Pore pressure prediction for exploratory deep Paleozoic well to avoid kicks, blow-outs, borehole instability and to design safe mud weight during drilling phase is a major challenge due to unavailability of deep well informations in South Fuwaris field, Kuwait. The problem was resolved integrating acoustic impedance volume derived from innovative seismic inversion on Pre-stack 3D Q-Land seismic data and geomechanical model with deeper pore pressure trend from drilled well data.
The Q-land data with exceptionally clean, high signal to noise ratio, reliable amplitude, stable phase and wide range of frequency with high trace density facilitated reliable inversion for prediction of reservoir properties from seismic. The high resolution is achieved through global optimization to a single non-linear objective function, which provides the optimum positioning of the layers and 3D multi-trace damping of the random-noise. The low frequency model, a pre-requisite for seismic inversion was built with densely sampled stacking velocity constraining on seismic horizons and wells.
The most popular Bower's method, accounts for Loading (under-compaction) and Unloading (fluid expansion ) was applied to estimate Bower's parameters by cross-plotting velocity against effective vertical stress for drilled well - "A??. The velocity reversal at Sargelu formation was confirmed with kicks in this well which was also cross validated with nearby Humma wells.
The pore pressure and frac gradient were estimated along proposed exploratory well with the trend developed at known shallower well "A?? which was found to be in conformity with regional trends. The lithology predicted along proposed boreholes in order to design mud weight plug and sanctity was reviewed at Top lithological markers using pseudo porosity logs derived with multi-attributes using neural network technique.
This paper presents an integrated approach of pore pressure prediction for drilling deep exploratory well to minimize drilling risks.
Meddaugh, William Scott (Chevron ETC) | Osterloh, W. Terry (Chevron Corp.) | Gupta, Ipsita (Chevron Corp.) | Champenoy, Nicole (Chevron Corporation) | Rowan, Dana E. (Chevron) | Toomey, Niall (Chevron Corp.) | Aziz, Shamsul (Chevron Corp.) | Hoadley, Steve Floyd (Joint Operations) | Brown, Joel (Chevron Corp.) | Al-Yami, Falah
The Paleocene/Eocene First Eocene dolomite reservoir is a candidate for continuous steamflooding due to its large resource base and low estimated primary recovery. There are two steamflood pilot projects in operation to evaluate reservoir response to steam injection: a single pattern pilot (SST) and a 40-acre, 16 pattern pilot (LSP). At the SST an interval with abundant tidal flat cycle caps characterized by muddy, finely crystalline dolomites with low porosity and permeability may be the observed vertical barrier to steam migration. Detailed studies, including micropermeameter measurements and micro-CT scans were used to characterize the heterogeneity. Data suggest that similar vertical barriers may exist at the LSP. Early steamflooding results show a positive response to injection and multiple thermal events (likely baffles rather than barriers). The data also shows the occurrence and distribution of some lateral high permeability pathways between injectors and producers as well as between producers. While the rapid temperature response observed in a few wells may reflect fractures or karst-like zones, simulation using very fine grids shows that some wells will experience very short breakthrough times without fracture or karst-like zones.
Injection of high temperature, high pH fluids may induce fluid/rock interactions that affect reservoir fluid flow near-well and in-depth. This in turn could affect storage capacity, production and injectivity. Reactive transport models (2D-RTM) were run to simulate high pH steam injection into the First Eocene reservoir for a continuous injection period of 6-12 months to understand possible changes in mineralogy, coupled with porosity change and potential scaling. Initial results predict precipitation of calcite and brucite, dissolution of dolomite and anhydrite, and conversion of gypsum to anhydrite. Sensitivity studies examined the impact of steam quality, pH, rock surface area, reaction rates, and mineralogy.
Al-Najim, Abdulaziz (Joint Operations) | Zahedi, Alireza (Wafra Joint Operations) | Al-Khonaini, Talal (Joint Operations) | Al-Sharqawi, Anwar (Wafra Joint Operations) | Tardy, Philippe Michel Jacques (Schlumberger Oilfield Eastern Limited) | Abdur Rahman, Adil (Schlumberger) | Nugraha, Ikhsan (Schlumberger Overseas S.A.) | Ramondenc, Pierre (Schlumberger) | Alhadyani, Fahad Saleh (Schlumberger Well Services)
This paper presents a case study of a matrix acidizing treatment in a well located at the neutral zone between Kuwait and Saudi Arabia, whereby the combination of a "smart fluid?? in a stimulation treatment pumped through a Coiled-Tubing (CT) with the real time distributed temperature sensing (DTS) technology helped improve the real-time decision process of fluid placement, temporary plugging placement, and treatment efficiency evaluation. As part of the analysis process and to facilitate the onsite decision-making process, a temperature inversion technique was also used to translate the actual temperature profiles into fluid invasion profiles across the horizontal open-hole section of the well. Additionally, a full scale acid placement and thermal modeling is proposed in order to perform an in-depth post-treatment evaluation. The bottom hole data evaluation further confirmed the benefits of using a smart fluid. Following the treatment, the well produced at a rate of 1500 bbl/day with 17% water cut, which is well below the field average of ~50%.
Hoadley, Steve Floyd (Chevron Corp) | Al-Yami, Falah (Chevron Corp) | Deemer, Arthur Ruch (Saudi Arabian Chevron) | Brown, Joel (Joint Operations) | Al-Mutairi, Ghanim O. (Chevron Corp) | Lekia, Solomon D.L. (Chevron Corp) | Al-Dhaferi, Fahad (Chevron) | Al-Odhailah, Fares | Barge, David
Hoadley, Steve Floyd (Chevron Corp) | Al-Yami, Falah (Chevron Corp) | Al-Mutairi, Ghanim O. (Chevron Corp) | Lekia, Solomon D.L. (Chevron Corp) | Brown, Joel (Joint Operations) | Deemer, Arthur Ruch (Saudi Arabian Chevron) | Al-Dahfeeri, Fahad (Saudi Arabian Chevron) | Barge, David (NAPESCO KSC) | Kadhe, Chetan Shridhar (NAPESCO KSC) | Nwabuogor, Collins Ejiogu
Meddaugh, William Scott (Chevron) | Osterloh, W. Terry (Chevron Corp) | Toomey, Niall (Chevron) | Bachtel, Steve (Chevron) | Champenoy, Nicole (Chevron) | Rowan, Dana E. (Chevron Global Upstream & Gas) | Gonzalez, Gregorio (Chevron Corp) | Aziz, Shamsul (Chevron Corp) | Hoadley, Steve Floyd (Joint Operations) | Brown, Joel (Saudi Arabian Texaco Inc.) | Al-Dhafeeri, Fahad M. (Saudi Arabian Chevron) | Deemer, Arthur Ruch
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.