Harsh wellbore environments reduce the run-life of an Electrical Submersible Pump (ESP), adversely affect casing integrity and require expensive ESP replacements that also subject the well to formation damage due to invasion of the kill-fluid used for well-control. Under such severe operating conditions, an ESP pod system coupled with an isolation packer and a fluid loss valve (FLV) can increase the pump run life, reduce downtime and improve well integrity. Pod system is a specially designed capsule to encase the ESP in an enclosed and sealed environment. The Isolation-packer along with the fluid loss valve (FLV) provides mechanical isolation at the sand-face during ESP replacement operations and protects the formation from the invasion of damage inducing kill fluids. During production, the system safeguards the casing from corrosive well fluids and eliminates damage to the power cable from pressure cycles; fluid enters through the bottom of the pod system and is lifted through the tubing without coming in contact with the casing above the packer. This paper describes a case history on the planning, in-house design, completion and post-installation performance of an ESP pod system implemented as a pilot study for a well in Humma field, Wafra Joint Operations –Partitioned zone. A cost effective and case specific solution was achieved by assembling the various ESP pod components together after researching the various vendors available. The objectives of higher production, improved recovery, and reduced lifting costs were achieved since installation, in the last five and a half years of ESP run-life. The pod system proved to be a customized solution for this well which was previously functioning with diminished pump performance and suffered from frequent failures that led to critical well control issues encountered during pump replacement. ESP is a preferred mode of artificial lift in the Humma field to tackle higher production rates from deep reservoirs. The post installation performance of the ESP pod system has laid the guidelines to achieve uninterrupted and commercially viable production from similar reservoirs that have sub-hydrostatic reservoir pressure and hostile downhole operating environments not conducive for a standard ESP installation and operation.
Al-Ghamdi, Saleh Ali (Joint Operations) | Al-Najim, Abdulaziz (Joint Operations) | Al-Khonaini, Talal (Joint Operations) | Bouyabes, Ahmed Nouman (Kuwait Gulf Oil Company) | Nugraha, Ikhsan (Schlumberger Oilfield Eastern Limited) | Hamid, Saad (Dowell Schlumberger)
Carbonate scaling is one of the common problems that occur in wells producing high amount of water. The tendency of scaling escalates in mature fields. This problem becomes critical in sub-hydrostatic wells with Electrical Submersible Pumps (ESP). In such cases, the scale not only reduces the flow of fluids into the wellbore, but also causes frequent failures in downhole equipment, eventually stopping production leading to well workover. Frequent ESP failures can increase the operating costs to unacceptable levels which may eventually lead to field abandonment.
Joint Operations (Chevron and KGOC) in Partitioned Zone (PZ) faced severe scaling problems in Humma field producing from Marrat Carbonate reservoir. A thick layer of calcium carbonate scale was observed in the completion string during the workover. As a result of this scale, ESP repair and replacement frequencies increased abnormally. Also, the ESP amperage charts showed erratic behavior due to solids interference inside the pump resulting in pump failures.
A combined scale control and stimulation treatment was applied in three wells in Humma field in Joint Operations to slow down scaling tendency in the formation and tubular. These wells are producing up to 1523 BWPD averaging 28% water cut. The treatment provided effective placement of scale inhibitor in the formation while controlling any increase in water production because of stimulation. As a result, the workover frequency due to pump failures was reduced. Not only did the production improve, the amount of deferred oil was also significantly reduced resulting in direct oil gain and significant savings in operating costs.
This paper describes the lab analyses, treatment design and execution procedure, adopted for the implementation of this technique as well as the recommendations and lessons learned from the field experience.
Brief Review of Scale Problem
Numerous studies have been done to understand the scale in oilfield. Subjects are very wide covering scale behavior, deposition, identification all the way down to treatment and inhibition chemicals. In the subject of material selection Wang, Z (2005) reported that the surface can be engineered in order to decrease the scale formation and adhesion. Minimizing the surface roughness and number of hooking sites can decrease the extent of scale deposition.
From the treatment point of view various technique has been employed to introduce scale inhibitor into the well even beyond matrix rate, in the effort to maximize the amount of inhibitor can be placed in the well, hence extend the scale protection. In 2001, Norris, et al, published a report that the uses of scale inhibitor impregnated proppant in the fracturing treatments were able to get acceptable scale inhibitor residual.
