Al-salali, Yousef Zaid (Kuwait Oil Company) | Ayyavoo, ManiMaran (Kuwait Oil Company) | Al-ibrahim, Abdullah Reda (Kuwait Oil Company) | Al-Bader, Haifa (Kuwait Oil Company) | Duggirala, Vidya Sagar (Kuwait Oil Company) | Subban, Packirisamy (Kuwait Oil Company)
This paper discusses the outstanding performance achieved in a deep HPHTJurassic formation drilled using Potassium Formate based fluid. This paper alsodescribes methodology adopted for short term testing and stimulation of anexploratory well and finally the field results.
Drilling and completion of deep Jurassic formations in the state of Kuwaitis generally done with Oil Base Mud (OBM) weighted with Barite. Duringdrilling, barite causes significant formation damage to the carbonates withnatural fractures and it is essential to stimulate the well to evaluate thereal reservoir potential. Formation damage is usually treated with matrix acidstimulation, however barite does not respond to acid. Kuwait Oil Company (KOC)was in search for an alternative drilling fluid causing relatively lessformation damage and also responds to remedial actions. Potassium Formate brinewith suitable weighting agent to achieve sufficient mud weight around 16ppg wasselected for field trial in one of the exploratory wells. Formate based brineis a high-density Water Base Mud (WBM) which maintains rheological stability athigh temperature and minimizes formation damage.
Last 2,000 feet in 6" hole section of 18,000 feet well was drilled using15.9 ppg Potassium Formate WBM. During short term testing, acid wash alone wassufficient to remove the formation damage and productivity has tripled which isunlikely in case of wells drilled with OBM.
This case study shows how Potassium Formate based mud enhanced theproductivity and reduced the testing time and cost. Based on the successfulfield test results, it is planned to drill future Jurassic deep formation withPotassium Formate based fluids in future.
The demand for hydrocarbons is expected to grow worldwide. As a result, deeper reservoirs are being explored. Emulsified acid systems are preferred for the stimulation of high-temperature carbonate reservoirs with bottomhole temperatures (BHTs) of 275°F and above. The retarded nature of an emulsified acid system decreases both the acid reaction rate and the rate of corrosion. However, the lack of emulsion stability of these systems is a major problem associated with high-temperature applications (at 300°F and above).
Corrosion inhibitors and intensifiers can interfere with the stability of an emulsified acid system, which consequently leads to higher corrosion losses. At the same time, there is a need for better inhibition systems to counteract the effects of corrosion at higher temperatures. In this paper, a combination of three intensifiers was used, based on the differences in their mechanisms for inhibitor intensification action. The study includes the effect of varying the concentration of each component, hydrochloric (HCl) acid strength (20 to 28%), and temperature (275 to 325°F) on the stability and corrosion rate using P-110/N-80 coupons. The unique combination of the corrosion inhibitor and three intensifiers with proper optimization created a system capable of passing a corrosion test at 300°F using 28% HCl acid. The temperature limit of the system can be extended up to 325°F using an additional intensifier with 25% acid strength.
The present system can be used for acid stimulation of carbonate reservoirs with BHTs up to 325°F. This study revealed a better understanding of the effect of the intensifiers in an emulsified acid system and the synergism amongst them. This enabled the use of an emulsified acid stimulation on carbonate reservoirs having BHTs up to 325°F while reducing the corrosion rate to a level that meets the current market demand for acidizing operations. This work shows that emulsified acid systems can be used with HCl acid strengths ranging from 20 to 28% at high temperatures. The resultant better wormholing at high temperatures should also lead to enhanced oil production.
Influenced by the success of shale gas production worldwide and to meet requirements for clean energy supply, a multidisciplinary team of petroleum specialists was established in Saudi Aramco. Meeting the growing requirement in industrial consumption and especially electricity production is driving force for developing unconventional gas reserves. "The initial focus is in the northwest and in the area of Ghawar, where gas infrastructure exists. Initial knowledge building from similar plays in North America is being supplemented with internal technical studies and research programs to help solve geological and engineering challenges unique to Saudi Arabia and to locate specific wells planned for 2011. The company is innovatively combining knowledge and research to maximize gas reserves and production from conventional and unconventional resources in order to meet growing domestic demand.?? 
