The recovery of unconventional oil such as heavy oil is receiving great interest as the world oil demand is increasing along with relatively high oil prices. Producing such high viscosity oil is complex and challenging, which usually require thermal techniques. Thermal recovery methods are widely used to recover the heavy oil and bitumen basically by thermally reducing oil viscosity, improving the mobility ratio and enhancing the heavy oil displacement. In response to the recent effort of leveraging heavy oil and tar plays in Saudi Arabia, Saudi Aramco has launched a new thermochemical research program to tackle challenges associated with lowering oil viscosity to improve well productivity and the overall reservoir depletion efficiency. One of the promising new technologies is enabling in-situ steam generation by chemical reaction (EXO-Clean) to mobilize the low API crude oil or tar reserves. In this paper a new steam flooding methodology will be introduced and compared with existing technologies. Steam will be generated in-situ by chemical reactions, which will have better efficiency and lower cost compared to conventional steam injection methods. Simulation study, lab experiments, and field treatment showed great promises of the technology. The developed EXO-Clean treatment relates to in-situ steam generation to maximize heat delivery efficiency of steam into the reservoir and to minimize heat losses due to under and/or over burdens and non-producing areas. The treatment consists of injecting exothermic reaction-components that react downhole and generate in-situ steam and nitrogen gas. The generated in-situ steam and gas can be applied to recover deep heavy oil, and tight oil reservoirs, which cannot be recovered with traditional steam injection methods.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThe use of unique or modified HF acid systems for matrix acidizing within the Niger Delta and some other parts of the world is still the preferred method for effective stimulation of sandstone reservoirs. The continued success of treatments done with modified HF systems in this area are due to its ability to mitigate the rapid spending of the active acid with clays and silicates; prevent matrix unconsolidation in the near wellbore region and the subsequent precipitation of acid reaction by-products within specific well applications. This success has brought about modifications to the acid system and new applications for various well scenarios. This paper discusses the successful application of a unique sandstone acidizing process that uses a single acid stage (no preflush or postflush is required) making multiple stage treatments much simpler while still achieving both economic and technical targets for the well. It covers the non-formation stimulation treatment of several wells using this single-step method and also describes a successful approach to improving the productivity of high water cut wells with severe finesdamaged gravel packs by this system. Unique experiences acquired during the field trials carried out within the Niger Delta using this system are evaluated. The results demonstrate a significant increase in incremental hydrocarbon production for normally high risk, low reward wells and remarkable stimulation cost reduction via reduced chemical volumes, less equipment requirements and shorter job times.Also included are a thorough analysis of actual candidate selection criteria, fluid chemistry, actual job design and operational issues during execution of treatments. Key technical and economical performance indicators including skin factors, production rates, specific productivity indices, treatment costs indicate that this system has certainly and successfully increased the application envelope for unique HF treatments within sandstone reservoirs.

HF-sensitive reservoirs that could not be hydraulically fractured nor effectively stimulated have been a challenge to the Petroleum Industry, hence locking the potential reserves that could otherwise be producible. These formations are typically those with high swelling clays, chlorite clays, feldspars and certain zeolites. Experience shows that even when such formations are stimulated with conventional HF- or HCl-based acid systems, the production performance declines shortly after the treatments, causing the reservoirs to produce at less-than-optimum rates. The skin damage associated with such reservoirs and stimulation by-products act as down-hole chokes, strangling production and increase drawdown. Successful stimulation of these kinds of HF-sensitive reservoirs had been carried out with a Organo-Phosphonic Acid Complex. Treatments have been carried out in seven Oil Producers, Water Injectors and Gas Injection wells in the Niger-Delta Nigeria and an oil producer in South East Asia. Post-treatment rates were above 800% of the pre-treatment values and more than 100% the maximum potentials ever recorded by most of these wells since they were commissioned. The new acid system offered true stimulation of carbonate and sandstone reservoirs as well as restoration to natural permeabilities of these intervals by the process of sequestration and complexation. An overall dramatic response of more than 200% over the wells treated with other formulations in the same basin was achieved. This paper discusses the non-HF based Organo-phosphonic acid formulations for Oil Producers, Gas Producers, Water Injectors and Gas Injection wells in both carbonate and sandstone reservoirs. The process of dissolution of the acid soluble and insoluble minerals that plug the near-wellbore region; candidate selection criteria; design; process of scale inhibition; field applications; results; treatment effectiveness and evaluations. The performance over other formulations is compared with respect to treatment costs, accelerated production, payback time, sustained production or Injectivity after treatment and percentage of original permeabilities being restored. Introduction The world's crude oil and gas come from limestone (CaCO3) / dolomite (CaMg[CO3]2) - Carbonate formations and quartz particles / Silicon dioxide (SiO2) - Sandstone formations. The carbonate formations could be found in their pure forms or in the form of carbonate or siliceous sands cemented together with calcareous materials whereas most sandstone formations are found in the form of quartz particles / silicon dioxide bonded together by various kinds of cementing materials, chiefly carbonates, silica and clays. Primarily, limestone and dolomite react at high rates with hydrochloric acid (HCl) and moderately with formic and acetic acids but sandstone reacts very little. The amount of reaction of these acids in sandstone formations depends on the amount of calcareous materials present. However, the silicon dioxide, clay and silt react with hydroflouric acid (HF). Since HF reacts with silt, clay, sandstone and most drilling fluids, it has been found effective in removing impairments and stimulation of sandstone reservoirs. The major defects of HF is the formation of by-products of calcium fluoride (CaF2) with calcareous material and sodium hexafluorosilicate (Na2SiF6), hydrated silica (SiO2·2H2O) and potassium hexafluorosilicate (K2SiF6) which are both insoluble and damaging precipitates. Carbonates, clays and iron compounds can ruin a well executed treatment. The chemistry of the reactions leading to the above insoluble and damaging precipitates are shown in appendix A. Fluorine is a very reactive element and since the composition of sandstone is varied, many reaction products can form when sandstone formations are stimulated with HF acid, hence HF-sensitive reservoirs that could not be hydraulically fractured nor effectively stimulated had been left unattended, thereby leaving the wells to produce at less-than-optimum potentials. Such reservoirs are predominantly made up of high swelling clays, feldspars, chlorite clays and certain zeolites.

