Serra De Souza, Antonio Luiz (Petrobras S.A.) | Meurer, Gustavo Bechara (IBP - Brazilian Petroleum and Gas Institute) | Pastor, Jorge Aurelio (Schlumberger) | Naveira, Vanessa Palma (Petrobras S.A.) | Souza, Jorge (Schlumberger) | Frydman, Marcelo (Petrobras) | Chaves, Ricardo A.P. (Schlumberger) | Chaves, Michelle
Several Petrobras fields in Campos Basin are soft sandstone with a large number of faults, which demands a careful reservoir geomechanics study in order to maximize their production and minimize geomechanical risks. Those risks are associated with compaction and/or dilation, subsidence and in special with fault reactivation due to water injection, which can lead to a connection between different layers and reservoirs.
The object of this study is a faulted turbidity reservoir in Campos basin where a water injection project has started. The Mechanical Earth Model (MEM) was developed. It was identified that the planned injection pressure would increase the risks for fault reactivation, and recommendations for a safe water injection project was obtained. Special emphasis is on factors that may have enhanced leakage pathways at some point during injection, reducing its effectiveness and bringing other related risks. Reservoir performance and associated reservoir deformation was estimated. The predicted stress and strain changes that were induced by production/injection were used to assess the wellbore stability, faults reactivation potential, cap rock integrity and rock fracturing. Understanding of the various potential processes and being able to predict the field behavior are critical to the optimal management of the reservoir for maximum productivity and recovery.
In the last decades, the major oil companies have moved aggressively toward challenging targets such as deep and ultra-deep water environments to increase their hydrocarbon reserves portfolio.
To deal with these new targets, attractive but located in harsh environments, technology has to improve significantly as well as the attention to be paid to operate under safe conditions. Operational daily costs are generally huge, sometime in excess of 1 million US$. As a consequence, the goal is to achieve a satisfactory balance between the value of information about the reservoir to be investigated and the ability to operate in a cost-effective manner.
The option of capturing real time downhole P&T data by using electric cables when testing an exploration well is considered less and less attractive due to intrinsic safety risks. This has triggered significant developments in the wireless technology in recent years. Real time data are transmitted acoustically, removing the need for wireline operations.
This wireless technology proved to be very effective increasing the test efficiency, optimizing the test sequence to acquire the well/reservoir response, minimizing costs and operating in a totally safe way.
A real field application on an offshore exploration gas well is presented in this paper. The test offered the opportunity to assess both benefits and limitations of the technology.
Charnvit, Kerati (M-I Swaco) | Kongto, Abhijart (M-I Swaco) | Huadi, Fransiskus (M-I Swaco) | Sharma, Sunil (M-I Swaco) | Simon, Gerard A. (Chevron Corp.) | Estes, Brent Lamar (Chevron Corp.) | Trotter, Robert Neil (Chevron ETC)
Typical wells in the Gulf of Thailand are drilled using a slim-hole design that requires 6?-in. hole for their reservoir interval. The slim and highly deviated well geometry, potential of high acid gas contamination, and high-temperature environment requires a well-engineered non-aqueous drilling fluid (NAF) to meet the overall well objectives. These conditions always place severe limitations on the drilling fluids design and often lead to failures in openhole wireline logging operations, which is the most important well objective.
The key fluid properties to ensure the success of wireline logging operations under this high temperature are high-temperature,high-pressure (HTHP) filtration control, filtercake quality, and thermal stability of the drilling fluid under
extreme static condition. Selected emulsifier and HTHP filtration control agents work synergistically in providing excellent hole condition which allows the hole to be fully logged and evaluated. Clear benchmarks were set and monitored in all the field applications: (1) Successful wireline logging operation; (2) Variation of mud weight after static condition; (3) Variation of mud weight compared to formation tester data point.
This paper details the design, development, and field applications of an ultra-high-temperature NAF used for drilling deep and hot wells in the Gulf of Thailand. In addition, the extensive laboratory work required to optimize the formulation for extreme high temperatures, the lessons learned, and the critical engineering guidelines for running a NAF in such harsh conditions will be described.
