This paper highlights the difficulties and limitations encountered and the respective solutions proposed and executed during an acid stimulation campaign conducted on multiple offshore power water injector (PWI) and oil producer (OP) platforms in Saudi Arabia.
The field development concept for a mature brown field in Saudi Arabia includes a water drive mechanism, having unique placement of both onshore and offshore peripheral water injector wells for reservoir pressure maintenance. This field has a major concentration of extended reach hydrocarbon wells in the region. The offshore portion of the field has 83 developed wells on 13 platforms, with their openhole production profile ranging from 3,000 to 9,000 ft.
Post-drilling or -workover operations, acid stimulation is required to restore well productivity or injectivity affected by drilling mud damage. A heavy tar mat zone, which characterizes the field, adds to the relative complexity of the PWI wells, generating hard mixed deposit bridges. For optimum treatment, each well requires uniform acid stimulation with significant volumes of chemically inhibited and diverted acid to achieve uniform zonal coverage, which are placed through 2-in. coiled tubing (CT) to help protect the completion from corrosion. Based on multiple laboratory tests conducted by the operator, an optimized treatment gradient (gal/ft) was fixed for this campaign, corresponding to significantly large stimulation volumes of 1,700 to 5,100 bbl for PWIs and 1,500 to 4,500 bbl for OPs.
Because of offshore platform weight and space confinement issues, a rigless intervention technique was used, with a stimulation vessel handling the chemical additives, acid, diesel, and water logistics, on-the-fly treatment fluid mixing, and pumping, while a self-propelled barge handled the CT unit with nitrogen lift pumping capability and return handling system.
The successful combination of the CT intervention and stimulation vessel fluid handling system in this campaign resulted in greater than 300% improvement post-stimulation in terms of both injectivity and productivity, with wells averaging 5 to 6 days for execution. This paper includes case histories of wells that were successfully stimulated in this campaign. The multiple successes of this stimulation campaign imply that significantly large stimulation treatment volumes can be designed for a complex offshore environment.
Limin, Zhao (Chengdu University of Technology, Sichuan, China, RIPED, Petrochina) | Duan, Tianxiang (RIPED, Petrochina) | Han, Haiying (RIPED, Petrochina) | Xu, Jiacheng (RIPED, Petrochina) | Guo, Rui (RIPED, Petrochina) | Zhu, Xiang (Chengdu University of Technology) | Liu, Lei (Chengdu University of Technology)
Accurate geological characterization for complex carbonate reservoirs plays an important role in guiding the optimal oilfield development. Mishrif Formation of H Oilfield in south of Iraq is the most important target among several Cretaceous oil-bearing carbonate formations due to the high OOIP proportion. It is composed mainly of bioclastic limestone with multiple pore types. It is massive reservoir with medium porosity and low permeability. The great variation of vertical and lateral reservoir quality leads to poor relationship between porosity and permeability which brings great challenge in reservoir characterization and favorable area identification. This paper presents the comprehensive reservoir evaluation and characterization in combination of all data available. The sedimentology and stratigraphy are reviewed in terms of depositional environment and lateral stratigraphic correlation. The variability inherent to the depositional mode and digenesis leads to complex reservoir geometry and pore types. Rock typing is examined based on core measurements and well logs to get the improved correlation coefficient between porosity and permeability. Neutral network method is used to propagate the rock types to un-cored wells to get the accurate permeability estimation. Facies model and rock type model are built constrained by the seismic inversion reservoir prediction results which provide crucial information on carbonate proportions distribution, especially in areas with low well control. Permeability model is generated constrained by rock type and porosity which can indicate the reservoir flow capacity. Based on the integrated reservoir model, horizontal wells and multilateral wells for Mishrif Formation are proposed and optimized in the good reservoir quality area. The high individual well production rate verified that the well placements upon fine reservoir modeling are successful.