In order to achieve successful scale control, it is required to take a holistic approach and looking at the scale within the frame of total production system from reservoir to completion and all the way to surface. For that, the first question should be to predict whether a reservoir with the existing production system will have scaling tendency sometimes during its production life. Brown, M (1998) reported a loss of production in one of North Sea well from 30,000 BOPD to zero in just 24 hours. This shows that the predicting scale tendency and its magnitude are not an easy task.
Al-Aslawi, Raed (Joint Operations) | Al-Sharqawi, Anwar (Wafra Joint Operations) | Al-Haimer, Mohammad (ChevronTexaco International) | Zahedi, Alireza (Chevron Corp) | Al-Khonaini, Talal (Joint Operations) | Al-Najim, Abdulaziz (Joint Operations)
The South Fuwaris and Humma Fields are located in the Partitioned Zone between Kuwait and Saudi Arabia. The South Fuwaris Field commenced production in 1963, with the majority of its production from the Lower Cretaceous Ratawi Limestone/Oolite reservoir. The Humma Field was discovered in 1998, and has the only PZ production from the early Jurassic Marrat Formation. 95% of the wells in South Fuwaris and Humma produce via electrical submersible pumps (ESP).
The remote location of both fields requires all ESP systems to be powered by individual diesel generator sets located close to the well heads. Based on the requirements of the preventive maintenance program for these generators, each generator set is scheduled for lube oil/filter change every two weeks, at which time production is shut-in. The shut-ins result in a considerable volume of deferred oil.
A recent Root Cause Analysis study of the historical failures of the downhole production assemblies of ESP-equipped South Fuwaris and Humma producers revealed that a significant number of failures could be directly or indirectly attributed to the produced solids settling back into the ESP after shutdown. When the well is shut down, the fluid column above the ESP drains back into the wellbore through the pump, causing produced solids to be deposited in the ESP. This causes high current draw during start up and eventually leads to motor or cable failure, in many cases resulting in complete seizure of the ESP shaft.
To avoid the production loss and ESP failures that result from well shut in, the asset management teams in South Fuwaris and Humma have developed a method for keeping wells on line while generator sets undergo lube oil/filter change.
The purpose of this paper is to demonstrate how the downhole ESP is kept running while its power generator undergoes scheduled preventive maintenance work. The paper also demonstrates the in-field applicability of the generator set synchronization technique to the oilfield operations, and how this technique has maximized ESP run time in Humma and South Fuwaris Fields, saving Wafra Joint operations greater than $10 MM annually. As more new wells are being drilled and produced, the annual dollar savings increase even further, through the use of a simple and cost-effective process.
A limitation of Electrical Submersible Pumps (ESPs) is the inability to handle significant volumes of gas. The implications of this limitation become even more critical if the fluid production rate is at or below the minimum rate required for coolingof downhole equipment. The oldest and most widely practiced method for forced convection cooling of the motor of an ESP system is to use a motor shroud. However, numerous field case studies have shown that even with the motor shroud in place, motor failure has been the primary cause of ESP failure in low-volume high-GOR wells.
The optimal mitigation solution for low-volume high GOR cased-hole producers is to lower the ESP string below the perforations, with a shroud installed for cooling of the motor. For low-volume high-GOR ESP-equipped producers that are producing from an open-hole interval installation of the same conventional shrouding system would take care of the cooling of the motor but it will not function as a free gas eliminating or reducing device. The production strings of the ESPs producing from an open-hole interval usually include an inverted shroud intended to reduce the amount of free gas entering the pump. Such installations would not function as a motor cooling device.
The large degree of production loss and the increased operating cost incurred by unplanned ESP shut-down and failure have been two of the major challenges faced by the asset teams of South Fuwaris (SF) and Humma (HUM) Fields in PNZKuwait, in their efforts to maximize the uptime of low-volume high-GOR ESP-equipped open-hole producers. A customized shrouding system was needed to simultaneously resolve the issues of motor cooling and the reduction of the
amount of free gas entering the pump. The dual functioning nature of a shrouding system composed of a conventional shroud combined with an inverted shroud was the main feature that had to be incorporated in the design of such system.
Through the continuous efforts of the South Fuwaris and Humma asset teams, a novel dual-shrouding system has recently been developed to fulfill the requirements of cooling of the motor and reduction of free gas entering the pump simultaneously. Multiple customized versions of this system have been installed in critical low-volume high-GOR openhole producers since the 4th quarter of 2009.
Examination of historical operating conditions of ESP strings equipped with the new shrouding system showed a significant reduction in the number of ESP shut-downs due to underload, overload or high motor temperature trips, and a dramatic drop in the number of ESP failures caused by overheating of the motor.
