This paper describes a very successful acid stimulation treatment performed in AGIP's Trecate-Villafortuna Field. The matrix acidizing treatment used in-situ crosslinked acid (ICA) as the diverting agent. The treatment is unique because it represents the highest temperature application ever attempted for such a system and falls under the definition of high-pressure high-temperature (HPHT). The design process included temperature simulations, detailed laboratory testing, and a review of acid formulations that were used successfully in the Trecate-Villafortuna Field and elsewhere. Temperature simulations indicated that cooldown from the bottomhole temperature (BHT) of 180°C to at least 150°C could be achieved despite the high treating pressures that limited injection rates. Even after cool down, serious concerns about corrosion and the effectiveness of the ICA system still existed. Laboratory support included fluid optimization for high-temperature application of the ICA. The flow tests enabled the selection of the most appropriate base acid systems and demonstrated that the ICA system would indeed function at the predicted high temperatures. Success of the treatment must also be attributed to the operational planning and close attention to experience gained from previous stimulation treatments. The execution of the treatment used all of the components considered to be state-of-the-art in matrix acidizing treatment execution and evaluation: pre stimulation injection tests, spotting of acid with coiled tubing (CT) to help reduce injection pressures and improve zonal coverage, the use of the Maximum Pressure Maximum Rate Diversion Technique (MAPDIR), and real-time treatment pressure monitoring. The paper will present job procedures and a detailed treatment pressure analysis. It will also give details on the changes in injectivity and the Productivity Index (PI) before and after stimulation. Introduction The HPHT Trecate-Villafortuna well discussed in this paper produces oil from a naturally fractured dolomite reservoir at a depth of 6000 m. In this well, a new horizontal 220-m section was drilled and completed as open hole. The goal of the acid treatment was to remove the near-wellbore mud damage and to improve the permeability of the horizontal drain. The high pressure at 6000 m and the bottomhole static temperature (BHST) of 182°C, classify the acid treatment as HPHT. During the treatment design phase, two major issues had to be addressed:Potential problems associated with the HPHT character of the well: high acid-rock reaction rate, cross linking chemistry, and corrosion of tubular goodsProper diversion and optimal zonal coverage of the entire 220-m payzone High-temperature acidizing poses a number of problems during treatment design and execution, which are not normally encountered during treatments at lower temperatures.1,2 The high acid-rock reaction rate requires the use of a retarded acid system to ensure that acid will not all spend on the formation face (compact dissolution) but will penetrate deeper into the formation. Protecting the tubulars against acid corrosion is another serious challenge at high temperatures and requires careful selection of the acid fluids and inhibitor package design. In the following sections of this paper we will discuss these issues in more detail.

During the past decade, multiple transverse fracturing in horizontal wells has been applied so successfully in onshore low-permeability reservoirs that it is becoming the standard completion practice in many areas. The reasons for the success of this technique vary, but the two main reasons are related to the undisputed effectiveness of hydraulic fracturing as a production enhancement technique and the relatively low cost of pumping services in onshore areas. Success and industry eagerness for process/cost optimization have contributed to many technological improvements in the multistage completion process allowing sequentially executing several fracturing treatments in a single pumping operation. Nevertheless, the high direct and indirect costs and the risks associated with offshore operations have traditionally been limiting factors in spreading this technology to offshore applications. Sometimes, the misplaced perception of hydraulic fracturing as risky and costly operation prevented, rather than encouraged, its application in marginal offshore oilfields. Recent increases in oil prices and the success in onshore applications have encouraged the use of hydraulic fracturing in offshore applications. This study documents the successful effort of taking these techniques to the offshore environment. Transverse fracturing with multistage completion concept— with properly engineered design of well trajectory—can make the difference between the economic success or failure in the field development of low-permeability reservoirs. This study used multidisciplinary and integrated approach to design and execute the treatments, involving reservoir, production optimization, and fracturing engineers from the early stages of well planning to construction. The multilayer Foukanda field, located 52km offshore from Pointe Noire, Congo, has a low permeability and virgin target that was considered noncommercial after discouraging results of two wells. Based on the production results of three cased-hole wells in an analogous field where multiple propped fracturing was applied, the operator decided to drill an open-hole horizontal well that was to be multi-fractured. The initial 90 days average production of this Foukanda well was more than 2500bbl/day. This production rate was double the simulated rate of a vertical well and opened a wide range of further developments both in Foukanda and in other analogue fields in the offshore Congo. Introduction The Foukanda Marine field is located, 20 km to the north of the Kitina platform and 52km to the west of the city of Pointe Noire. Average water depth is around 100 meters. The field was discovered in 1998 by the well FOKM-1. Production started on June 2001. In the same year one well was drilled in the reservoir D but, due to very poor reservoir characteristic this level was abandoned and the well was recompleted on the shallower reservoir B4. The low permeability reservoir D (less than 10 md) was therefore abandoned and only the reservoir B4 and B7 put on production. In the first months of 2007 Foukanda field had a production potential of about 3000–3500 bopd with 6 producer wells (5 in the reservoir B4 and 1 in the B7) and 2 injector wells (2 in B4 and 1 in B7).

