A horizontal hot deep gas well was not on production due to high water cut. The well had a bottom hole temperature of 300°F (149°C) and a bottom hole pressure of 7,000 psi. The well was completed into a carbonate reservoir with an average permeability ranging from 2 to 3 mD. It was completed with a 7 in liner at a measured depth (MD) of 13,611 ft. The open-hole section extends from 13,611 to 16,456 ft. After the well completion operation, water was observed entering the open-hole section at the toe at a depth of 14, 677 ft. The exact water producing zone was identified by the resistivity log run on the subject well. Therefore, a mechanical packer was set in the open-hole section at 14,677 ft to isolate the water producing interval. The packer did not solve the problem. The water production continued to occur. Due to their versatility, polymer gels were considered for remediating this problem and to revive the well. A gel system based on a low molecular weight polymer crosslinked with an organic crosslinker was considered. A serious challenge was the high temperature of the reservoir. The high temperature conditions imposed the use of a retarder to elongate the onset gelation time during the polymer gel placement. The available mixing waters in this field contained significant amounts of salts (a total dissolved solids content of 1,188 ppm). These solids caused compatibility problems upon contact with the commercially available retarder. Therefore, a new retarder was developed. The retarder was cost-effective, efficient and compatible with the available saline mixing water. The retarder's placement was examined in porous media under conditions similar to those encountered in the field (55 minutes placement time). The gel did not show any injectivity problems indicating the efficient nature of the retarder. The initial recommended recipe of the gel showed syneresis due to the extra amount of the crosslinker suggested. This was addressed by reducing the crosslinker concentrations in the gel recipe. The treatment utilized a pre-flush to displace the reservoir fluids around the wellbore and to cool down the near wellbore area. This helped reduce the near wellbore area temperature from 300 to 240°F according to the temperature simulations. The gelant contained 250 gal/1000 gal of polymer with a 10 gal/1000 gal of crosslinker. After the gelant placement, the well was shut-in for three days. Once opened, the well showed an increase in gas production by a factor of 7.7 with a water cut reduction of 42 %.

We have investigated the siting and distribution of Al atoms in the zeolite clinoptilolite using periodic lattice simulation techniques. A novel procedure is presented for the study of the unresolved problem concerning the Al atoms siting in heulandite-structured materials. The resulting structural models are in excellent agreement with experimental studies and show preferential aluminum siting at T2 and minimal aluminum occupancy of T5. We show how Al−Al and Al−Na interactions are important in the siting of Al atoms in low Si/Al regimes. We also show the importance of lattice relaxation in finding the lowest energy aluminum distribution and the failure of standard Monte Carlo techniques in this context.

The reactions of ethylene, propene, and acetylene with two different zeolite models are computationally characterized using both semiempirical and ab initio methods. The MP2/6-31G* level calculations give activation energies which appear too high in comparison with the estimated experimental values. The DFT values seem more reasonable. The AM1 and PM3 transition state structures appear dubious with respect to both ab initio results and generally accepted intuitive descriptions.

The isotope-exchange reactions of D2 and CD4 with a zeolite model are analyzed using a b initio calculations.It is concluded that these exchange reactions could occur with activation energies in the 25-40 kcal/mol region. The mechanisms for these exchanges are different than those encountered in previous modeling studies of the addition of ethylene, acetylene, and formaldehyde to the acidic sites of zeolites. The addition mechanisms come close to conceptually involving ZO-,HR+-like transition states. However, the exchange-reaction transition states have anionic character for the transmitted moieties, H-and CH3-, respectively, and two protons are strongly attached to the oxygen of the zeolite model. In the case of isotope exchange of water, protonated water, and Dz and CD4, the transition states come closer to involving fully proton-transfer structures.

Ab initio and semiempirical calculations are used to characterize the reaction of formaldehyde with model zeolite structures, ZOH, to form hydroxymethylated products, ZOCH2OH. Both single-site and two-site models are investigated. The calculations show that the two-site reaction has a low activation energy of only a few kilocalories per mole. In this latter case, the mechanism of the reaction involves a concerted proton transfer from the zeolite to the formaldehyde oxygen, while the C -O &nd is being formed at the adjacent oxygen on the zeolite structure. Only the product configuration, ZOCH20H, is found to have charge-transfer character due to the ionic nature of the ZO-C bond. Although no distinctly zwitterionic complex of the type ZO-, CH20H+ was found, it was determined that such a structure is not far in energy from the transition state.

Successful fracturing treatment necessitates expensive completion assembly that provides some form of isolation to perform controlled fracturing treatments. Currently isolation is performed mechanically which dictates that isolated interval is very short. This in turn may require that the well is cased, cemented and perforated. This would increase the cost of completion significantly. Another option is to focus the fracturing energy via the use of hydrajetting. In this paper we present another approach that provides a high degree of control on where the transverse fractures will initiate and propagate.The various existing techniques for creating multiple hydraulic fractures along an openhole horizontal well are briefly summarized. Laboratory experiments shedding light on some of these techniques will be first presented. The new technique to precisely place a hydraulic fracture in an openhole horizontal well drilled in any direction relative to the in-situ stress field is presented. The new technique is based on rock mechanics understanding of an openhole horizontal well under a given insitu stress field; thus it accounts for the near wellbore stress field to ensure creating a planar hydraulic fracture. Additionally, the new technique does not require costly mechanical isolation to place a hydraulic fracture. Basically, the new technique aims to bypass the near wellbore stress field such that the fracture can be conveniently initiated independently of the stress direction.This new approach is validated using laboratory experiments which will be discussed in details. The experiments were performed on simulated wells casted in rock samples with dimensions of 6"x 6"x10". The samples were triaxially loaded simulating various arrangements of a given wellbore relative to the in-situ stress field. Then, the simulated wells were hydraulically fractured using water based gel. Fracturing pressure versus time was recorded and analyzed.The experiments were very successful in proving the new concept to fracture openhole horizontal wells. The developed technique is fairly easy to implement and the impact of precise placement of a hydraulic fracture across an openhole horizontal well is illustrated.