This paper discusses the benefits of the newly-designed shrouding system and its built-in perforated tail pipe, specifically designed for low-volume high-GOR producers in South Fuwaris and Humma Fields, and actual results achieved from field implementation of this system.
The Jurassic-age Humma Marrat carbonate reservoir was discovered in 1998. Eleven wells have been drilled to date including several horizontal completions. The gross reservoir interval is about 235 m (730 feet) thick. The reservoir produces from three intervals - Marrat A, Marrat C, and Marrat E. The partially dolomitized lowermost Marrat E interval contributes 75-85% of the total production from zones averaging 20-25% porosity and 10-100 mD permeability. Productive intervals in the Marrat A and C zones average 15-20% porosity and 0.5-2 mD permeability. The current estimated original oil in place is about 500 million bbls.
A volumetric uncertainty look-back (1998-2007) has allowed a historical assessment to be made for porosity and water saturation (Sw) uncertainty. This look-back based assessment of porosity and Sw uncertainty allows the impact of increasing quantity of data, changing analytical workflows, and updating interpretations to be examined. Based on the standard deviation or range of the available data at various times in the look-back period, the estimated porosity uncertainty was about ±2-2.5 porosity units (pu) after the first three wells were completed. After two additional wells and integration of core data, the estimated porosity uncertainty was reduced to about ±1.5-2 pu. Data from all eleven wells available at the end of the look-back period showed that the porosity uncertainty reduced slightly to about ±1-1.5 pu. However, a significantly lower estimate for the uncertainty is derived from the variation of the average porosity of the individual well averages after the first three wells were drilled. Using this parameter as a measure of uncertainty provides an uncertainty of ±0.5-1 pu early in field history (after three wells) and ±0.25-0.5 pu at the end of the look-back. Likewise, the uncertainty estimate for Sw decreased from ±15-20 saturation units (su) in 2000 to ±10 su in 2007 based on the standard deviation and range of the data available at each analysis date in the look-back period. Using the change in average Sw of the individual well averages, the uncertainty was ±5-10 su early in field history (after three wells) and ±2-4 su at the end of the look-back' significantly less than that derived from standard deviation or data range. A proposal is made to use the variation of the average of the individual well averages to define uncertainty in cases for which enough data (generally more than 3 wells) is available and there are no changes expected to analytical workflows (e.g. recalculating log derived porosity once core data is available). If changes to analytical workflows are anticipated a more conservative (e.g. larger) estimate for uncertainty should be used, perhaps based on the standard deviation or range of the available data.
An original oil in place (OOIP) uncertainty look-back based on a consistent design of experiments-based approach (Meddaugh et al (2006a) is also presented along with a brief discussion of using a normalized uncertainty index (UI = (P90 OOIP -P50 OOIP ) / P50 OOIP) to track delineation efficiency.
Microseismic monitoring of hydraulic fracture stimulation treatments has done much to diminish the expectation of engineers and geoscientists that symmetrical bi-wing fractures extending away from the well bore from as a result of the treatment. Mapping of microseismic event locations indicates that more often, zones of high complexity form which suggest multiple rock failure mechanisms could be in play during the stimulation treatment. The complexity of the failure is further complicated, or perhaps explained, by the interaction of the perturbed stresses with existing fractures in the reservoir relative to the unperturbed stress state of the reservoir. Existing fracture planes favorably oriented for shear will fail at lower stresses than are required to create new fractures. Geologic mapping and regional to local in-situ stress information will allow informed interpretation of the resulting microseismicity patterns as well as providing predictive capability for fracturing patterns of treatments in subsequent area wells and production planning. Correlative to the improved fracture mapping is the use of the fracture interpretation as input to fractured reservoir modeling and fractured reservoir simulation. Utilizing microseismicity data not only to constrain location of fractures, but also fracture size, shape and orientation allows creation of improved fractured reservoir models based on geologic concepts and supported by the real time data.
In this paper two examples are presented from a hydraulic stimulation of North American mid-continent wells that were monitored with a surface-based geophone array. The resulting microseismicity patterns in both wells show that the fracture development was strongly influenced by pre-existing discontinuities (fractures or faults), which are easily explained by geologic and in-situ stress analysis. The fracture interpretation and microseismicity data from one example is used to generate a discrete fracture network from which fracture flow properties are created in a geocellular model. The resulting model provides a quantitative framework for production history mapping and reservoir behavior, with hard constraints for the behavior of the dominant fractures in the fracture network.