When bottomhole static temperature (BHST) exceeds 400°F, good engineering practices and extra attention are required during hole drilling operations for NAF to perform within expectations, especially when coupled with acid gas contamination and high solids content, specifically low-gravity solids (LGS). Emulsifiers can thermally degrade leading to gelation problems as well as contributing to increased high-temperature, high-pressure (HTHP) fluid loss. HTHP filtration control and filtercake quality can also deteriorate due to the degradation of HTHP filtration control agents. Therefore, the selection of appropriate additives and their concentration is critical to ensure the drilling fluid will withstand prolonged exposure to ultra-hightemperature openhole wireline logging operation (>48 hours).
Historically, conventional NAF systems have had a good performance track record in the Gulf of Thailand providing the necessary fluid and wellbore stability to achieve successful wireline logging operations. However, when BHST exceeds 400°F, problems have been reported during wireline logging operation, including difficulties in moving wireline logging tools up/down to reach the target depth or even getting stuck which led to non-productive time (NPT) and/or loss of tools in several wells. As a result, a more robust NAF, which could help minimize the NPT, was requested by the operator as numerous wells being planned would have BHST considerably above 400°F. The first approach to solve this issue was to review and modify field engineering practices in an attempt to extend the stability of the conventional NAF formulation; however, it was concluded from this initial study that a novel NAF was required for this ultra-high temperature condition.
The relative permeability curves do not share the same degree of acceptance and credibility. This is particularly serious because the estimation of reserves in natural processes and in EOR projects using immiscible fluids (water, gas, steam) heavily depends on relative permeabilities. Most of the relative permeability in fractured reservoirs measurements are performed through the unsteady state method, by which the reported end points correspond to steady state flow conditions (homogeneous saturation and single phase flow), while the intermediate values are calculated during a transient stage in which sample saturation is not homogeneous. Because of this, the end point saturations should have greater validity than the remaining points in the curve, since the shape of the curves in heterogeneous systems depends - among other things - on the mobility ratio, while it is generally accepted that the end points - if properly extrapolated at the end of the test - are independent from it.It is generally believed that residual oil saturation, Sor ,is obtained only after injecting "infinite" poral volumes of water.
In many cases, the production curve, the residual oil saturation and the permeability to water - at such saturation - notably depend on the flow rate used during displacement. Although laboratories take different steps to correct, or not, the measurements performed, they mostly fail to inform what flow rates were used in the lab or the range of application of the reported data. The relative permeability curves presented by the labs are usually continuous along the entire saturation range between Siw and Sor.
Based on the above considerations,it would seem reasonable to conclude that, in order to properly characterize the reservoir, the different displacement mechanisms and flow directions should be studied to analyze their effect on the production curves used to determine the system relative permeabilities.
The initialization of a reservoir simulator calls for the populating of a three-dimensional dynamic grid-cell model using subsurface data and interrelational algorithms that have been synthesized to be fit for purpose. These prerequisites are rarely fully satisfied in practice. This paper sets out to strengthen initialization through four key thrusts. The first addresses representative data acquisition, which includes the key-well concept as a framework for the cost-effective incorporation of free-fluid porosity and permeability within an initialization database. The second concerns the preparation of these data and their products for populating the static and dynamic models. Important elements are dynamically-conditioned net-reservoir cut-offs, recognition of primary flow units, and establishing interpretative algorithms at the simulator grid-cell scale for application over net-reservoir zones. The third thrust is directed at the internal consistency of capillary character, relative permeability properties and petrophysically-derived hydrocarbon saturations over net reservoir. This exercise is central to the simulation function and it is an integral component of hydraulic data partitioning. The fourth concerns the handling of formation heterogeneity and anisotropy, especially from the standpoint of directional parametric averaging and interpretative algorithms. These matters have been synthesized into a workflow for optimizing the initialization of reservoir simulators. In so doing, a further important consideration is the selection of the appropriate procedures that are available within and specific to different software packages.
