Summary Several oil wells in a Saudi Arabian field have shown a significant decline in oil productivity in recent years. A few have "died" prematurely, while others have become intermittent producers. The oil productivity decline is aggravated by water encroachment and has occurred with relatively low water rates and without any significant drop in reservoir pressure. These wells have low productivity indices (PIs), resulting in relatively low flowing bottomhole pressures (FBHPs). This paper presents the results of an investigative case study to determine the causes of productivity decline in these wells. A multidisciplinary team was set up with engineers and scientists from reservoir management, production engineering, and the R&D Center for the investigative study. The team focused on multiple aspects, including reservoir and production engineering as well as a comprehensive laboratory and field investigation. The results of this study indicate that one of the main causes of productivity decline in these wells is related to asphaltene precipitation and the subsequent formation of tight emulsions downhole. The emulsions block the pore throats and cause formation damage, which leads to productivity decline. Another factor that further aggravates the productivity of these wells is poor rock quality in the area. Possible causes of formation damage by inorganic scaling and leakage and mixing of gas from a deeper reservoir have been eliminated. Well-test analyses on some of the affected wells show that the formation-damage mechanism in the affected area is further aggravated by poor reservoir rock quality. The time-lapse pressure-transient analysis also indicates a deterioration of skin and productivity with time. On the basis of these findings, a special solvent treatment was recommended and designed as a pilot trial for one of the dead wells. The treatment included squeezing xylene and demulsifier to dissolve the asphaltenes and break the tight emulsions around the wellbore area. The treatment resulted in only a slight improvement in the PI, and the well died after a few days. Currently, a stimulation treatment with acid and demulsifier is being implemented in selected wells. The results of the field trials are described here. Introduction Several wells in the northwestern part of a Saudi Arabian field have shown a decline in productivity in recent years. A few wells have died prematurely at relatively low water cuts, some as low as 25%, which is atypical for wells in this area. It has been noticed that the oil productivity decline is aggravated when wells become wet. The decline has occurred with water rates remaining mostly stable and without any significant drop in reservoir pressure. A location map of affected wells is shown in Fig. 1. Oil and water production rates are plotted in Figs. 2 through 4 for three affected wells. The oil production rates declined from ~ 10,000 to 12,000 B/D to less than 1,000 B/D during a period of approximately 4 to 5 years. Water rates remain generally low, less than 2,000 B/D. It can also be observed that the oil rate decline is substantial as soon as water breaks through in the well. This study was initiated with the objectives of finding the causes of productivity decline in these wells and of finding effective ways to mitigate the problem. A multidisciplinary team was set up with members from reservoir and production engineering and the R&D Center. Several potential causes of productivity decline in these wells were investigated, including the precipitation of asphaltenes, emulsion blocking, mixing of hydrocarbons from a deeper reservoir, inorganic scale precipitation, aquifer-brine and injected-water compatibility, and regional geology, including rock quality, drilling fluid damage, and distance of wells from the gas/ oil separation plant (GOSP). This paper presents extensive experimental work, reservoir-engineering and pressure-transient analysis studies, and results of a field trial. Experimental Investigation Asphaltene Precipitation. Asphaltenes comprise the heaviest polar fraction of crude oils. Asphaltenes exist in the form of colloidal dispersions and are stabilized in solution by resins and aromatics that act as peptizing agents. Asphaltene precipitation and deposition may occur deep inside the reservoir, near the wellbore, and/or in processing facilities.1–4 It was evident from preliminary analyses of wellhead samples that some form of asphaltene precipitation was taking place in the affected wells. All these wells showed tight emulsions, and asphaltenes were observed in the bailer samples. Asphaltene precipitation is a function of pressure, temperature, live crude oil composition, and, to a lesser extent, oil/water interactions. Asphaltenes have a tendency to precipitate as the pressure is reduced, especially near the bubblepoint. However, precipitation can occur even at pressures higher than the bubblepoint, depending on the crude. Normally, this reduction in pressure occurs in the wellbore, where it might not be such a problem because the precipitated asphaltenes may be dragged to the GOSP and redissolve as the pressure reduces further.1,3 However, if the pressure reduction occurs inside the reservoir, for example near the wellbore, it may result in asphaltene precipitation within the effective pore space. This may lead to an increase in skin and, subsequently, more precipitation. Ultimately, this may result in the reduction of oil rates and lead to the death of the well. Asphaltenes are also known to stabilize emulsions.5–8 Tight emulsions can lead to emulsion blocking, a phenomenon that also reduces productivity in oil wells.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractMatrix acidizing of horizontal and multi-lateral wells is a challenging task for several reasons. First, oil reservoirs are heterogonous in nature and the presence of high permeability streaks is common. Proper diversion technique is always required to better distribute the injected acid across the target zone. Secondly, stimulation of horizontal wells requires injection of large volumes of acids. This will require using an effective corrosion inhibitor package that can protect down hole tubulars and coiled tubing, especially in sour environments. Thirdly, recovering large volumes of spent acid is a concern, especially in tight formations. Acid treatments should be designed to address these issues in a cost effective way.Currently, there are a limited number of chemicals that can divert the acid into the formation. This paper introduces a new viscoelastic surfactant which was used to form stable foam during matrix stimulation of a seawater injector. The length of the target zone was 1,500 ft, and the average permeability of the carbonate was 700 mD. A 1.75-inch coiled tubing was used to better distribute the acid in the open hole section (6.125-inch in diameter).As with previous viscoelastic surfactant systems, the surfactant molecules form structures in solution in the presence of salts. These structures enhance the viscosity of solution significantly and can be broken by dilution with injection water or by adding mutual solvent (3-5 vol%) to the preflush/postflush stages.Unlike previous viscoelastic surfactant-based systems, the new surfactant builds viscosity faster and its gel breaks down in a shorter period of time.This paper examines the results of extensive lab testing that led to the development of this improved self diverting system. It will also give details of the first field application of this system. Following the acid treatment, the well injection rate improved by five folds, from 16,000 to 80,000 BPD. Benefits and improvements introduced by the new diversion technique will be discussed in detail.

