First EAGE Workshop on Tight Gas Reservoirs 2009

Deep, tight reservoirs face significant appraisal and development challenges. In particular, it can be difficult proving the presence and mobility of sufficient quantities of gas to make the reservoir economically viable. At the same time, drilling costs are extremely high. In this context, underbalanced drilling (UBD) provides a number of benefits: first, it enables the operator to proof (i.e., provide physical evidence for) the presence of producible quantities of gas (so-called “testing while drilling”) while the well is being drilled. Underbalanced drilling also can minimize formation damage and maximize the rate of penetration. This, combined with reduced use of expensive mud formulations, can result in significant savings of drilling and completion costs relative to conventional drilling. However, not all reservoirs are suitable for UBD as there is much greater risk of mechanical wellbore instabilities relative to wells drilled overbalanced. We present a new, realistic approach that enables to increase the accuracy of predictions and at the same time takes scale as well as time depenent effects into consideration. The results of this type of analysis can provide an invaluable help for tight gas reservoir exploration and production.

The experimental results indicate that the tensile fractures are much less conductive than shear fractures and the shear fractures are less conductive than propped fractures. The concept of effective stress within the rock matrix is totally different than that of natural fractures; therefore, the effective stress function for both matrix and natural fractures should be separately evaluated to obtain representative functions for any simulation study. The tensile fractures lose conductivity at very early stages of reservoir depletion. Recommendations to manage these tensile fractures for optimum hydrocarbon recovery are suggested.

Operative and economical optimization of hydraulic fracture stimulation designs requires accurate reservoir description. For unconventional tight gas reservoirs it is commonly difficult to obtain reliable results from conventional build up analysis after flow testing a well because the time required to reach the IARF(Infinite Acting Radial Flow)could be much longer than normal rig time operations will practically allow. In many cases the impossibility of the well to produce after perforation makes the scenario even worst. Mini-Fall-Off injection test is economical and efficient technical solution to solve this problem providing an excellent starting point to understand unconventional plays and optimize the entire process of hydraulic fracturing technique. The scope of this work is to present an optimal operative processes which will allow understanding how, when and where it is recommended to apply this technology with the objective to optimize the hydraulic fracture stimulation. Following a theoretical description of this new methodology, several field applications studies in oil and gas fields are provided. In addition, this work includes a detailed guideline for planning execution and interpretation of the falloff pressure to obtain reliable reservoir transmissibility, reservoir pressure and closure pressure. Finally, the results of two cases were evaluated and it was determined that a simple field implementation could be adopted as a standard to be used in conventional pre-frac pumping procedures.

There exists a huge potential for tight-gas development in the Middle East and North Africa, through the application of hydraulic fracturing (both propped and acid). Although hydraulic fracture stimulation is not widely used in this area, there is some history of tight gas development using hydraulic fracturing in a number of countries. Oman has the most widespread development of tight-gas resources, in the Saih Rawl and Barik fields. Saudi Arabia has also developed some deep tight gas in the same reservoir, as well as from carbonate formations. A large number of gas/condensate wells have been fracture stimulated in Egypt, although these were not truly "tight-gas" wells. There has even been tight gas fracturing in Jordan, to a very limited extent. In North Africa, the bulk of tight-gas fracturing has been exploration well work in Algeria. More recently, tight-gas wells have been fracture stimulated in Morocco and Tunisia as well. In this paper, we will provide an overview of the experience and lessons learned from all of these developments, based on material published by ourselves and our customers and in-house data. Since our company has been involved to some extent in almost all of these projects, we have a unique overview on the experience built-up with tight gas fracturing in the region. This paper will provide a good starting point for engineers in the Middle East region who are only now starting to look at tight-gas developments and would like to know what has already been done. References • "Comprehensive Fracture and Production Analysis Leads to Optimized Fracture Stimulation Strategy in a Laminated Gas/Condensate Reservoir in Oman," SPE 82209, J.R. Shaoul, C.J. de Pater, M. Al-Hashmi, R. Langedijk. Presented at the 2003 SPE European Formation Damage Conference, The Hague. • "Hydraulic Fracture Optimization Maintains Original Production Rates in New Wells in a Mature Gas/Condensate Reservoir in Oman", SPE 88611, J.R. Shaoul, P. Giacon, A. Casero, A. Shueli, S. Al-Harrasi. Presented at the 2004 SPE Asia Pacific Oil and Gas Conference and Exhibition, Perth, Australia.

