Operational conditions in the remote highlands of Papua New Guinea bring a multitude of challenges including complex geology, steep jungle terrain, extreme rainfall, a sensitive ecosystem, a variety of landowner cultures, ageing facilities, mature reservoirs, and fraught logistics. These factors conspire to increase the complexity of production forecasting well beyond just reservoir performance.
After missing production targets for a number of years, a significant improvement in forecasting was needed to fully capture the uncertainties, both identified and unforeseen. A probabilistic forecasting tool using Monte Carlo simulation has been developed which incorporates assessments of all major variables and takes account of historical performance and system changes.
Successful implementation has resulted in the generation of realistic targets which have been met within four per cent for three years. Further, a clearer understanding of potential threats and opportunities combined with their impact on production has been achieved. These results have delivered material benefits to business planning, decision making and company reputation. Data to be presented on the forecasting tool will describe the quantification of uncertainty for each major variable including reservoir and facility performance, incremental production opportunities, project schedules and major unplanned downtime.
This approach could be applicable to E&P companies operating in difficult conditions worldwide, where unreliable production targets have a major business impact. It is flexible enough for both short and long term forecasts, tracking and reporting, and adaptation to new or changed operating conditions.
In recent years, the use of fracpack treatments has gained attention and is becoming increasingly popular because of their dual benefits of stimulation and sand control. A fracpack is a hydraulic fracturing treatment using a very high proppant concentration that attempts to "pack-off?? the mouth of the fracture. Fracpacking is widely used in high-permeability, poorly consolidated to unconsolidated sandstone formations. Accurate estimation of fracture width is important for both fracpacking and hydraulic fracturing to help ensure a successful treatment.
With the development of low-leakoff fluid systems, it has become possible to force the fluid through the proppant pack and out through the tip of the fracture without losing all the fluid through the fracture faces in a high-permeability, soft formation. In such scenarios, the effect of fluid leakoff on the fracture width profile for the case of arbitrary pressure distribution developed as a result of flow of non-Newtonian fluid through the proppant pack has been discussed in the literature. In this paper, the work has been further extended to include the effect of fluid leakoff through fracture faces for radial fractures.
The fracture face leakoff phenomenon is modeled using a generalized Carter equation, with different leakoff rates being incorporated in the form of fracture face leakoff coefficient values. The effect of fracture face leakoff on the final width profile, net pressure, fracture volume, and pack radius was investigated. It was observed that the width profile is significantly affected when fluid leakoff through the entire fracture face is considered. Controlling fluid leakoff through the fracture faces can result in much wider fractures because of large net pressure developed inside the fracture from fluid squeezing through the proppant pack.
This paper presents determination of aqueous phase composition of a new triglyceride microemulsion in which the triglycerides constitute the whole oil-phase of the microemulsion. Palm oil was used as the oil phase of the microemulsion. Experimental results indicate that the optimum triglyceride microemulsion was achieved when equal mass of palm oil and the aqueous phase containing 3wt% sodium chloride, 1wt% alkyl polyglycosides, 3wt% glyceryl monooleate, and 93wt% de-ionized water were mixed. The formulated composition of the aqueous phase was able to form translucent Winsor Type I microemulsion with palm oil at ambient conditions. The measured interfacial tension between the optimum microemulsion and the model oil, which is n-octane in this study, was 0.0002mN/m. The maximum tertiary oil recovery of 71.8% was achieved after the injection of the optimum microemulsion formulation to a sand pack. The significant increase in total oil recovery (87%) suggests the effectiveness of the triglyceride microemulsion formulation for enhanced oil recovery. Its capability in recovering additional oil (4.3% of the trapped oil after water flooding) compared to a typical polymer in tertiary oil recovery indicates the efficiency of the optimum triglyceride microemulsion formulation.
In this study, a transient multiphase simulator has been used to characterize the fluid-hammer effects of well shut-in and start-up on the coupled subsurface and surface systems. The original work was performed by applying sensitivity analysis on a typical production system that includes well completion, wellbore, downhole equipment like packer etc., and the associated surface equipment like flowline, riser and valves. The data used in the study was taken from the published literature to summarize the general course of key factors that worsen the fluid-hammer effects. Fluid-hammer is also known as water hammer, a shock wave produced by the sudden stoppage or reduction in fluid flow.
