Shrivastva, Chandramani (Schlumberger) | Al-Mahruqy, Sultan Hamed (Petroleum Development Oman) | Mjeni, Rifaat (Petroleum Development Oman) | Al Kindy, Sueliman (Schlumberger) | Hosein, Feraz (Schlumberger Oman) | Al-Busaidi, Hafidh (Schlumberger Oman) | Al-Busaidi, Jokha (Schlumberger) | Laronga, Robert J.
Borehole images play a crucial role in tight gas exploration. Recognition of sedimentary features helps in understanding the depositional architecture and allows refinement of the facies model for flow unit identification and stimulation treatment. The structural analysis of faults and fractures provides clues not only about the tectonic history, but also about the possible conduits for fluid migration that lead to diagenesis. The diagenetic imprints and their impact in a sequence stratigraphic
framework can be understood through textural analysis performed on the borehole images across the field. And, hydrofracturing of tight gas reservoirs require important input from the borehole images in understanding the variability of stress regimes.
Established micro-resistivity imagers for the water-base mud (WBM) environment provide robust results, except when there is a large contrast between the formation resistivity (Rt) and the mud resistivity (Rm). With more frequent use of hyper-saline mud, a new and improved definition imager is deployed to obtain high quality images. Novel hardware and improved signal processing algorithms are employed to acquire the images despite the hostile conditions provided by the combination of lowresistivity salt-saturated (WBM) and high formation resistivity that would otherwise impede the data quality. Early field testing of this enhanced capability took place in the Sultanate of Oman and the examples of its improved performance are presented.
Getting the most detailed image data in oil-base mud (OBM) is challenging compared to the WBM systems. As an alternative to the options commercially available in the industry today, the new high-definition imager developed for the WBM system can also be used under favorable conditions to acquire valid images in the OBM. The high-definition imager works best in OBM when both formation resistivity and mud permittivity are high.
A workflow is developed for the Go - No Go decisions for borehole imaging tools in different mud systems for tight gas reservoirs. It is important at the planning phase of the logging programs to anticipate the imaging tool behavior in the proposed mud system and conditions. The results from trials made in the tight gas reservoirs of North Oman provided the basis for a decision tree for imaging, since the logging environment exerts a strong control on data quality. The decision-tree presented here aims to ensure that images acquired are the most suitable for detailed geologic interpretation and subsequent integration in development plans for optimal exploitation of tight gas sands in Oman.
Jasem Al-Saeedi, Mohammed (Kuwait Oil Company) | Al Fayez, Fayez Abdulrahman (Kuwait Oil Company) | Rasheed Al Enezi, Dakhil (Kuwait Oil Company) | Sounderrajan, Mahesh (Kuwait Oil Company) | Saxena, Ashok (Kuwait Oil Company) | Chimirala, Vivekanand (Schlumberger D&M - Kuwait) | Mckinnell, David Charles (Total)
Recent drilling activities in the State of Kuwait have focused on the search for high quality oil from the Jurassic formations. The wells drilled to these prospects are very challenging because of HPHT conditions, presence of high levels H2S and CO2, and narrow pore/fracture pressure windows.
The targeted Jurassic formations are the Najmah-Sargelu and Middle Marrat, which are located below the Gotnia salt/anhydrite. These reservoirs consist of layered shales and limestones, which can be highly fractured. One of the main challenges in the effective development of these reservoirs is the ability of the wells to access a permeable interconnected vertical fracture network. Horizontal well profiles increase the probability of crossing multiple fractures or fracture swams, resulting in high productivity and reserve recovery per well.
A ‘Conceptual Project' was set up with the objective to design the first horizontal well to be drilled through the Najmah reservoir, in the North Kuwait fields. The challenges included; the establishment of an optimum well trajectory, drilling through the mobile salt section of the Gotnia at well inclinations above 60º, planning a pilot hole in the reservoir section to facilitate positioning of the lateral, identifying suitable water base mud system to improve image log quality, planning a high DLS openhole sidetrack just below 10 3/4" casing shoe and introducing a casing string (just above lateral) to address borehole stability concerns.