During years 2010 - 2011 major international petroleum industry players - Schlumberger, Halliburton and Baker Hughes - were invited to share their experience in a series of workshops held in Dhahran. Exchange of expert ideas developed into appreciation of complexity of the shale gas reservoir and helped to identify the scope of work for the first Silurian Qusaiba shale gas well. The SHALE-1 well was drilled in 2007 as a gas exploration well. Recent drilling and geophysical data obtained in the well were beneficial for detailed sidetrack and fracture stimulation design.
The Multidisciplinary Saudi Aramco - Halliburton SHALE-1 task group was established and positioned in Dhahran. This allowed them to have regular face-to-face meetings and improve the most critical criteria of any new venture - communication. The draft work plan was developed 8 months before actual operations commenced on the well site. Thorough examination of the draft work plan progressed to the final work plan with a number of improvements. For example, "R?? Nipples were dropped from the monobore 4-1/2?? completion string. The Frac Stimulation design was fine-tuned, involving expertise from Saudi Aramco and Halliburton. The Complete Well on Paper exercise involved over 25 specialists from both sides and helped to rectify remaining completion/stimulation design issues, and put everyone on the same page in terms of the work program. Well site operations commenced in May 2011; the well was successfully re-entered and window cut in 7?? liner. An S-shaped 5-7/8?? hole was drilled in the direction of minimum horizontal stresses, to the required depth in Qusaiba Shale with a maximum DLS of 4°. The well was completed with 4-1/2?? cemented liner and monobore 4-1/2?? string to surface. The Hot Qusaiba interval was perforated; frac stimulated with mixed results and successfully flowed. A temporary isolation FasDrill plug was set above the perforation interval. The Warm Qusaiba interval was perforated; successfully frac stimulated and flowed with mixed results. Finally, the FasDrill plug was drilled out with CTU and both intervals flowed and required production log runs.
All targets set for the SHALE-1 re-entry well were successfully achieved and the well was suspended for future utilization as an observation well.
Al Hamad, Abdullah (Halliburton) | Abdul-Razaq, Eman (KOC) | Al Bahrani, Hasan (KOC) | Surjaatmadja, Jim Basuki (Halliburton) | Bouland, Ali (Kuwait Oil Company) | Turkey, Naween (KOC) | Brand, Shannon (Halliburton) | Al-Saqabi, Mishari Bader (Kuwait Oil Company) | Al-Zankawi, Omran (Kuwait Oil Company) | Vishwanath, Chimmalgi (KOC) | Gazi, Naz H. (Kuwait Oil Company)
There are many ways to stimulate an unlined openhole horizontal well using acid. The simplest way is to just pump acid into the well (i.e., bullhead) without placement control. However, this can often be ineffective. Although still used, such approaches can create massive enlargements at the entry point or high injectivity area, thus causing ineffective treatments and re-entry issues. Wellbore collapse often follows. The use of coiled tubing (CT) as a "pin-point?? delivery method is therefore preferred. Using CT allows dispersal of the acid either uniformly or intermittently along the lateral, as desired. CT also allows acid washing to be performed, which is another common process that can improve stimulation without much additional expense to the operator. Using a jetting tool with many jets, acid can be sprayed onto the wellbore wall, and the active agitation caused by the acid-wash process increases the chemical reactivity of the acid at the desired locations.
Another beneficial approach of using CT is the hydrajet assisted acid fracturing (HJAAF) method. With focused jetting of acid at much higher pressures, the process initiates microfractures in the wellbore walls. When etched with acid, this approach effectively bypasses near-wellbore (NWB) damage much deeper than common washes, thus providing much better results. Further modification of the process by exerting high annular pressures offers the capability of delivering medium to large fractures.
This paper discusses two HJAAF processes uniquely combined into one process used in two large horizontal wells. Because of the large dimension of the inner diameter (ID) of the wells combined with the small production tubing the tool must pass through, the implementation had to be further improved by using a unique jetting mechanism, which positioned the jet nozzles closer to the target. Actual results of such stimulations are presented.