disposal and handling concerns, and corrosion of tubulars and surface equipment.Current literature describes RPM treatments that use various types of chemical treatments in essentially all lithologies. If these treatments were successful in all cases, RPM technology would be applied more frequently than is currently indicated. Despite claims of success, none of the materials or techniques used in RPM processes have performed consistently well in field operations. Although the literature contains several theories on RPM mechanisms, 1-3 none appear to be universally accepted. This lack of consensus may exist because no single factor determines the success of an RPM. Rather, an RPM's success depends on several well and reservoir characteristics, including chemistry, lithology, problem type, permeability, saturation, and many others.Because all of these factors affect the outcome of an RPM treatment, developing a single RPM for all well situations is unlikely. Instead, a better solution may be to focus on specific reservoir conditions and to design a treatment process that fits those circumstances. A polymeric RPM was developed recently that allows such customization when used with a systematic approach of proper preflushes and post-flushes. 4 Conventional Water-Reduction SystemsTwo categories of chemical systems are available for reducing unwanted water production in a porous medium: (1) nonsealing systems that allow the flow of fluids, and (2) sealing systems that completely block the flow of fluids.Nonsealing Systems. Nonsealing systems are typically diluted solutions of water-soluble polymers that adsorb onto the formation. These polymers most likely reduce effective water permeability through a wall effect, 1 where the polymer adsorbs onto the formation and creates a layer of hydrated polymer along the pore throat, which inhibits water flow.Sealing Systems. Sealing systems are porosity-fill materials, which can be valuable when a water-producing zone can be mechanically or chemically isolated. However, in many situations a target zone cannot be isolated and the sealing system sometimes penetrates zones that should not be treated. Although claims that sealing systems will reduce water permeability more than they reduce oil permeability have been made, pumping such Abstract For many years, relative permeability modifiers (RPM's) have received a great deal of attention from the oil and gas industry. Because of the completion techniques used in many wells, protecting the hydrocarbon interval properly during a watershutoff treatment is not always practical or cost effective. RPM's offer the option of bullheading a treatment without zonal isolation, which is designed to decrease water production with little or no decrease in oil or gas production. This paper describes the laboratory development and optimization of a polymeric RPM. The resulting material can best be described as a brush polymer consisting of a polymeric backbone grafted with methoxypolyethylene glycol (MPEG). Various phases of the development are discu...

Recently Saudi Aramco and international companies started an aggressive gas exploration campaign in tight gas sandstone formations. In most of the cases the prospective tight gas producing zones were discovered at a depth below 20,000 feet where the stress and temperature are extremely high and the reservoir permeability conditions are low; being necessary in all cases to fracture stimulate each horizon to define the fluid and evaluate productivity. The extreme stress and temperature conditions are actually one of the main challenges to perform fracture stimulations on this type of formation, this because the fracturing fluid needs to be stable, induce minimum damage and have good proppant transport capabilities at high temperature conditions. As a part of the referenced exploration activity in the first quarter of 2008 Saudi Aramco has the challenge to perform a proppant fracture stimulation in a deep tight gas on shore sandstone formation where the temperature and stress conditions (375° F and 1.1 psi/ft at 20,000 feet) exceeded the working pressure capability of the available equipment and the existing fracturing fluids application limits. To answer the referenced challenges and knowing that 20,000 psi fracturing equipment is not available in the area an extensive laboratory evaluation was done to design a new high density fracturing fluid. After a lengthy laboratory evaluation, we were able to select a regional supplier for the 1.48 specific gravity (12.3 lb/gal) heavy brine used as the base fluid and prepare a user friendly cross linked fluid for the referenced field application. The new fluid system was successfully mixed and pumped in the field enabled the treatment of the well through lower surface treating pressure with conventional 15,000 psi equipment, lower horsepower requirements, and a safer work environment. The paper summarizes the well conditions, extensive fluid qualification testing, procedures, and specially learned lessons during the referenced first field application of the new fracturing fluid system. Introduction 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 Mid Qusaiba formation. These two reservoirs have been penetrated over 25 times in Ghawar and western Rub' Al Khali areas by Saudi Aramco and the International Oil Companies. Reservoir quality is typically moderate to poor (5–15% porosity); natural fractures are thought to significantly enhance deliverability in wells. Recently hydraulic fracturing was included in the testing of these formations which resulted in short term rates of 3–5 mmscfd. Hydraulic fracturing these formations are increasingly challenging due to mechanical limitations on the completion assembly and surface equipment. Maximum surface pressure limitations of 15,000 psi with a maximum bottom hole pressure limitation required the use of 12.3 lb/gal sodium bromide (Nabr) brine. Heavy brines have been successful in the deep Gulf of Mexico frac packing however they have never been applied to a tight gas reservoir. Development of this fluid was targeted to local material resources, fluid stability at 375º F temperature, proppant transport capability, and minimal formation damage. The new fluid was extensively tested to ensure it would perform as required in the field.