A few oil wells in a Saudi Arabian field have shown significant oil productivity decline in recent years. A few of them have ‘died’ prematurely while others have become intermittent producers. It has been noticed that the oil productivity decline is aggravated with water encroachment. The oil productivity decline has come about with relatively low water rates and without any significant drop in reservoir pressure. These wells have low productivity index (PI) resulting in relatively low flowing bottom hole pressures (FBHP). This paper presents the results of an investigative case study to determine the causes of productivity decline in these wells. A multi-disciplinary team was set up with engineers and scientists from reservoir management, production engineering and the R&D Center for the investigative study. The team focused on multiple aspects including reservoir and production engineering, as well as a comprehensive laboratory and field investigation. The results of this study indicate that one of the main causes of productivity decline in these wells is related to asphaltene precipitation and the subsequent formation of tight emulsions downhole. The emulsions block the pore throats and cause formation damage leading to productivity decline. Another factor that further aggravates the productivity of these wells is poor rock quality in the area. Possible causes of formation damage due to inorganic scaling, and leakage and mixing of gas from a deeper reservoir have been eliminated. Well test analyses on some of the affected wells shows the formation damage mechanism in the affected area is further aggravated by poor reservoir rock quality. The time-lapse pressure transient analysis also indicates a deterioration of skin and productivity with time. Based on these findings a special solvent treatment was recommended and designed as a pilot trial for one of the dead wells. The treatment included squeezing xylene and demulsifier to dissolve the asphaltenes and break the tight emulsions around the wellbore area. The treatment resulted in only a slight improvement in the productivity index and the well died after a few days. Currently a stimulation treatment with acid and demulsifier is being implemented in selected wells. The results of the field trials will be described in the paper. Introduction Several wells in the northwestern part of a Saudi Arabian field have shown productivity decline in recent years. A few of them have died prematurely at relatively low watercuts, some as low as 25%, which is atypical behavior for wells in the area. It has been noticed that the oil productivity decline is aggravated when wells become wet. The oil productivity decline has come about with water rates remaining mostly stable and without any significant drop in reservoir pressure. A location map of affected wells is shown in Figure 1. Oil and water production rates are plotted in Figures 2–4 for three affected wells. The oil production rates declined from ~10–12,000 BPD to less than 1,000 BPD over a period of approximately 4–5 years. Water rates remain generally low at less than 2000 MBD. It can also be observed that the oil rate decline is substantial as soon as water breaks through in the well. This study was initiated with the objective of finding the causes of productivity decline in these wells and finding effective ways to mitigate the problem. A multi-disciplinary team was set up with members from reservoir and production engineering and the R&D Center. Several potential causes of productivity decline in these wells were investigated including the precipitation of asphaltenes, emulsion blocking, mixing of hydrocarbons from a deeper reservoir, inorganic scale precipitation, aquifer brine and injected water compatibility, regional geology including rock quality, drilling fluid damage, and distance of wells from the Gas Oil Separation Plant (GOSP).

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractSeveral acid treatments were conducted in the Ghawar filed to increase the well injectivity and to support the reservoir pressure in this area. Vertical and horizontal wells with an open hole completion in a carbonate reservoir were selected to be a candidate for post acid treatments evaluation study.These wells were stimulated using hydrochloric and emulsified acid with foamed viscoelastic-based water. Viscoelastic-based water system was used to enhance the diversion mechanism and the lifting process for the spent acid following the treatment. In this paper new correlations for acid treatment design were obtained from an extensive study of several case histories that can be used for optimizing future acid treatments design in the Ghawar field. This study was mainly utilized the results from the post acid treatment jobs in terms of HCl acid, emulsified acid and viscoelastic volume correlated with the well's injectivity. Based on the study results, there is a strong relationship between the emulsified acid volumes with the injectivity index for the selected wells.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractSeveral acid treatments were conducted in the Ghawar filed to increase the well injectivity and to support the reservoir pressure in this area. Vertical and horizontal wells with an open hole completion in a carbonate reservoir were selected to be a candidate for post acid treatments evaluation study.These wells were stimulated using hydrochloric and emulsified acid with foamed viscoelastic-based water. Viscoelastic-based water system was used to enhance the diversion mechanism and the lifting process for the spent acid following the treatment. In this paper new correlations for acid treatment design were obtained from an extensive study of several case histories that can be used for optimizing future acid treatments design in the Ghawar field. This study was mainly utilized the results from the post acid treatment jobs in terms of HCl acid, emulsified acid and viscoelastic volume correlated with the well's injectivity. Based on the study results, there is a strong relationship between the emulsified acid volumes with the injectivity index for the selected wells.