Lu, Qianli (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University) | Guo, Jianchun (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University) | Zhu, Haiyan (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University) | Zhao, Xing (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University)
Multi-cluster staged fracturing is an effective method to exploit shale gas. Field observations reported some clusters did not generate fractures. X formation in Sichuan Basin is a 3000m deep shale reservoir. The horizontal stress ratio (Shmax/Shmin) is around 1.4 which is therefore difficult to generate fracture network. How to enable all fractures propagate effectively from each cluster and generate enough stress interference to enable fracture network is of critical concern.
This paper established a 2D fracture propagation model based on finite-element method to simulate multi-cluster fracturing. The fracture propagation model couples seepage-stress-damage theories to simulate fracture propagation. The cohesive element is used to simulate the forming of fracture, and the filtration from fracture to matrix is taken into consideration. This model is used to study three fractures propagating simultaneously from three clusters. Different cluster spacing cases were simulated to investigate the fracture geometry and the stress field.
When the cluster spacing is 10m, 20m and 30m, the simulation shows that the length of the middle fracture is severely restricted; but for the side fractures, the length is over propagated. When the cluster spacing is 40m and 50m, balanced propagation of all the three fractures is achieved. In 10m, 20m and 30m cases, the stress field shows that in front of the middle fracture, there is a high compressive stress area caused by over propagated side fractures, and this stress could prevent the middle fracture from propagating. So the range of optimized cluster spacing is reduced to greater than 40m. In order to increase the possibility of generating fracture network, the cluster spacing should be small to create high rock frame stress between the fractures. By considering the fracture geometry and stress field, the optimized cluster spacing is 40m cluster.
This paper presented a method to optimize the cluster spacing by both considering the fracture geometry and stress field. Cluster spacing optimized by this method could enable the effective propagation of all main fractures and increase the possibility of generating fracture network.
The offshore oil and gas industry recognizes and agrees that there are too many instances of premature failures leading to loss of life, environmental impacts, reputation damage, increased downtime, and production losses. In response to this situation, there has been rapid growth in integrity management related research and development, however it has become difficult to keep track of all of this activity. The purpose of this state-of-the-art review paper is to summarize key findings and provide a comprehensive list of pertinent literature in the field of deepwater facilities integrity management. Focus is given to the latest information on integrity management systems, regulations, standards and recommend practices, and current industry challenges. The goal of this paper is to consolidate and provide the most updated information regarding integrity management, in order to assist those individuals and companies that are new to this field. Several of the referenced documents are available to the public via the World Wide Web. The references are provided for information only, and do not represent a comprehensive list of applicable standards, recommend practices, or regulations.
VICO Indonesia is an Oil and Gas company which has operated mature fields located in the onshore part of East Kalimantan which has been on production for over 30 years. The fields are dominated by gas reservoirs with a much lower presence of oil reservoirs. Production mechanisms cover from natural depletion to weak and strong water drive, particularly in some of the shallow areas. Recent well completions include single and dual slimhole monobore.
The field is a perfect combination of stratigraphic and structural traps with more than 4000 sandstone reservoirs where around 450 of those are oil reservoirs. The oil recovery factor for these reservoirs is in the range of 10-30%. Oil development in this fields performed using gas lift as the main artificial lift while several wells still flowing naturally. Coiled tubing gas lifted (CTGL) wells contributes to 60-80% of current oil production of 8000 BOPD.
Totally, 50 CTGLs have been installed in VICO Indonesia where most of those considered successful. The main problem found related with initial operation after installation. Lesson learned has been summarized including the design and the procedure for initial operation. Coiled tubing gas lift design and troubleshooting are rarely found in literature. Thus, this paper presents the detail step by step design and how to troubleshoot the possible failure during early operation. This approach exhibits a real benefit to recover more untapped hydrocarbon with more aggressive program.
Unconventional reservoirs (UNC) are considered those that do not produce at economic flow rates and cannot be cost-effectively produced without applying stimulation, fracturing, and recovery. They are located in predominantly extensive regional accumulations, which, in most cases, is independent of the stratigraphic and structural traps. This requires using special technology for extraction, either by its oil properties or the characteristics of the rock that contains it.