The implementation of these thrusts has demonstrably enhanced the authentication of reservoir simulators through more readily attainable history matches with less required tuning. This outcome is attributed to a more systematic initialization process with a lower risk of artefacts. Of course, these benefits feed through to more assured estimates of ultimate recovery and thence hydrocarbon reserves.
Napalowski, Ralf (BHP Billiton) | Loro, Richard (BHP Billiton) | Anderson, Calan Jay (BHP Billiton) | Andresen, Christian Andre (ResMan AS) | Dyrli, Anne Dalager (ResMan AS) | Nyhavn, Fridtjof (ResMan AS)
This paper describes the interventionless approach that was successfully executed during the Pyrenees early production phase to identify the timing and location of water breakthrough. Chemical inflow tracers were installed in key production wells within the lower completion along the horizontal production sections. Results from this work have supported the reservoir simulation history matching process and confirmed the performance of the inflow control devices (ICDs). These data in conjunction with the real time rate information from subsea multiphase meters has allowed proactive reservoir and production management that has contributed to the early identification of additional infill opportunities.
Latief, Agus Izudin (Roxar (M) Sdn. Bhd.) | Ridzuan, Ahmad Idriszuldin (Petronas (Kuala Lumpur)) | Faehrmann, Paul A. (Shell) | Macdonald, Alister C. (Roxar Software Solutions) | Arina, Wardah (Petronas) | Rahman, Gozali (Roxar Software Solutions) | ab rahman, mohd elzrey
Baram is a giant mature field situated, offshore Sarawak Malaysia. Reservoirs consist of an approximately 7000 ft thick-stacked sequence of shallow marine sands, distributed in excess of 200 zones. The field is extensively faulted. Early Growth faulting followed by a later compressional phase has led to complex fault geometries. The field has been producing for over 40 years and presently has 175 wells.
Although the reservoirs are generally of good quality, the field currently has relatively low production rates, a low recovery factor, and a significant amount of remaining reserves. The geological complexity poses a key challenge, and a robust static reservoir model is a prerequisite for efficient reservoir management and for identifying viable Improved Oil Recovery (IOR) measures.
Static models of the Baram field had previously been constructed. This modelling took in excess two years to complete and the models were segmented into 10 pieces, as technology during this period was unable to tackle complex fault geometries. Due to the results of the static / dynamic modelling being insufficiently robust when tested during a drilling campaign in 2009, the decision was made to remodel.
The Baram subsurface team was challenged with building a static model which could be used for field management and IOR /EOR process selection and optimization within a six month timeframe. This is to allow for early investment decisions and an accelerated reversal of production decline. The key aspects of the fixed timeframe static model construction are described below. They consist of:
1. The subdivision of the field into independent models.
2. The utilization of a modern algorithm to model complex fault geometry.
3. Nested stratigraphic modeling.
4. Parallel property modeling and the re-combining of results into a single simulation grid to enable integrated reservoir
A full focus on the importance of the timeline and early investment, plus the adoption of a variety of strategic project
management measures and use of "state of the art" modeling technology can allow fit-for-purpose static models to be delivered on time.
This paper will demonstrate that the use of quantitative risk analysis (QRA) has limitations and does not, in isolation, demonstrate adequate management of risks. The only way to demonstrate that risks are being appropriately managed is to identify all hazards; understand the level of risk; identify all prevention, control and mitigation barriers; and then demonstrate that those barriers are adequate and effective in managing that risk to a level that is as low as reasonably practicable.
This paper is applicable to all process industries and, in particular, those industries operating under the jurisdiction of NOPSEMA in Australia. Under the OPGGS Act we have a legal obligation to demonstrate that we are managing risk to levels that are demonstrably ALARP.
In summary this paper will show that QRA has its place in demonstrating adequate management of risks; however, it should not be used in isolation. Having a QRA conducted can sometimes provide a false sense of security that risk is being managed. The UKOOA Risk-based Decision Making Framework is a useful tool in demonstrating the small part that QRA plays in managing risk. The answer to managing risk effectively lies in demonstrating that adequate and effective controls are in place. Not only do we need to identify the controls that are required to manage risk effectively, we also need to demonstrate that those controls are actually in place, are performing as they should and that competent people have confirmed that this is the case.