Horizontal drainholes in thick, high-permeability reservoirs have been used effectively to produce many reservoirs in the Middle East. Many of these bottom-water-drive reservoirs have natural fractures intersecting the wellbore that connect through the oil-water contact. Therefore, they are susceptible to water encroachment through natural fractures when high drawdowns are applied. The resulting water production leads to a number of well maintenance problems and reduces the efficiency of the completion.
Hydraulically fracturing these horizontal drainholes can offer a number of benefits including reduced water influx. The placement of several small and/or a few large hydraulic fractures at pre-designed intervals in the horizontal wellbore would significantly improve the deliverability of the reservoir and thus reduce the drawdown necessary to achieve optimum production. It is of course necessary to keep the fractures from penetrating into the water-bearing formation. Since most of these wellbores are uncased, openhole completions, a special fracturing technique has been used that allows precise placement of these fractures without the need for mechanical isolation of intervals during the fracturing operation.
Production modeling of a horizontal completion in reservoirs with bottomwater encroachment through natural fractures will be compared to a hydraulically fractured completion with the same conditions. Modeling will also illustrate the potential of using hydraulic fracturing as a remediation technique for water production problems. It will also illustrate its effect on completions with current water production. The openhole fracturing technique will be illustrated with a case history from the Hanifa formation in Saudi Arabia.
The Jurassic-age Humma Marrat carbonate reservoir is mainly located in the southwest corner of the Partitioned Neutral Zone (PNZ) between Saudi Arabia and Kuwait. The reservoir was discovered in 1998. The reservoir depth is about 9000 ft subsea. The gross reservoir interval is approximately 730 ft thick (110 ft net). The lowermost Marrat E zone contributes 80-90% of the production based on PLT data. The productivity of the Marrat E is dominated by a forty-foot thick, largely dolomitized interval with 15-20% porosity and 20-100 mD permeability. The upper zones contribute 10-20% of the production from thin intervals with 12-15% porosity and 2-5 mD permeability.
A two stage design of experiments (DoE) based workflow was used to evaluate and optimize primary reservoir development. Reservoir uncertainties affecting volume and connectivity were assessed in the first stage of the workflow. The second stage of the workflow focused on dynamic uncertainties. The results of the workflow defined the P10, P50, and P90 models used for development optimization. Economic analysis showed that 640-acre primary development using vertical wells was the most attractive option. Pressure data obtained during field delineation in 2005 and 2006 showed the reservoir to be approaching bubble point pressure in the Marrat E zone main compartment. On-going dynamic modeling showed that only a limited number of additional wells were needed and the primary development project scope decreased considerably.
Data acquired during delineation drilling in 2005 and 2006 continued to reduce reservoir uncertainties. Additional dynamic simulation was done in 2006 to refine development options. Rather than redo the entire DoE-based workflow, a series of dynamic models were generated in 2006 that incorporated the new well data and preserved the capability of giving probabilistic results. The modified DoE approach was shown to be an efficient tool for final assessment of primary development options and reserves.
The Ratawi Oolite carbonate reservoir in the Partitioned Neutral Zone (PNZ) is located between Kuwait and Saudi Arabia and has been a prolific oil producer in the area. Several billion barrels of oil from this reservoir has been produced within the PNZ. As the fields mature, the easy produced oil in the high permeability intervals is diminished by increasing water cut. Considerable by-passed oil remains in the tighter and lower quality intervals. These oil reserves cannot be produced efficiently and economically by vertical wells through primary or secondary methods. Without different techniques of drilling and completion, most of the oil in the low permeability intervals will be left unrecovered.
A combination of horizontal drilling with geosteering tools and technology for precise lateral placement in the low permeability reservoirs in addition to a low fluid loss drilling fluid system have resulted in significant incremental oil recovery that would not be produced by existing or additional vertical wells. The success has led to new opportunity for horizontal drilling and horizontal sidetracking targeting low permeability reservoirs in mature fields.
The South Umm Gudair (SUG) and South Fuwaris (SF) fields are located in the PNZ between Kuwait and Saudi Arabia. The fields were discovered in 1966 and 1957 respectively and put on production in the 1960s. Locations of the fields are shown in Fig. 1.