To address these challenges a team based approach was established between operator and contractors, to develop the well design, detailed engineering and operational procedures. This paper will describe the methodology adopted during this well design process and the technical challenges faced and overcome.
Flores, Vincent Pierre (VAM Drilling) | El Bachiri, Kamal (VAM Drilling) | Fei, Li (Zhongyuan Drilling Services, Sinopec) | LI, Fei (Sinopec - Zhongyuan Oilfield Drilling Services) | Zhang, Da (Zhongyuan Drilling Services, Sinopec)
Puguang region is known for containing sour fields with significant amount of H2S. Since 1975, sour service wells have been drilled entailing critical drilling conditions. To optimize drilling efficiency without sacrificing security, drill string improvements have been always looked for, by carefully evaluating steel grades, drill pipe sizes and connections.
The evolution of drilling programs has driven the industry to develop more suitable solutions adapted to extreme and aggressive conditions such as Sour Service environments. High strength drill pipe is often necessary to achieve deeper drilling performance, even when Sulfide Stress Cracking susceptibility is observed in minimal concentrations of H2S in partial pressures. Due to the astringency of the sour environment, particular precautions have to be defined to select and
characterize an adapted Sour Service steel grade.
This paper presents the evolution of choices in drill string design from basic API grades and connections to adapt and proprietary steel grades resistant to H2S with a high mechanical performance properties and high torque double shoulder connections.
Recent work has shown the potential usefulness of magnetic susceptibility and hysteresis techniques in assessing the impact of fine grained hematite on permeability in red and white sandstone samples (Potter et al. 2009; Ali and Potter, 2011b). The present study demonstrates that hematite cementation is a major controlling factor on permeability in a deep tight gas reservoir in the North Sea. Magnetic susceptibility measurements undertaken on core plugs in this reservoir showed a strong correlation with probe permeability performed on the same plug samples. Moreover, samples with a higher content of hematite exhibited lower permeability values. Thin section analysis revealed the presence of a thin (approximately 10-15µm) rim of hematite cement surrounding quartz grains, which block pore connections and reduce permeability.
Magnetic hysteresis measurements on some representative samples indicated a very similar paramagnetic clay content in both the low and high permeability samples suggesting that the clay (mainly illite) is not the dominant controlling factor producing the variations in permeability that we observed. Since samples with higher hematite content exhibit lower permeability it appears that hematite is a major control on the permeability variations seen in this reservoir. Whilst the paramagnetic clays undoubtedly have an influence on the absolute permeability value, since increasing paramagnetic clay content has previously been shown to correlated with decreasing permeability (Potter, 2007), small amounts of hematite cement can significantly further reduce the permeability. Analysis of the magnetic hysteresis parameters on a Day plot indicated that the permeability was essentially independent of the hematite particle size for the fine particle sizes observed in this study.
Exploration for shales has become an integral part of many operators' processes in the North American shale boom. While leveraging public data in existing plays is a major advantage, when looking outside those existing areas, a comprehensive plan must be developed. The shale-exploration methodology is fundamentally different from conventional exploration, with different drivers and metrics.
Shale exploration requires an exploration program that includes a heavy data-acquisition element. Beyond the initial geological identification of the prospect, wells need to be drilled to evaluate the potential of the shale prospect. Extensive coring, open-hole logging and formation pressure testing are required to answer four basic questions: Does the shale have enough total organic content? Does the shale have the thermal maturity necessary? Does the shale have the stimulation potential? Does the sale have a simple structural environment conducive to horizontal drilling? Once these questions have a satisfactory answer, the key shale properties can be mapped using multiple sources with the goal of identifying core areas suitable for further horizontal well evaluation.
This paper describes the process and workflow for a data-acquisition program and demonstrates not only the benefits of acquiring specific data, but also highlights the uses of the data to aid the exploration decision process. Examples are given of the type data acquired, and the analytical workflow is discussed.