Stanitzek, Theo (AkzoNobel) | De Wolf, Corine (AkzoNobel) | Gerdes, Steffan (Fangmann Energy Services) | Lummer, Nils R. (Fangmann Energy Services) | Nasr-El-Din, Hisham A. (Texas A&M University) | Alex, Alan K. (AkzoNobel)
Matrix acidizing of high temperature gas wells is a difficult task, especially if these wells are sour or if they are completed with high chrome content tubulars. These harsh conditions require high loadings of corrosion inhibitors and intensifiers in addition to hydrogen sulfide scavengers and iron control agents. Selection of these chemicals to meet the strict environmental regulations adds to the difficulty in dealing with such wells. Recently, a new environmentally friendly chelating agent, glutamic acid -diacetic acid (GLDA), has been developed and extensively tested for carbonate and sandstone formations. Significant permeability improvements have been shown in previous papers over a wide range of conditions. In this paper we evaluate the results of the first field application of this chelating agent to acidize a sour, high temperature, tight gas well completed with high chrome content tubulars.
Extensive laboratory studies were conducted before the treatment, including: corrosion tests, core flood experiments, compatibility tests with reservoir fluids, and reaction rate measurements using a rotating disk apparatus. The treatment started by pumping a preflush of mutual solvent and water wetting surfactant, followed by the main stage consisting of 20 wt% GLDA with a low concentration of a proper corrosion inhibitor. Following the treatment, the well was put on production, and samples of flow back fluids were collected. The concentrations of various ions were determined using ICP. Various analytical techniques were used to determine the concentration of GLDA and other organic compounds in the flow back samples.
The treatment was applied in the field without encountering any operational problems. A significant increase in gas production that exceeded operator expectations was achieved. Unlike previous treatments where HCl or other chelates were used, the concentrations of iron, chrome, nickel, and molybdenum in the flow back samples were negligible, confirming low corrosion of well tubulars. Improved productivity and longer term performance results confirm the effectiveness of the new chelate as a versatile stimulation fluid.
Jadoon, M. Saeed Khan (Oil and Gas Development Company Limited) | Majeed, Arshad (Oil and Gas Development Company Limited) | Bhatti, Abid Husain (Oil and Gas Development Company Limited) | Akram, Mian M. (Oil and Gas Development Company Limited) | Saqi, Muhammad Ishaq (Pakistan Petroleum Limited)
Balanced drilling through naturally fractured reservoir and controlling loss for preventing reservoir damage and rehabilitation of normal production is a serious challenge in the Kohat-Potwar basin of Pakistan. The potential of hydrocarbons in these reservoir rocks has been masked by the overbalance drilling practices in this region. Due to overbalance drilling in fractured reservoirs and the use of heavy mud with barite blocks the fractures and that results in little or no flow during DST. The negative results of DSTs usually force the decision makers either to abandon the well or to re-test and establish the connectivity between the formation and the well bore.
The well under study was drilled in fractured carbonate reservoir rock to a depth of more than 5000 meters in Kohat-Potwar basin to target Datta and Lockhart formations. During drilling, due to complexities, well could not reach the Datta formation. No wire line and image logs could be obtained in Lockhart formation due to slim hole. The last 5-7/8 inch hole of this well had to be drilled by using Oil Based Mud (OBM) to control well bore instability, the same mud was used in the reservoir sections. During drilling, losses were observed in the reservoir section. On the basis of drilling information, the well was directly completed in the Lockhart formation. After completion, well was allowed to flow but no hydrocarbon surfaced. As Lockhart formation is proven producer, and it became a challenge to evaluate the reservoir for its production potential and to find out the causes of no flow from the formation.