Perforations provide the communication between wellbore and formation resulting in a communication path both for injected and produced fluids from the reservoir. Many perforation parameters such as shot phasing, charges size, shot density, type of gun and length of interval play an important role in the correct execution of a fracturing job. Those parameters have to be engineered to guarantee easy formation breakdown, minimize near wellbore restrictions (or tortuosity) and be big enough to prevent proppant bridging while considering fracture treatment size, proppant concentration, proppant size and treatment flow rate. Ideal fracture initiation perforations would create a minimum injection pressure initiating a single fracture (not for shale gas reservoirs) and generate a fracture with minimum tortuosity at an achievable fracture initiation pressure. Best perforation practices are important during the decisional and designing phase but have to be confirmed by field experience even in well known reservoir where formation heterogenity, well deviation, local stress anomalies, cement bound and many other factors can result in unexpected behaviors that could compromise the success of the stimulation treatment. In the following paper a briefly description of perforating theories and different field experiences are reported showing test results executed for a better perforation strategy. Unexpected deviations both from theory recommendations and from field analogies were analyzed as well as successful and unsuccessful remedial solutions in cases of injectivity issues.

Not all unconventional plays are created equal, in a substantial number of regions around the world the tectonic environment is quite different from the typically relaxed and more passive states found widely in most, if not all, of the US unconventional plays. This is merely a function of the relative proximity of such plays to distinct geological features characterized by active tectonic plates and with dynamic margins and recent activity. The Nazca plate associated with the Andes, the Arabian plate linked with the Al-Hajar mountains and the Indian plate connected with the Himalayan mountain range are just a few examples of tectonically influenced regions, where potential hydrocarbon traps are subject to complex states of stress generated by convergent plates, subduction zones and associated faulting. This scenario often translates into severe strike-slip and reverse fault stress states. Additionally, the presence of both multi-layered and laminated formation geology as well as the presence of overpressure and pressure differentials, typical of tight gas and shale gas, can exacerbate this situation even further. This situation can result in an extremely challenging environment for the successful execution of hydraulic fracturing and the associated development of unconventional resources. This paper will demonstrate, that such complex stress-states will directly affect well completions and hydraulic fracturing in a multitude of ways, but that some of the most impactful consequences are often severe casing failures, production-liner restrictions and complex fracture initiation scenarios. Casing failures are responsible for increased intervention costs as well as higher costs for the upgraded and strengthened wells. Equally, such issues can severely impair efficient execution of the completion plan and create a bottle-neck to subsequent well production. Horizontal, complex and pancake fractures will typically develop in strike-slip / reverse fault stress states, often resulting in fracture conductivity and connectivity loss that will greatly impair the eventual well performance. Layer interface slippage and natural fault re-activation are dominant mechanisms for hydraulic fracture induced casing failures. Examples of micro-fracs, micro-seismic and other diagnostics will be presented aiming to document the practical difficulties encountered while completing wells in these complex environments. This paper will demonstrate that unconventional development in such environments requires a renewed focus on all aspects of well design and construction, from directional drilling and lateral placement to casing selection and lower completion design. All these considerations are made with the goal of enabling the competent delivery of a highly effective and conductive fracture network, to efficiently access and produce the hydrocarbon resource.

In the past two decades, the advent of the Shale Gas Revolution (SGR) was made possible by the visionary idea that hydrocarbons contained in ultra-low permeability source rocks could be extracted using available technology. Usually, these hydrocarbons take geological time to migrate to higher permeability reservoir rocks until the right structural conditions evolve to extract as recoverable resources. However, paradigm shifts in drilling and completion engineering have enabled unlocking resources from these ultra-tight formations. The innovative idea at the base of this industrial revolution was the combination of horizontal well drilling and hydraulic fracturing, which allowed increasing the surface area available for hydrocarbon flow and overcame the slow and shallow hydrocarbon release from the source rock. This approach can be considered as a bridge between petroleum engineering based on radial diffusivity equation and mining engineering based on physically accessing and extracting the resource. To achieve the high number of hydraulic fractures needed for economical production, different execution techniques evolved and developed in what is known as horizontal multistage fracturing (HMSF) completions. Although HMSF is indescribably linked to SGR, it was surprisingly applied in tight gas formation and offshore sand control applications more than 30 or 40 years ago. SGR contributed to the fast development of new innovative systems engineered and deployed at scale all over North America land operations and was subsequently exported internationally in conventional, unconventional, land, and offshore applications. This paper will cover the most common HMSF completion systems types with a primary focus on unconventionals. It will encompass the evolution of these systems over the past several decades. It will also explore the opportunity case for conventional, and high permeability plays through a series of theoretical and real examples.