used mineral sealing layer.
Although the implementation of the treatment facility is influenced by the new data acquisition the construction works covering more than 600 ha are on schedule. A Reed Bed area of 195 ha out of 234 ha has been completed and the plantation of 1,200,000 locally produced Phragmites australis plants has been started on schedule. The current program will allow the full wetland to be operational by the commissioning date in January 2011.
In order to reduce the environmental impact of produced water management a wetland system is being installed in the Sultanate of Oman. The facility will reduce the disposal of hydrocarbon polluted produced water into deep aquifers, recover hydrocarbons by means of an additional oil/water separation step and decrease the overall power consumption of the oil field operation by using a gravity flow system. During construction measures have been taken to reduce the impact by using only local materials for the installation of a sealing layer.
The project is currently in the commissioning phase and first result have shown that up to 60 bbl/d of crude oil were recovered, an overall a reduction of the power consumption between 1.2 and 1.8 Mio MWh can possibly achieved in the 20 years of operation and due to the installation of a mineral sealing layer the impact during construction could be reduced by 80 % for this element compared to the installation of an artificial sealing.
Walton, William (Petroleum Development of Oman) | Scholten, Sven Olaf (Petroleum Development of Oman) | Aitken, John Fenwick (Petroleum Development of Oman) | Al-Hakmani, Abdullah Said (Petroleum Development of Oman) | Al-Siyabi, Hisham Abdulrahma (Petroleum Development of Oman) | Skaloud, Dieter Karl (South Rub Al-Khali Company Limited) | Millson, John A. (Shell)
Early Palaeozoic-age non-associated gas fields operated by Petroleum Development Oman (PDO) in the Sultanate of Oman have traditionally comprised good reservoir quality sandstones located on three- or four-way dip-closed structural highs. While gas exploration success has continued over the last five years, this has been restricted to discoveries in much poorer quality ("tight??) sandstone reservoirs. Significant challenges exist: target reservoirs are deep - over 4500 m (18,000 ft) with high reservoir temperatures (> 170°C). Porosities range from less than 3 to 10% with (ambient) permeabilities ranging from 0.001 to 1 mD.
These tight reservoirs have elevated pressures (above hydrostatic) and many wells record GDT (Gas-Down-To) situations (i.e. no GWC recorded). Furthermore, basin modelling indicates that peak hydrocarbon generation occurred during the Palaeozoic and Mesozoic and may have continued until Early Tertiary times in some areas.
A study was started in 2008 to analyse the above data applying a range of techniques including basin modelling, geochemistry, regional well results evaluation together with pressure data analysis and comparison with global analogues. This resulted in approval for a four well exploration campaign to evaluate diverse locations across north Oman addressing the quest for tight gas in a basin-centre setting. Drilling of the first exploration well started in late 2009 with the aim of proving the presence of deep gas accumulations and ultimately gain an indication of commercial attractiveness.
This paper presents the key criteria expected to influence the deep gas play prospectivity (i.e. presence of favourable reservoir, hydrocarbon charge and retention) and the steps to mature this opportunity. We also highlight an approach to progressing an unconventional gas opportunity in a challenging geological environment, in the Middle East, where the maturation of this resource type is currently in its infancy.
BP's Khazzan-Makarem (KM) appraisal project is located in Central Oman. BP committed to appraise four deep tight gas reservoirs and has drilled seven wells to date. An Extended Well Test (EWT) facility is designed to provide a long term (multi-month) flow test of those wells.
Basic information relating to trap, seal, areal extent, and Gas-in-Place (GIP) is not the most significant problem in this appraisal project; the most important issue is long term well performance. The tight gas nature of these reservoirs results in considerable uncertainty in prediction of future deliverability. It is not uncommon for tight gas wells to achieve excellent flow rates after fracture stimulation, yet decline precipitously over a short period of time (typically months) once on production. Prediction of well performance based on this early flow rate is a highly unreliable indicator of long term performance. This can result in drastic miscalculations for Full Field Development (FFD) planning and economics.
Extensive surveillance activities are critical to evaluate this uncertain behavior. An examination of stimulation, well testing and Pressure-Build-Up (PBU) analysis in these wells provides the starting point for understanding well deliverability.
BP's KM appraisal wells were planned to selectively target reservoirs addressing variations in reservoir quality and continuity. Completions were designed from the start, to facilitate extensive stimulation programs. Surveillance programs were constructed with permanent down hole gauges (PDHG) to provide critical real time information about the stimulation efforts, well testing, fluid composition analysis, and extreme long term (~ 1 year) PBU. All of this effort provides guidance in planning the EWT facility for an extended flow testing campaign which will feed into FFD planning. Achieving commercial rates in tight gas reservoirs in Oman has proved to be challenging. However this comprehensive appraisal and surveillance program is providing a growing level of confidence in the development potential of the Khazzan-Makarem project.