After negative results of well test, all the data of G & G and mud logging was reviewed and detailed analysis of fractures network over the field were carried out to understand the well behavior. The data revealed that mud losses during drilling are i ndicative of fracture's presence in the tested zone(s) and fractures may have been plugged resulting in no flow during test. It was realized that reservoir has potential but connectivity between formation and the well bore need to be enhanced. Even after no flow during initial testing of the well for long period, bold decision of cleaning of the well was under taken and series of Nitrogen kick off jobs were undertaken to facilitate the well to flow. The nitrogen kick off were continued for four months, longest cleaning job ever undertaken in Pakistan and close monitoring of well was put inplace. After four months, WHFP started improving and flow of the hydrocarbons was observed and finally 730 bbl/d of oil and 1.6MMscfdgas were recorded. After the flow of the well, stimulation, with special recipe after lab experiments for OBM, was carried out with very encouraging results. After producing about one year, the well is still cleaning under natural flow.
In this paper, we would try to share our experiences about the use of OBM in fractured carbonate reservoirs, fracture characterization, reservoir damage and its remedial jobs. In addition to this, well performance, well cleaning and stimulation methodology, evaluation of non-flow behavior of well during initial testing and the lessons learned to transform failure to success will be explained.
Typical shale well completions involve massive, multistage fracturing in horizontal wells. Aggressive trajectories (with up to 20°/100 ft doglegs), multistage high-rate fracturing (up to 20 stages, 100 bbl/min), and increasing temperature and pressure of shale reservoirs result in large thermal and bending stresses that are critical in the design of production casing. In addition, when cement voids are present and the production casing is not restrained during fracturing, thermal effects can result in magnified load conditions. The resulting loads can be well in excess of those deemed allowable by regular casing design techniques. These loads are often ignored in standard well design, exposing casing to the risk of failure during multistage fracturing. In this work, the major factors influencing normal and special loads on production casing in shale wells are discussed. A method for optimization of shale well production casing design is then introduced. The constraints on the applicability of different design options are discussed. Load-magnification effects of cement voids are described, and a method for their evaluation is developed. Thermal effects during cooling are shown to create both bending stress magnification and annular pressure reduction caused by fluid contraction in trapped cement voids. This can result in significant loads and new modes of failure that must be considered in design. The performance of connections under these loads is also discussed. Examples are provided to illustrate the key concepts described. Finally, acceptable design options for shale well production casing are discussed. The results presented here are expected to improve the reliability of shale well designs. They provide operators with insight into load effects that must be onsidered in the design of production casing for such wells. By understanding the causes and magnitude of load-augmentation effects, operators can manage their design and practices to ensure well integrity.
Ussenbayeva, Khadisha Yerikovna (Tengizchevroil) | Utebaeva, Dinara (Tengizchevroil) | Molesworth, Gregg R. (Chevron USA Inc.) | Dunger, Darrin (Tengizchevroil) | Akwukwaegbu, Chinedu Franklyn (Chevron Corp.) | Salikhov, Timur M. (Tengizchevroil) | Kamispayev, Akylbek (Tengizchevroil) | Zielinski, Matthew Bernard (Chevron Corporation) | Yakovlev, Timofey (Schlumberger) | Savin, Artemiy | Aglyamov, Mansur
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.
Arukhe, James Ohioma I (Saudi Aramco) | Al Dhufairi, Mubarak (Saudi Aramco) | Ghamdi, Saleh (Saudi Aramco) | Duthie, Laurie (Saudi Aramco) | Elsherif, Tamer Ahmed (Schlumberger Middle East SA.) | Ahmed, Danish (Schlumberger Middle East SA.)
Two new records exist in one of current world's largest oil increment field development projects in Saudi Arabia. The records set while achieving a well's intervention objectives include; 1. Attaining the deepest coiled tubing (CT) reach for rigless well intervention at 29,897 ft (9.11 km) measured depth in an extended reach open hole horizontal power injector well using a CT tractor and; 2. The first application of real time logging enabled through a wired motor head assembly via the tractor. The intervention objectives were to acid stimulate an open hole completed relatively deep in the reservoir with total depth of 29,897 feet and open hole length of 6,697 feet utilizing 2" CT with open hole tractor, to perform injectivity / falloff test, and to conduct real time logging for evaluating the reservoir's injectivity profile.