As Saudi Arabia increases their demand for natural gas inside the Kingdom, ongoing reservoir targets are moving increasingly to more challenging reservoirs which exhibit low permeability of <0.01 md. Reservoir pressure ranges from low or can be extremely high (11-13,000 psi) and the high temperature makes obtaining reservoir data increasingly difficult due to tool limitations. Two particular formations which have recently received attention is the Sarah and Qasim formation.The Sarah and Qasim formation creates a challenging environment for hydraulic fracturing due to the difficult environment and depth. This paper will identify theses challenges and discuss course of actions to overcoming them.

Reservoir sweet spots represent areas of improved permeability in tight reservoirs. Sweet spots are considered critical exploration targets to maximize productivity in deep tight reservoirs. Historically the process of identifying sweet spots from direct or indirect indicators relied mainly on seismic data analysis. This study presents concepts for development of three major types of sweet spots in tight reservoirs relied mainly on structural concepts: the structural-stratigraphic sweet spots; and the structural-digenetic sweet spots, based on the geologic processes involved in their generation. Integration of gravity, magnetic, seismic and outcrop data in the eastern Arabia province, with concepts of strain analysis are the basis of this study. Exploring for combined sweet spots is an economic demand of higher priority but it requires integration and much detailed analysis, using multi-data.

Specific data acquisition strategies have been developed to address the challenges of deep wells in tight reservoirs in remote and harsh environments. Advanced Mud Logging technologies have helped SRAK to gain trust in mud logging data sets to such an extent that this technology is now the prime source of information for certain datasets. Comparison of mass spectrometer derived mud gas data with downhole sampled gas has shown a very good compositional match. The targeted use of Logging While Drilling has been a successful strategy. In tight gas reservoirs that are typically drilled with high overbalance, it is difficult to obtain high quality data before invasion occurs. The high overbalance often results in deep invasion that may lead to underestimation of gas and other hydrocarbons. The use of LWD could also be used for fluid typing and as a permeability indicator when used in several time-steps across the same interval. This talk will also show how SRAK's decision to core both reservoir and non-reservoir facies rocks has helped to integrate all available data, from gas samples to core plugs, to come up with relevant conclusions on charge history and migration paths.

Basin-centered gas deposits are abundant in North America. A key property required to plan and optimize production in these reservoirs is permeability. Extremely low and often disconnected porosity results in small permeability, often in the nano-Darcy domain. An alternative to a physical measurement is a numerical simulation of fluid flow in a 3D digital pore space accurately imaged by high-resolution CT scanning. We present examples of this digital technique for two samples from the Williams Fork formation with the total porosity ranging from 0.01 to 0.10. The porosity of the first sample was about 0.08, dominated by fairly large pores connected by narrow conduits, presumably due to secondary dissolution of carbonate inclusions. This pore space was imaged in a micro-CT machine with a voxel resolution of 2.2 microns. The simulated permeability was in the 1 to 5 mD range (Table 1). The pore space of the second sample was not discernible at the micro-CT resolution. It was imaged in a nano-CT machine with a voxel resolution of 0.065 microns. Disconnected spherical pores of approximately 1 micron in size were discovered.

Commercial success and successful completion of tight gas prospects requires an understanding of the complexities of the rock matrices which can either promote or curtail production. Porosity, occluded porosity, variations in grain size, the total organic carbon, the formation of clay minerals in pore spaces, and the recognition of open or mineralized fractures, as well as seals and compartmentalization within the strata must be determined to assess potential productivity and to develop effective completion strategies. Often there is an absence of petrophysical models that can account for or predict and distinguish these reservoir properties and a dearth of formation evaluation data. Conventional formation evaluation measurements and conventional interpretation techniques are challenged when applied to tight gas reservoirs. However, the integration of a host of new technologies can significantly aid in the evaluation of gas shales and tight gas reservoirs, resulting in significant improvement and reduction in risk for development of tight-gas plays. With the use of newly developed geochemical sondes, nuclear magnetic resonance interpretations, acoustic compressional and shear velocities, borehole resistivity images and deep reading acoustic images, we can obtain accurate porosities, mineralogy, and total-organic carbon, gas, and water saturations and map fractures away from the borehole. Further, these measurements can be used to differentiate between lithofacies which either influence or curtail gas production and to compute critical geomechanical properties that predict which facies are favorable for hydraulic fracture stimulation and which might be frac barriers. The integrated petrophysical method has the potential to reduce completion cost and enhance production for vertical well prospects and provide valuable direction for drilling horizontal wells in gas shales and tight gas sand reservoirs.

The ability to predict reliably the performance of oil and gas wells is key to the economics of all development projects. The methodology used in the industry relies heavily on the quality of the data gathered from exploration and appraisal wells, and on workflows which involve reservoir simulations. For the particular case of tight gas reservoirs, this process requires some specific precautions or methods. The presentation will describe some key aspects which are relevant for tight gas reservoirs.