There is a very significant move today towards multiple zone fracturing operations in a single well where zones are separated and individually fractured, particularly in shale gas completions. This technique has to date involved the use of ball seat activated sliding sleeves located across each zone, with consequent reductions in internal diameter (ID) and attendant flow characteristic limitations or selective perforating, fracing and isolation with a bridge plug in a cemented casing string while working up the hole. Both approaches involve many downhole intervention operations such as perforating, shifting sleeves, running plugs and subsequently milling them up with coiled tubing (CT) intervention, all of which extend the length of the operation and add to the overall costs.
To simplify the process of multiple fracturing operations, especially in open hole, a new approach has been designed which uses Radio Frequency Identification (RFID) techniques to remotely operate sliding sleeves. The number of sleeves that can be run in a well using this technology is essentially unlimited, each one having the same ID and a unique electronic address which allows it to be operated remotely at will. This approach provides for a means of making considerably more zones available for treatment without physical intervention with CT or wireline and thereby speeds the multiple frac operations and allows for wellbore clean up from the toe to the heel of the well.
In this paper the authors will describe the design and operation of the RFID operated frac sleeves and the advantages they provide. They will go on to detail the Worlds' first remotely operated horizontal openhole frac completion where frac sleeves and swell packers were used in an extended reach horizontal shale gas well.
Tight gas reservoirs show challenges to geologists to characterize because of their tendency to be generally heterogeneous due to depositional and diagenetic processes. The value petrophysical properties are very valuable in static and dynamic reservoir modeling. This paper presents a prediction of Klinkenberg permeability by using artificial neural network, composite logs and core data in basin in western USA. The klinkenberg model approximates a linear relation between the measured gas permeability and the reciprocal absolute mean core pressure. This model has been a consistent basis for the development of methods computing the absolute liquid permeability of a core sample based on a single data point.
In tight gas reservoir with increasing in gas slippag ( klinkenberg effect) cause to decrease in pore-throat size and permeability parameters. In advanced there were some method to determine Klinkenberg permeability in situ which can be obtained by measuring just routine air permeability and Klinkenberg parameter such as byrnes in 1997 & 2003 but these ways intensively depend on core permeability, so it needs some core plugs and inevitably we have to spend much time and money.
The goal in this study was to research about relationship between core Klinkenberg permeability and composite logs (gamma ray, density, neutron and formation resistivity and so on) by using MLP & Back Propagation methods (Artificial neural network) to characterize the Klinkenberg permeability in situ in 3 different wells in 3 stages (training, validation and application) with suitable core calibration. For two wells there is very good core calibration and the R2 is more than 0.7 in training and application processes.
The importance of evaluation of tight gas reservoir with high heterogeneity by using artificial neural network and conventional logs is spending less capital or time and finally obtaining reliable Klinkenberg permeability in situ.
Technological advances and improved operational efficiency have made unconventional resources around the globe far more lucrative for producers. The challenge in recovering hydrocarbons from unconventional resources is low permeability, making it essential that a cost-efficient fracture-stimulation treatment program be performed. However, while the wells being completed are economical, are operators truly capitalizing on their full potential?
The process of fracturing unconventional reservoirs has remained virtually unchanged in recent years. Stimulation treatments are pumped at high rates through multiple perforation clusters over a large interval and isolated using mechanical plugs. This poses several problems:
- Uncertainty of the number of fractures created.
- Uncertainty of proppant placement into fractures.
- Costly and time-consuming recovery from screenouts.
- Pumping plugs results in overflushing the near-wellbore.
- Treatment changes cannot be seen at the perforations until a casing volume is pumped.
- Increased cost, footprint, personnel, and hydraulic-horsepower (HHP) requirements.