The paper examines several challenges that engineers and operators encountered during intervention in this well. A partially sealing high viscosity tar layer exists between the overlaying oil column and underlying aquifer. Operationally, the challenge was to overcome obstructions arising from tar accumulation during the well intervention. This challenge was overcome by the use of a solvent and the well was successfully acidized with the aid of the CT-tractor. The other concern was the tractor integrity while large amount of acid is pumped and the extended exposure time of tractor to acid. The tractor successfully handled huge amounts of corrosive fluids in a sour environment while providing the required pulling force to reach the total depth of the well to set the intervention record for tractor reach without adverse effects on the integrity of its O-rings, seals, and mechanical parts. In addition to organic deposits, azimuth changes in the well added to well entry challenges as a result of changes in hole inclination, doglegs, and azimuth. The application of real time informed decisions was critical in overcoming all the challenges, optimizing stimulation design, and yielding a notable and consistent injectivity increase with evidence of extended life and a true reflection of deep penetration into the damage zone. The successful re-entry will benefit industry operators confronting similar intervention challenges.
An extensive study of the field and its predominant drive mechanism revealed that production and simultaneous peripheral matrix water injection is the preferred depletion strategy. Extended reach wells and relatively complicated trajectories typically characterize the powered water injectors drilled for reservoir pressure maintenance. The injectors will support oil production from one of the largest field developments in the history of Saudi Aramco in the M field. The field development consists of 27 artificial islands linked by 41 kilometers of Causeway spanning the Arabian Gulf Sea. The blend of onshore, offshore, causeway and artificial island construction concept was the optimal field development option for the field because it results in only 30% offshore development and 70% onshore development. The chosen concept for the field development requires water injection wells to provide peripheral matrix water injection as pressure maintenance strategy to support oil production. A tar mat zone characterizes the field. About 65% of the powered water injection wells have lengths greater than 17,000 feet, beyond the normal reach of coiled tubing.
Developing unconventional shale gas plays in the Middle East is starting to gain momentum in activity based on the success of unconventional shale gas in North America. A closer look at the statistics reveal that although initial well productivity in North America has increased with the adoption of new drilling and completion technologies, it is still difficult to forecast the success of a single well, as results may be quite inconsistent within the same section or across the play. This paper reviews the factors affecting well productivity and focuses on optimized completions design based on a better understanding of the stress fields in the sub-surface as well as the fracture network. Based on experience from the Barnett Shale, one of the most mature and prolific natural gas fields in North America, the paper will highlight the importance of natural fractures, offset induced fractures, faults, and internal stresses, which are increasingly important to characterize and map as infield drilling increases. A high-resolution logging while drilling (LWD) electrical imaging tool was used to acquire images on a well drilled between two wells drilled between two offset wells 600ft apart within the same section. Fracture systems, faults, and stresses in the field were interpreted and mapped to further develop completions, fracture treatments and well placements. The paper shows how LWD images were used to determine which stages had previously been fractured and to explain how production from offset wells was reduced by as much as 40%. Operators have increased well productivity by up to 20% in more than 300 wells drilled to date. Lessons learned can be applied to most conventional and unconventional plays around the world.
Geology and Well Design in Barnett Shale
The Fort Worth Basin covers approximately 15,000 sq. mi. (38850 km2) and is located in north-central Texas as shown in Fig. 1 (Devon Energy; Hall, Devon Energy). This basin is a shallow, north-south elongated trough and is bounded on the north, northeast, and east by faulted basement uplifts of the Red River Arch, the Muenster Arch, and the Ouachita Structural Front. The southern limit is defined by the Llano Uplift and the basin shallows onto the positive feature of the Bend Arch to the west.In its deepest area adjacent to the Muenster Arch, the Fort Worth Basin contains a maximum of 12,000 ft (3657.6 m) of sedimentary section. In this area, the Barnett Shale can reach a thickness greater than 1,000 ft (304.8 m) (Devon Energy; Hall, Devon Energy). In the core area (Fig. 1) of the Newark East Barnett Shale Field, the Barnett shale is encased by tight carbonates, which act as fracture barriers during the completion process (Devon Energy; Hall, Devon Energy). A typical stratigraphic column of the Fort Worth basin is depicted in Fig. 2.