A carbonate field in Saudi Arabia is undergoing major development requiring water injection wells to provide peripheral matrix water injection as pressure maintenance scheme to support oil production. The field is characterized by a tar mat zone, which potentially could isolate the oil reservoir from the planned pressure support and serve as a barrier for the water injection. Therefore, the injection wells were geosteered horizontally right above the tar " barrier?? into the transition zone between the heavy and lighter oil, which poses a challenge in assuring adequate pressure support to the producers, without leaving pockets of relatively high oil saturation behind the waterflood front. To address transmissibility uncertainty between producers and the injectors, long-term injection (LTI) pilot tests were designed utilizing one water injector and six observation wells to capture pressure signals. Building the surface facility to deliver the required test as planned was challenging, starting with the seawater as a source, to water treatment and ending with pump selection. This paper discusses the unique layout of the LTI surface equipment, a mini-plant by itself, and how operational challenges were overcome in the field. The authors highlight some operational issues related to the LTI test that had almost 90% efficiency from operating over 200 days and over 2 million barrels of injected filtered and treated seawater volume, as well as present valuable insights to demonstrate how a project of this scale was successfully executed and more value added to the development plans. The unique equipment layout comprised twin sea-submerged, skid-mounted electrical submersible pumps (ESPs), 6?? hoses, filtration unit, a chemical treatment unit, eight 500 bbl storage tanks, and a horizontal pumping system (HPS). The layout of the surface facility components, their performance and the importance of continuous water injection in addressing the test goals are discussed. The injection well performance was monitored by integrating Joshi's equation to Hall Plot and slope analyses to provide means of more meaningful use of injection pressure and rate data. The synergy of the mini-plant components coupled with engineered performance monitoring tools were enablers in this test design to help unlock more reserves. Overall, the test was a great tool to qualify field development plan assumptions, indicating that less powered water injectors than initially planned, are required Introduction Production from the carbonate field started several years ago from reservoir A with fluid and rock compressibilities being the primary drive mechanisms. Nearly 20 years later, production started from a lower reservoir Bb, and from reservoir Aa six years later. Due to low demand, it was subsequently shut-in. In all three reservoirs, (Aa, Ba and Bb) a continuous tar mat underlay the oil column and posed an uncertainty as to the extent it was sealing and effectively separating the oil column in the reservoirs from the underlying aquifer. Water injection was considered a priori since the assurance for an adequate natural water drive from the aquifer is low. With the present major development by means of peripheral matrix water injection as the planned pressure support mechanism, the tar mat created a potential challenge in assuring adequate pressure support for the field during production. Without an effective communication between the tar mat layer and the oil zone, with water flooding, a potential risk yet remains of leaving relatively high oil saturation pockets behind the flood front.

The challenge to make best producers for the least investment in tight gas reservoirs has always been with the oil and gas industry since production in many tight gas reservoirs is oftentimes marginal, at best. This paper presents solutions for better production in tight gas reservoirs through hydraulic fracturing. Properly engineered hydraulic fracture treatments are enablers to achieve overall economies of scale with development of tight gas reservoirs. These treatments are conducted to bypass completion damage and stimulate production from low permeability reservoirs. They are designed using simulators with a range of capabilities in an effort to maximize the economic benefit of the treatment, effective fracture length, and number of zones producing, fracture conductivity, acceleration of recovery, addition of reserves, and minimize job failures and treatment costs. To accomplish these goals, substantial amount of information is required to describe reservoir flow capacity and provide the data needed to predict treatment pressure response as well as fracture geometry and conductivity. These data will determine the optimum size of the treatment, the maximum proppant concentration that can be pumped, and the expected production response to the stimulation. When sufficient input data are available to characterize the reservoir, the fracture geometry can be accurately modeled with a capable simulator, the treatment goals listed above can be realized and an optimum design can be reached. The design process, including selection of proppants and fluids, pumping schedule, injected proppant concentrations, total job size, pump rate, and other parameters requires an idea of the desired outcome of the job: required fracture length, possible pack concentration and clean-up time. Critical measurements from testing of actual cores has allowed to sift through the chaff to find those "gems" in hydraulic fracturing that materially improve the completion efficiency in tight gas reservoirs. Introduction A definition of tight gas reservoir is "a reservoir that cannot be produced at economic flow rates or recover economic volumes of natural gas unless the well is stimulated by a large hydraulic fracture treatment or produced by use of a horizontal well bore or multilateral well bores."4 The major unconventional gas reservoir types include tight reservoirs, CBM, shales, and hydrates. Tight reservoirs are most important in terms of production (15.6 Bcf/D in U.S., 4 Bcf/D in Canada representing some 25% of Canadian Production)1. To some degree, there has always been production from unconventional reservoirs in virtually all North American basins in the United States such as Rocky Mountains, South and East TX, north LA, Mid-continent, Appalachia, Jonah/Pinedale, Natural Buttes, Wilcox Lobo, Cotton Valley/Travis Peak, and Clinton/Medina.