Field operations such as pressure transient analysis, facility maintenance and workover require well shut-in process. For a typical production system, the resulted sudden rises in pressure can be critical because it has direct impact on equipment including unsetting of packer and may also cause possible damages to instrumentations. This paper provides estimates of the typical ratio of transient shock in pressure and flowrate over pre-condition values, and the duration of such pressure shocks. It also proposes the best location of the shut-in valve and the length of flowline to reduce the fluid-hammer effects.
This is a pioneering approach to integrated multiphase flow modeling of transient fluid-hammer effects, targeting flow assurance issues. This approach also can be applied to surface facility design and served as a guidance in field operation to avoid hydrocarbon leaks.
Most of the mature field surface networks suffer from the back pressure applied on the wellheads. An extra pressure in front of the influent fluids should be overcome to handle the fluids to the final destination gathering point. This paper presents de-bottlenecking of Abu Attifel surface network and the solution proposed during production optimization phases. To capture the performance of Abu Attifel field wells, sixty wells single branch model were built using nodal analysis technique. All these wells were connected together to present the total field network. The network model consists of two different pressure systems. Low pressure system, which are 7 wells connected directly to the second stage separator, the remaining 53 wells are connected to the first stage separator operating at higher pressure. The network model was calibrated and matched globally through tuning of pipeline roughness and compared with the pressure measuring points at the gathering manifolds. As a result, reasonable match was obtained with 2% difference between actual and model calculated flow rates. All gathering points and well headers were matched with the available pressure and flow rate measurements. This validated network provided a valuable tool to evaluate, optimize and enable enhancement of the oil production. It defined several solutions to increase oil production such as converting some wells to the lower pressure separator, and the visibility to install two multiphase booster pumps in the flow line.
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.
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.
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.
Acharya, Mihir Narayan (Kuwait Oil Company) | Kabir, Mir Md Rezaul (KOC) | Al-Ajmi, Saad Abdulrahman Hassan (Kuwait Oil Company) | Mai'a, Noura (Kuwait Oil Company) | Kumar, Ashok (Kuwait Oil Company) | Pradhan, San Prasad (Kuwait Oil Company) | Al-anzi, Ealian H.D.
The unique Kimmeridgian-Oxfordian complex of unconventional and fractured carbonates has been tested to be prolific producer of gas, condensate and light oil in different wells discovered in various North Kuwait fields. The challenge is to characterize the complex reservoir flow system where critical reservoir parameters such as reservoir type, porosity and permeability characteristics, and production and pressure data can vary substantially.
The relationship between the natural fractures and the tight matrix in controlling effective system conductivity in reservoir flow units are the key features which dictate the nature of inflow mechanisms thus the production performance. The paper deals with developing an effective methodology which integrates the variations in critical reservoir properties of the low porosity yet naturally-fractured carbonate reservoir.
The drill stem test (DST) results in some wells were successful without stimulation, while in other wells the DSTs were unsuccessful in spite of advance and repeated stimulations, thus categorizing these plays as geologically-complex, tight gas condensate reservoirs where out of ordinary stimulation techniques may be needed to activate the fractured matrix. Pressure transient analyses and flow regime interpretation of the successfully-tested wells confirm the dual porosity flow-system and the fractured nature of the reservoir.
In this paper, the authors will discuss a new integrated approach for understanding the production and pressure behavior in light of the unique unconventional reservoir characteristics along with the fractured reservoir properties. Dual-layer and dual poro-perm models for pressure transient analysis have been applied extending the previous study of relationship developed between the productivity index (PI) and the total organic carbon (TOC). The proposed integrated methodology can significantly improve the current approach to production optimization, reservoir management strategy, completion, and stimulation design in fractured tight gas condensate reservoirs in Kuwait as well as in other regions.
In the previous study, Acharya et. al., 2009, observed the drill stem test (DST) success trend in the wells tested in the secondary targets in the kerogen and tight-fractured deep carbonate resercoir complex, across multiple fields in the study area in North Kuwait, is being controlled by the unconventional parameter. As the test results in several vertical wells had a positive to negative ratio of 1:1, where, the negative DSTs were either no-flow or no-hydrocarbon, in spite having all other conventional reservoir parameters comparable. This has become quite critical to establish an integrated understanding of the factor of successful unconventional reservoirs tests in multiple vertical exploratory wells, being linked to average total organic carbon (TOC) content of the particular sub-unit in the stacked reservoir sequence (Acharya et. al. 2009). The wells having average TOC content below 2.45% in the NJM unit have positive test results during initial DSTs. Average organic richness in term of total organic carbon (TOC) for NJK and NJM units in the fields under study is very high up to 12.5 wt % and up to 4.5 wt % respectively (Acharya et.al, 2009).
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.