In the process industry, post-Macondo & Montara, it is essential that operators move away from just demonstrating that they understand the level of risk that personnel and the environment are exposed to. We all need to move towards demonstrating that we have adequate and effective barriers and controls in place to manage that risk effectively.
Liu, Xinghui (Pinnacle Technologies) | Chang, Yanrong (Changqing Oil Field) | Lu, Hongjun (PetroChina Changqing Oilfield Company) | Chen, Baochun (Changqing Oil Field Res. Inst.) | Li, Jianshan | Qi, Yin | Wang, Chengwang
Huge oil reserves are located in low-permeability reservoirs in the Ordos basin in China. These reservoirs have three key characteristics: low reservoir quality (10 to 13% in porosity), low reservoir permeability (0.3 to 2.0 md), and low reservoir pressures (pressure gradients of 0.0075 to 0.009 MPa/m). Fracture stimulation is essential for commercial production in these reservoirs. To better understand fracture growth behavior and to optimize treatment designs, microseismic monitoring and fracture modeling were performed for pilot wells in key areas. In some low-permeability oil reservoirs in the basin, fracture closure stress sometimes could not be obtained from commonly used pump-in/shut-in tests because pressure decline is extremely slow. Closure stress is one of the important parameters for fracture modeling. To obtain closure stress in these reservoirs, conventional pump-in/flow-back (PIFB) tests were modified and employed. Once the closure stress in the payzone was determined, the closure stresses in adjacent and/or bounding layers were estimated from sonic log and lithology data. Fracture modeling analysis was then conducted using a calibrated fracture model, which must match both the observed net fracture pressures and the fracture dimensions from microseismic mapping. This approach led to significant improvements in fracture treatment designs in these tight-oil reservoirs. The first improvement was to maximize effective fracture lengths in fracture designs. A novel staging technique was also developed to stimulate large pay intervals using a stress diversion technique without mechanical isolation. Larger treatments using a hybrid fracturing technique were recently implemented to stimulate ultralow-permeability oil reservoirs. Production results using the new stimulation techniques were significantly better than traditional techniques in the region. This paper discusses how an integrated, engineered approach was applied to stimulate tight-oil reservoirs in the Ordos basin and demonstrates the benefits of an integrated approach to developing marginal, unconventional liquid hydrocarbon reservoirs.
Low permeability reservoirs contain a large volume of the world's oil resource. Often these fields are characterised by low waterflood injectivity, poor sweep and low productivity. A substantial number of these fields are initially, or during production become, fractured. Improved oil recovery and EOR for these fields is an attractive goal, although many conventional EOR applications present major challenges.
We present results on how wettability alteration, together with physical and chemical modifications of the waterflood, can improve oil recovery. From high precision adsorption experiments, together with wettability measurements on model systems, we present conclusions on the inter-relationship of adsorption behaviour and wettability of reservoirs.
Laboratory measurements are presented confirming how:
1. Wettability can be modified through changes in salinity, hardness and temperature.
2. In waterflooding there is a direct, measurable relationship between wettability (contact angle) and adsorption at the solid / liquid and liquid / liquid interfaces. These inter-relationships can be expressed in basic thermodynamic concepts.
3. Adsorption at solid / liquid interfaces can be directly related to the existence and nature of thin aqueous films in water wet and mixed wet reservoirs. Dynamic effects resulting from brines of different chemical and physical properties can be highly important in terms of displacement efficiency during waterflooding.
We demonstrate the significance of these results for waterflooding and EOR in lower permeability fields. Approaches such as wettability alteration, low salinity (including brine compositional modification) waterflooding, and variation of injection brine temperature all show potential. This is in contrast to more traditional chemical and immiscible gas injection, which are often technically difficult in these fields. We further conclude that these approaches can be beneficially applied fields with substantial fracturing and faulting.