The SUG field has been producing from the Lower Cretaceous age Ratawi Oolite carbonate reservoir. Current production is still under primary recovery assisted by bottomwater drive and an edgewater drive from the eastern side of the reservoir. A structure map of SUG is shown in Fig. 2. From initial field development to 2003, field production was predominantly from several high permeable layers, M4 to M12, of the Ratawi Oolite carbonate reservoir commingled in both vertical and horizontal wells. Permeability from these layers range from 300 to 1,000 md. Beginning in 2004, new horizontal and horizontal sidetrack vertical wells targeted the low permeability, 50 to 150 md, M3b layer. The new horizontal and horizontal sidetrack wells average 3,031 BOPD and 5% water cut compared to production of a single completion vertical well in the M3b reservoir, which averages only 500 BOPD and 50% water cut. The SUG field currently produces 65,000 BOPD and 10 MMcf/D with 58% water cut from 65 active wells, out of which 25 wells are horizontal and horizontal sidetrack (HST) wells. All wells are on artificial lift with electrical submersible pump (ESP) systems.
SF field development has historically focused on the relatively more permeable, 20 to 80 md, thin-layered Ratawi Limestone interval with minimal consideration given to the low productive, low permeable, 0.1 to 5 md, Ratawi Oolite section.
The Ratawi Oolite in SF is characterized as a thick, porous interval with good hydrocarbon saturation, a clearly defined oil-water-contact, with abnormally low permeability. Low production rates from past vertical and slant-hole completions led to disregarding the development potential of this reservoir. A field structure map of SF is shown in Fig. 3.
In 2004, the first horizontal sidetrack well was successfully completed in the low permeability Ratawi Oolite reservoir in the SF field. Well test data showed production stabilized at 914 BOPD and 1% water cut compared to a stabilized production of a vertical well at 100 BOPD and 1% water cut. A follow-up horizontal sidetrack was completed in 2005 with similar results. These two wells currently produce 1300 BOPD and less than 1% water cut. As a result, additional development will be implemented in 2006 to further define Ratawi Oolite potential in the field. The SF field currently produces 3900 BOPD with 50% water cut from 8 wells.
The target reservoirs are several limestone layers separated by shales and extend over a vertical height of up to 100 m. The reservoirs are developed differently in almost every well, and natural fractures exist in some, but not in all, wells. The wells are completed with regular 13 3/8-in. casing to around 900 m, 9 5/8-in. casing to around 3400 m, and a 7-in. liner through the reservoir section at around 4100 m. Surface temperatures range from +20°C in summer to -50°C and lower in winter, with bottomhole temperatures (BHTs) around 50°C.
Both for producers as well as injectors, a properly designed matrix acid treatment covering the entire reservoir proved to be the most successful production enhancement technique. Most of the wells were completed in a way that allowed the matrix acid stimulation treatments to be conducted in two stages. Both stages covered more than one perforation set. However, for the second stage the job team had to consider that the first stage covering the lower zones was already completed, and fluid would most likely be pumped into this lower zone. The challenge was to provide good diversion over the entire reservoir for one stage and, even more difficult, to divert the majority of the acid into the upper zone for the second stage. In addition, this reservoir oil has relatively high paraffin content, and paraffin deposition, hindering if not eliminating production, will occur below a certain temperature. This fact had to be considered in the matrix acid stimulation design.
For a single-stage treatment, or the treatment of the lower zones, a combination of Insitu Crosslinked Acid (ICA) and maximum pressure/maximum rate technique (MPMR) proved to give excellent diversion over these intervals. ICA is a chemical diversion technique. It features a thin, gelled acid with a viscosity of approximately 25 cP that forms a highly viscous crosslinked gel when the acid spends on the formation to a pH of approximately 2. The crosslinked gel can effectively stop any further fluid invasion, and following acid stages will be diverted to different parts of the zone. As the spending continues further, the crosslink will break again at a pH of approximately 4. The MPMR technique uses the concept of dynamic diversion, whereby the pressure remains constant just below frac pressure, and the rate is increased as the acid spends on the formation. Bottomhole (BH) gauge data are available to show the effect of diversion and eliminate any possible effects from friction and hydrostatic pressures that can affect surface data.
For the treatment of the upper zone, when the lower zone was already stimulated and could not be isolated by mechanical means, additional diversion was required to seal off the perforations of the lower zone. A combination of Biodegradable PerfPac Balls and ICA was pumped at the beginning of the treatment to divert the remaining matrix acid treatment away from the lower zone and optimize stimulation of the upper zone.
This paper shows how a properly engineered matrix acid treatment using a combination of diversion techniques can result in optimized stimulation treatments. In a carbonate formation, efficient diversion of acid fluids is even more important than in a sandstone reservoir because the acid-carbonate dissolution reaction rate is so fast.