Tengiz is a unique, super-giant oil field located in western Kazakhstan that is characterized as a fractured carbonate reservoir with high concentrations of H2S. It is operated by TengizChevroil (TCO). Current production is ~ 530,000 BOPD from 70 active producing wells. As part of an effort to increase the field's production output, a workover and stimulation program was initiated in 2011 after a hiatus of more than five years from such activities. A sizeable part of this workover effort was a matrix acid stimulation program which took lessons learned from earlier acid stimulation campaigns in the Tengiz Field to develop a modified acid stimulation treatment design. The result of this most recent program was a significant and sustained response in well productivity. The key components of the 2011/2012 acidizing program include: 1) increased acid volumes ranging from 50-100 gal/ft and 2) an acid diversion system that included the use of a viscoelastic diversion acid and degradable fibers. Another factor that supported the success of the acid stimulation program was the involvement of a multi-disciplinary team that addressed both candidate selection and acid stimulation design. The TCO 2011/2012 Acid Program has shown incremental improvement in all 19 wells stimulated to date. The average initial incremental gain following stimulation is ~4, 240 BOPD per well and the overall improvement in the Productivity Index (PI) has more than tripled. Post-stimulation production logs have confirmed improvement in the production profiles, indicating the acid diversion methods are having a positive impact.

In 1994 and 1995, a series of hydraulic fracture stimulation treatments were performed in the Mc Kittrick field Point of Rocks formation, a thick >2000') marine sequence of low permeability (0.1 ml)) sandstone intervals separated by shales. The thick interval, 10,000' depth, and a formation temperature of nearly 300 F posed challenges to effectively completing the desired intervals. In general, the initial series of treatments targeted large gross perforation intervals and incorporated a large pad fraction. The treatments included few procedures to enable engineering evaluation of actual in-situ fracture behavior, which was later found to be very different from theoretical or pre-job estimates. Due to some combination of fracture treatment design and reservoir limitations, the production response results from the 1994-995 treatments were mixed, resulting in marginal overall project economics. In 1996, six additional fracture treatments were performed in a new Point of Rocks well, No. 733-17Z. However, a very different fracture design methodology was utilized, focusing on real-data (net pressure) analysis. Objectives for these treatments included a) to place a more effective stimulation than resulting from past efforts, b) to characterize fracture behavior so that reasons for success or failure were clear, and c) to begin the process of optimizing treatment design. A more surgical fracturing strategy was employed, targeting selected Point of Rocks intervals using small perforation intervals and multiple independent fracture stages. Changes were also made to more effectively place fracture conductivity in the intended intervals, including a dramatic reduction in pad fraction and an increase in maximum proppant loading. These changes were implemented with the support of real-time fracture pressure analysis, enabling on-site diagnosis of proppant placement problems, and final treatment design refinement based on observed fracture behavior. Compared with past treatment results, the new hydraulic fracture strategy resulted in a dramatically improved production response. With initial commingled production of over 6 mmscfd and 200 bopd (over 1200 boegd), well 733–17Z had a larger IP and has not experienced the rapid production decline of the previous Point of Rocks wells. With this success, the use of real-data fracture engineering will continue; there remains significant potential for treatment optimization in further planned field development. Introduction This paper presents a case history of the application of real-data (net pressure) fracture analysis, which was used to support the successful implementation of an aggressive fracture strategy in a reservoir with marginal past fracturing success. While this project did not utilize or develop a new or unique fracture design, it provides a solid example of the value of real-data fracture engineering. The thesis of real-data analysis is that real-world hydraulic fracture behavior is extremely complex and affected by many unknown and variable factors. Thus, fracture modeling without utilization of real-data feedback (the norm until recently) may be at best useless, if not counter productive. As an analogy, what is the value of a reservoir performance prediction without the calibration provided by a production history or pressure buildup? The feedback for real-data fracture analysis is in the form of net pressure behavior. Net pressure is the pressure in the main body of the fracture minus closure pressure. Net pressure is the single most important fracturing variable, because it is directly connected to the relationship between fracture length width, and height. P. 643^

With the discovery of new fields becoming less common and the continued development of brownfields, water control is becoming increasingly essential to enhancing oil recovery. Water control operations are especially challenging in under-pressured reservoirs with openhole completions, such as in the Boscan field in West Venezuela. Gravel-packed slotted liners and standalone premium screens are common completion methods in this field. Dual injection, combined with permanent water shutoff (WSO) gels or relative permeability modifiers to control water production in these completions has traditionally produced inconsistent results. This method can fail to change the well production profile and possibly damage oil-producing layers. This paper will discuss the development, implementation, and results of an innovative solution for water shutoff that was engineered for the complex completion methods mentioned. The solution involves three key stages; the temporary isolation of the producing layers, the permanent shutoff of the water zones, and the effective cleanup of the isolated producing layers. The results of ten water control treatments are presented here. The average water cut was reduced to 30% from 88% and oil production was increased by an average of 300 BOPD per well through the application of this water shut-off solution. In one particular well, two previous water control treatments using a conventional water shutoff technique, including a relative permeability modifier (RPM), had left the well producing 100% water. The new solution reduced the water cut to 25%, resulting in a gain in oil production of 300 BOPD. This innovative solution was established as a standard practice for water shutoff in the Boscan field. Introduction The Boscan field lies 40-km southwest of Maracaibo, Venezuela and covers an area of approximately 660 km2, produces a 10.5°API gravity asphaltic oil from the upper Eocene, Boscan (Misoa) Formation with a live oil viscosity ranging from 200–400 cp at reservoir conditions. The reservoir dips to the southwest and ranges from 5000 to 9000 ft in depth. Boscan Field is a combination structural/stratigraphic trap. The reservoir sands were deposited in a tidal-dominated depositional setting. Boscan Field has a complex stratigraphic framework, the interpretation of which is made particularly difficult by the 1 to 0.6 kilometer well spacing. The field currently produces ~ 115,000 BOPD. Figure 1 shows the geographic location of the Boscan field. Since its discovery by the Richmond Exploration Company in 1947, the Boscan field has had over 800 wells drilled with 525 of them currently active. Most of the shut-in wells in the field are located in the south end of the field that in recent years has experienced a surge in water production. Most of the wells in this particular area are experiencing water cut of 90% or higher. Problem Scope The main production challenges in south Boscan wells are;Surface facility limitations in handling produced water; therefore the volume of fluid produced is limited. In addition, production enhancement is restricted.