Today, these reservoirs represent an interesting source of income, because many of them are found in deposits that were considered to be exhausted or non-economic by traditional recovery methods, and it is estimated that they are present in large volumes. The recently exploited shale plays are typically constituted by a matrix of very fine grain rock (size clay, shale or marl might be), with varying proportions of clay, silica, and carbonate, which act as source rock, and reservoir seals at the same time. They have very low permeability and often require massive stimulation to produce hydrocarbon.
Generally, resource shale reservoirs must meet a series of requirements to make them economically viable. These conditions are: Organic richness (> 2% COT for shale gas and shale oil variable) Thermal maturity (> 0.7% Ro) Thickness (> 30 m) and areal extent Adsorption capacity (mainly in shale gas) Fracturability (clay content < 40%) Overpressure Depth Surface facilities
Organic richness (> 2% COT for shale gas and shale oil variable)
Thermal maturity (> 0.7% Ro)
Thickness (> 30 m) and areal extent
Adsorption capacity (mainly in shale gas)
Fracturability (clay content < 40%)
The US has experienced massive increases in reserves and production of natural gas from unconventional reservoirs. The scale of this increase is unprecedented and is the envy of the rest of the world. Largely as a result of general regional studies by the US Energy Information Agency (EIA) and others similar organizations which promise similar, and in some cases, even higher resource volumes than in the US, many other countries have embarked on unconventional gas exploration efforts.
This presentation will describe the impact of US shale gas and the success factors responsible for its growth. These factors include ‘below ground’ factors such as favourable geologic conditions, presence of natural gas liquids and abundance of well and reservoir data. These factors are, in varying degrees, present in other countries and regions as well.
However, the US also enjoys a number of unique ‘above ground’ factors such as a dynamic service sector, low cost operators, favourable tax and regulatory regime, easy access to pipeline capacity, availability of capital and technology, transparent gas prices, and property rights to land owners. These factors are much harder to find in other countries and regions and are more crucial, it can be argued, for development of unconventional gas than for conventional gas.
Thus, the answer to the question "Can the US model for unconventional gas development be repeated elsewhere?" is unfortunately, "NO". Unless governments and regulatory agencies take strong steps to improve their ‘above ground’ score, it is unlikely that these countries will enjoy the success of unconventional gas development to the same extent as the US.
Yang, Jing (PetroChina Research Inst. Petroleum Exploration & Development) | Jin, Baoguang (Geoscience Center of CNPC Greatwall Drilling Company) | Jiang, Liangliang (University of Calgary) | Liu, Fang (Research Inst. Petroleum Exploration & Development)
Due to the high demand to increase oil production combined with the huge potential in enhancing oil recovery, surfactant/polymer (S/P) flooding is under increasing interest and importance in recent years. Numerous studies have shown that interactions between surfactant and polymer can be extremely important to the final displacement performance of S/P flooding, since the desired effect of polymer and surfactant may be enhanced or degraded as various slugs become mixed underground. Nevertheless, as far as we know none of the available commercial numerical simulators can account for the impact of these interactions.
The study focuses on constructing an improved S/P numerical simulator. A series of experiments were performed on S/P mixed system and flooding process. The results show significant influence of S/P interactions on viscosity, interfacial tension, and adsorption, and the interactions can be totally different when injected into different S/P systems. Quantitative relationships of the interactions were then provided based on the results. Then, an S/P flooding mathematical model was established on the basis of mass conservation, with the description of various important phenomena during flooding process being included, especially for the interactions between surfactant and polymer. Adaptive implicit method was applied to solve the equations and a simulator was developed. The simulator was finally used to perform the numerical study of different S/P mixed systems, in which synergistic promotion, non-interaction and competitive repulsion were respectively presented. The displacement performance was the best when synergistic promotion existed between surfactant and polymer, followed by non-interaction, and competitive repulsion. In summary, a new method for the treatment of interactions between surfactant and polymer in numerical simulation was derived in this work. The improved simulator could enhance the matching degree between mathematical model and field data.