This paper presents a high-rate coiled tubing (CT) fracturing technique that enables customized fracture treatments to help maximize stimulated reservoir volume (SRV) by manipulating flow rate and proppant concentration at the perforations in response to reservoir pressure. Therefore, every gallon of fluid and every pound of proppant can be used to effectively stimulate the formation. Recovery from screenouts is fast because of having coil in-hole, but the functionality of the process enables screenouts to be avoided all together. At the end of the treatment, the well is simply cleaned out, and the entire operation is completed with only one trip in hole and with no plugs to be drilled out. These benefits combined can maximize return on investment for the operator. This paper includes a side-by-side comparison of this technique with a conventional fracturing treatment, weighing risk, stimulation effectiveness, operational efficiencies, and cost savings.
Rahim, Zillur (Saudi Aramco) | Al-anazi, Hamoud Ali (Saudi Aramco) | Kanaan, Adnan (Saudi Aramco) | Habbtar, Ali Hussain (Saudi Aramco) | Omair, Ahmed M. (Saudi Aramco) | Senturk, Nejla Halime (Saudi Aramco) | Kalinin, Daniel Anatolievitch (Schlumberger Middle East)
Hydraulic fracturing technology is widely used to facilitate and enhance the gas recovery process from conventional and tight gas resources. Tight gas or unconventional reservoirs, that include very low permeability sandstones, carbonates, or shales, cannot be economically produced without hydraulic fracturing. Recently, much progress has taken place in the overall hydraulic fracturing procedures and the field implementations of advanced stimulation technology have produced good results. The proper selection of well trajectory, gel concentration, polymer loading, proppant type/size and concentration, perforation methods, locations for packer and frac port placement in a multistage fracturing assembly, number of fracture stages to cover the net pay, etc., have all contributed to
successful stimulation and improved gas recovery. Even though stimulating gas reservoirs has become a routine application and much experience has been gained in this area, not all treatments are straightforward without problems and challenges. Unless a stimulation treatment is carefully designed and implemented, the post-stimulation results in moderate to tight reservoirs may not be encouraging, and can easily fall below expectation.
The most essential step to close the gap between expected results and actual well performance is to understand reservoir characteristics and its potential to produce at a sustained rate after a successful fracturing treatment. Overestimation of reservoir flow capacity and achieved fracture geometry will also over-predict well performance.
This paper addresses the importance and impact of detailed reservoir characterization and superior stimulation processes on final well performance. Several field examples from Saudi Arabia's gas reservoirs are presented in the paper showing the value of effective well planning, reservoir characterization, application of hydraulic fracturing, and proper cleanup.
The paper also illustrates the impact of drilling trajectory and wellbore reservoir connectivity on the proper placement of desired hydraulic fracture treatments and sustained gas production.
Hydraulic fracturing has become a critical component in the successful development of unconventional reservoirs. From tight gas, to oil and gas-producing shales and coal bed methane, resource plays rely on hydraulic fracturing for commercial viability.
A primary goal in unconventional reservoirs is to contact as much rock as possible with a fracture or a fracture network of appropriate conductivity. This objective is typically accomplished by drilling horizontal wells and placing multiple transverse fracs along the lateral. Reservoir contact is optimized by defining the lateral length, the number of stages to be placed in the lateral, the fracture isolation technique and job size. Fracture conductivity is determined by the proppant type and size, fracturing fluid system as well as the placement technique.
While most parameters are considered in great detail in the completion design, the fracture geometry and conductivity receives lesser attention. Some mistakenly anticipate that in extremely low permeability formations, hydraulic fractures act as "infinitely conductive?? features. However, many factors that affect the realistic conductivity of the fracture are poorly understood or overlooked. This often leads to a less than optimal outcome with wells producing below the reservoir potential.
This paper presents an approach to assess the realistic fracture conductivity at in-situ conditions and the economic implications on proppant selection. The effects of transverse fractures, low areal proppant concentration and flow dynamics, are considered among other variables. The theory behind this concept is presented and supported with case studies where it has been applied in the field to various unconventional reservoirs.