The well within the context of this case study consists of reservoirs are sequences of permeable sands interbedded with variable proportions of silt and clay. Gas is the target hydrocarbon type, but light oil / condensate can be present unexpectedly. In these depleted reservoirs, hydrocarbons typing are complicated by their reduced volumes and corresponding diminished effect on conventional logs. Wells are highly deviated and targets don't align in the same direction leading to high trajectories tortuosity. This prevents to plan extensive wireline logging program. Formation evaluation is mainly based on LWD logs.
For such challenging condition, fluids identification is traditionally made possible by stationary Nuclear Magnetic Resonance (NMR) from wireline conveyed logging devices, adopting Diffusion— Relaxation maps technique. Through Diffusion—Relaxation maps technique, the contrast on both diffusivity and relaxation time (longitudinal relaxation time
This study proves that LWD NMR, due to its logging while drilling features, enables the simple
Density Magnetic Resonance Porosity (DMRP) method is used to estimate the total porosity and gas saturation. It provides a resistivity independent method to address the gas saturation. Considering the fresh formation water, the uncertainty on the petro—physical parameters is significantly reduced.
This paper divulges the value of T2 based fluid typing method with LWD NMR tool. It provides a simple but efficient way to identify gas from light oil. The fluid information offered is essential for field completion decision making.
Objectives/Scope: This paper showcases how an integrated static and dynamic modelling workflow was applied to cover a wide range of subsurface uncertainties in order to generate a more robust range of forecasts. These forecasts are in the process of being used to optimize the ongoing development plan for a marginal offshore field in South East Asia.
Due to an anticipated lack of aquifer support, the initial phase of development was based on flank and crestal producers with peripheral water injection to deplete Miocene-aged reservoirs within a fluvial-dominated coastal plain to delta environment where the predominant lithologies are clean sandstones and sandy to muddy heterolithics. The results from the early development wells indicated a more complicated reservoir than has been previously interpreted, as evidenced from well results, formation pressure data, flowing /shut-in pressure trends and early production data across the field.
Methods, Procedures, Process: For a field with an increasingly complex geological and dynamic background, use of an integrated workflow covering both the static and dynamic parameters allows for seamless updating and ensures continuity between geological and dynamic models when assessing the field uncertainty. This is achieved by predefining value sets and their uncertainty ranges and employing an experimental design technique. The information for each realization is used to generate a proxy model, which is then used to interpolate an objective function between runs and thus manage uncertainty. The proxy model provides a quantified distribution for each combination of input parameters in the reservoir simulation model with approximate results for any set of modifier values then generated.
The methodology provides a better understanding of subsurface risk assessment in conjunction with assisted history matching, thereby optimizing the development plan. Using an integrated approach allows the geological model to be current at all times during the drilling campaign and potentially allows for optimization during the campaign.
Results, Observations, Conclusions: This case study presents the results of the Integrated Uncertainty Analysis Workflow which resulted in sets of realizations of multiple scenario-based history matched results, whilst maintaining geological consistency between the static and dynamic models for reservoir behaviour predictions. The oil production and recovery ranges were then determined from the probability and cumulative density function resulting from these multiple realizations.
The effectiveness and challenges encountered when applying the workflow in a real field example will also be discussed in this paper.
Additional Information: Risk can be quantified and uncertainty managed within both static and dynamic models through an integrated workflow that covers the entire reservoir modelling process from seismic interpretation through to simulation and reservoir predictions. This implies significant cost savings, as this workflow provides results quicker and generates a comprehensive quantification and management of uncertainty within the reservoir modelling workflow. The geologically-consistent models enabled the delivery of an optimized reservoir model for waterflood management; a probabilistic approach to production forecasting; and crucial input into maximizing recovery and optimizing the field's economics. Such a workflow has the potential to be updated in near real time, and executed in a time space in line of well construction – thus optimization of well placement based on changes in the underlying geology, whilst maximize recovery are potentially possible.